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Transcript of Basic Logging Manual
1
Surface Logging
Manual v4.0
Written By Tom Arnold, Director of Training
2
Table of Contents PAGE Forward 8
Introduction to Surface Logging 10
History 10
Responsibilities 15
Employee Professionalism 18
Drilling Rig 22
Who’s Who 22
Drill Rig 23
Drilling Fluid 27
Basic Geology 29
Introduction 30
Rock Types 31
Model Process 34
Basic Structure 36
Tectonics 37
Faulting 38
Folding 39
Structural Basins 40
Unconformities 40
Fundamental Formation Characteristics 43
Formation Water 43
Porosity 44
3
Table of Contents Cont. PAGE Permeability 44
Factors Affecting Porosity &Permeability 45
Texture 45
Grain Shape 45
Grain Size 46
Grain Sorting 46
Grain Packing 46
Porosity Loss 47
Common Depositional Environments 48
Sandstone 48
Limestone 53
Evaporites 54
Common Sedimentary Rocks 55
Lag Determination 65
Concept and Calculation 65
Calculating Annular Volume 66
Calculating Pump Output 67
Calculating LAG 68
Lithology Description & Hydrocarbon Analysis 69
Sample Preparation 69
Sample Quality 69
Mud Viscosity 69
Sample Collection 69
Washing Samples 72
Preparing Samples 74
Sample Description 76
Abbreviations 77
Color 78
Texture 78
Cement/Matrix 80 Fossils & Accessories 81
Mineral Identification 82
4
Table of Contents Cont. PAGE Tests for Carbonates 82
Alazarin Red Test Chart 84
Tests for Specific Minerals 84
Hydrocarbon Analysis 86 Odor 86
Stain & Bleed 86
Reaction in Acid 87
Florescence 87 Reagent Cut Test 87
Solid Hydrocarbon & Dead Oil 92
Generalization 92
Interpretation Issues 93
Caving 93
Re-Circulation 93
Lost Circulation Material 93
Cement 94
Drilling Fluid 94
Oil Base 94
Oil Contamination & Pipe Dope 94
Pipe Scale & Bit Shavings 94
Rock Dust 94
Powdering 94
Indurated Shale 94
Fusing 94
Air-Gas Drilling Samples 94
Lag Error 94
Spread 96
Dog-Housing Samples 96
Sample Description Abbreviations 96
Color of Wet Samples 96
Chromatography 99
Understanding Gases in the Circulating System 102
Well Bore Model 103
Recycled Gas 105
5
Table of Contents Cont. PAGE
Liberated Gas 106
Produced Gas 107 Contamination Gas 109
WellSight 113
Appendix 135
A. Identification of Igneous Rocks 135 B. Identification of Sedimentary Rocks 137 C. Identification of Metamorphic Rocks 139 D. PALADIN Formation Targets 140 E. Stratigraphic Column of N. Louisiana 141 F. Bossier 142 G. Barnett Shale Cross Section 143 H. Barnett Shale Stratigraphy 144 I. Barnett Events Timetable 145 J. Anadarko Basin 146 K. Viola Outcrop 147 L. Marcelleus 148 M. Fayetteville 151 N. Haynesville 153 O. Gas Flow System & Troubleshooting 154 P. Rig Up & Rig Down/Electrical Maint. 159 Q. PALADIN Communication 161 R. Gas Extractor & Troubleshooting 164 S. Hydrocarbon Fluorescence 170
T. Format for Labeling Dry Sample Boxes 171
U. Wet Sample Preparation 176
V. Correlation 179 Wellbore Environment 179
Understanding the Gamma Ray 180
Typical Gamma Responses 181
6
Table of Contents Cont. PAGE
Correlation Basics 183
Correlation Procedures 183
W. IBall Operation 185 Exterior Part Labels 186
Setup 186
Maintenance 187
Display Screen Description and Definition 188
Alarms 190
Attenuation Adjustments 191
Gas Flow 191
Internal Components 192
Chromatography 194
Real-Time Data Viewer 197
X. Hydraulics 199
Introduction 199
Internal Pressure Losses 200
Annular Pressure Losses 202
Reynolds Number 204
Friction Loss 204
Power Law 205
ECD 206
Hydraulic Horse Power 207
Slip Velocity 208
Fracture Gradients 209
Abnormal Pressure Detection 215
Normalized Rate of Penetration 217
Chloride Ion Calculation 217
Pressure Swabs & Surges 218
Z. Pore Pressure Theory 222
Definitions 222
7
Table of Contents Cont. PAGE
Hydrostatic Pressure 223
Equivalent Mud Weight 225
Pressure Gradient 226
Overburden Stress 227
Normal Compaction Tend 229
Causes of Abnormal Pressure 230 Rapid Deposition of Shale 231
Artesian Aquifer 234
Differential Density 235
Erosion & Uplift 235
Intrusion & Psuedoplastic Formations 236
Hydrocarbon Generation 236
Impermeable Bed 238
Fluid Migration 238
Carbonate Compaction 239
Faulting 239
Underground Blowout 240
Oil & Gas 240
Transition Zone 241
Fracture Gradient 241
Abnormal Pressure Indicators 243 Sloughing Shale 243
Gas 244
Mud Temperature 244
Shale Density 245
Chloride Trends 245
Pit Volume Increase 248
Paleo Data 249
Drill Rate 249
Dxc 251
AA. FTIR Theory 255
AB. Basic Electricity & Troubleshooting 257
8
Forward PALADIN’s commitment to training is paramount to the success of our company. The Oil Field
and Technology are changing daily. And we, as an oil field service company, must do whatever
it takes to be sure that our technology and employees rise to meet this changing environment.
This two pronged attack, equipment and training, can be seen in our instrumentation upgrades
and in our employees as they progress through the various training programs being offered by
PALADIN. Therefore, it is to this commitment in providing the best service, equipment, and
professionally trained employees that this and all other of PALADIN’s training courses are
dedicated.
Our Name:
The name PALADIN was chosen because it represents the best of
the best, with origins deep in history, dating back to the ‘Dark
Ages’. Late in the 8th century, Charlemagne rose to become
emperor of Western Europe, the first emperor of the region since
the fall of Rome. Yet trouble was brewing in the south. The
Saracens had invaded Spain from Tangier and were now
threatening to conquer the rest of the continent. The pope beseeched Charlemagne to hold the
invaders at bay. To meet this goal, Charlemagne enlisted the twelve greatest knights of his time
to assist in that mandate. Called the Paladin, these knights represented the best Europe had to
offer. Like the knights of Arthur’s Round Table, they were seen as the defenders of the faith and
9
the protectors of Charlemagne’s empire and the rest of the world. For this reason, the name
PALADIN is synonymous with champion, because the PALADIN were Charlemagne’s champions.
As a PALADIN employee, your mandate is to protect the reputation of the company by being
the best of the best, just like a knight in the service of Charlemagne. Therefore in everything
you do, always remember the PALADIN mandate and go the extra mile for quality, service and
performance, thereby protecting the company and proving you are a champion.
Where to Start:
In order for you to do the best job for PALADIN and our clients, there are several subjects that
must be understood and will serve as a foundation for more advanced topics in the future.
These subjects are your day to day job, a general understanding of Geology and Lithology, an
understanding of the Drilling Rig, and a background in the types of Gases you will encounter as
a Surface Logger. With these mental ‘tools’ firmly fixed in your mind, you will be able to log
most continental wells. For all the other wells, offshore and international, we will offer courses
that will deal with more advanced topics. The courses to follow will include such advanced
logging topics as Pore Pressure Detection, Drilling Optimization, Well Control, and Advanced
Formation Evaluation. Once you have completed this suite of study, you will be able to work
anywhere in the world as a valuable asset to PALADIN and our clients.
10
Introduction to Surface Logging
What is Surface Logging?
Surface Logging, often referred to as Mud Logging, is the art and science of extracting
information from the drilling fluid that is used to construct a depth-related plot of varying
physical parameters of a formation. At the end of the drilling operation, you will have
constructed a permanent document that has recorded the changes in the concentration and
composition of hydrocarbons and have pinpointed each zone of interest as to where it is
located in the well-bore. This is accomplished by constantly monitoring the drilling fluid with
specialized equipment to establish a baseline or threshold value from which significant
deviations well be indicated.
History:
Commercial Mud Logging services started in the late
1930’s after the invention of the “wheatstone bridge”, a
gas detection device. It consisted of a small coiled wire
that was heated by an electrical current and gas samples
passed across the coil would burn and cause it to heat up
and increase the voltage. The higher the voltage, the more gas would be present in the sample.
This is basically the same principle used today in this type equipment.
The first mud logs were hand draw, taking many hours to plot the data and type in the
descriptions. In cases where multiple logs were required or when drilling was rapid, one person
11
drew the logs, while a second person collected samples and manually recorded the drill rates.
Gas was plotted by physically watching the volt meter and recording the values; total gas only.
Later all the data had to be assimilated and put into a form readable by the client, this became
the mudlog.
Technology changed little until the early 1970’s. Then, there was an electronics boom in rig
instrumentation. There were instruments for everything. Before the introduction of a rig EDR
(Electronic Drilling Recorder), depth and other rig functions had to be monitored by
instrumentation provided by the mud logging company. But still the processes were crude.
Depth / drill rate remains a key function
monitored by the surface logging engineer
today. However, prior to the advent of the EDR,
drill rate had to be obtained by whatever
means available. One technique involved
running a cable from the logging unit, up to the
crown of the rig, then down to the traveling
block. Connected to an instrument like the one
seen on the left in the logging unit, the depth
and drill rate could be monitored as a reel
within the logging unit released cable as the
Block and Kelly descended during drilling. Since a foot was designated by a certain number of
turns of the cable reel, a pin on the recorder would initiate when the reel unrolled out a foot.
The chart moved at selectable speeds, all in given values of minutes. From determining when a
foot was made on the chart and the time between ticks, a drill rate could be obtained.
Cumbersome and dangerous, especially when rigging up a system like this, other companies
found an easier method to obtain the drill rate.
12
The Geolograph was a drilling recorder designed to work much the same way as the drilling
monitor described above. Residing on the rig floor, usually in the
doghouse, this device had a rotating drum calibrated to spin once
every eight hours. Again a cable was run up to the crown and down
to the block. As a foot of cable was released, a pin would mark a
foot on the chart attached to the rotating drum. The image on the
right is what the depth marks looked like on the chart of the
geolograph. Reading drill-rate from the chart was difficult and
highly inaccurate.
Note: The Geolograph is still in use today. When an EDR is
unavailable, the method described below is used to obtain the
depth.
However, the mudlogger would
rarely have to use this chart.
Instead he would attach a small
micro-switch next to the
geolograph depth pin. When a
foot was marked on the
geolograph, the micro-switch would close advancing a counter in the logging unit. The method
was simple but effective.
Accurate depth was maintained by keeping a close account of the pipe tally. As each joint was
drilled to a point called ‘Kelly-Down’, the exact depth expected at that point was recorded and
that value updated on the depth counter
powered by the micro-switch on the
geolograph.
13
Other rig and drilling functions were monitored in the logging unit. Each had it’s own associated
equipment. In addition to the standard total gas and chromatograph, there were instruments
for depth, pump strokes (used for lag and rop calculations), mud temperature and resistivity /
chlorides plus a host of other drilling, mud and special gas detection equipment.
As technology increased through the early 1980s, other types of logging instrumentation
appeared. The use of infrared gas detectors like the iBall Bloodhound used by Paladin is not
technology developed in the 21st Century. To the
contrary, in the middle 1980s this technology was
available but was not in wide use.
Seen on the right, this equipment marked a major step
forward in hydrocarbon gas detection, providing a direct
RS232 port for communication with a computer, both
total gas and chromatography data was available for
incorporation with other logging data. At this point it was
no longer necessary to transfer data from a strip chart
recorder or gas meter into a computer. All drilling data
could now be stored by a computer and printed out for
quicker transfer to a mud log, albeit a log still drawn by hand.
Making copies of hand-drawn mud logs was a chore. One might think that a copy machine
could have been used for this, unfortunately, due to the size of the logs and the velum on which
they were drawn, a copy machine could not be used. Reverting to the process used by
engineers to create ‘blue-prints’, mudloggers used a two-step process to copy logs.
The original onion skin was placed onto a light
sensitive paper the size of the onion skin, hand drawn,
log. That sandwiched bundle was fed into a special light
via a slow rotating pressure bar. The light exposed the
paper with the imprint of the log.
14
After a few minutes in the ‘Roto-Light’, as they were called, the paper would emerge and then
be placed into a clear plastic tube like the one seen in the previous photo. Standing atop an
open container of ammonia, the exposed log was placed into the tube. The ammonia would
‘develop’ the image after a couple minutes, producing a log copy. (Note: The fumes from the
ammonia were so strong in the logging unit that the mudlogger was often seen ‘crying’!) From
start to finish, the process took about five or six minutes for each copy. If the logger had a large
distribution list, this process could take several hours to get copies ready for daily distribution.
That is why most logging operations required two loggers for each tower, one person to gather
samples, write descriptions and maintain drilling data while the other person drew the logs and
made the copies. It was a time intensive operation and often painful to the eyes and nose.
Technology has changed and none too soon for our industry. Drilling data is provided direct into
the logging unit, provided by the client.
Complete with everything that is
happening on the rig and providing our
all important depth and drill rate, all
our logging data is now gathered
automatically by the computer. No
additional rig-up is required by our
logging personnel.
Log drawing software can now
continuously monitor all the data
needed to produce the log, except the lithology and hydrocarbon analysis. When the internet is
added into the equation, our customers can even watch the real-time mudlog being created by
the computer from their office anywhere in the world. Depth, rop, gas, chromatography even
MWD data like gamma ray is updated automatically and presented as it happens to the web.
When the logger has completed his lithology description and interpretation and entered the
data into the computer, that information becomes visible along with the rest of the log data.
Today we can even add photomicrographs of cutting samples to the mudlog, providing a direct
15
visual aid of the lithology to our customers. Technology has finally freed the logger to do what
he is best at providing, an in-depth analysis of the cutting samples and evaluation of the rocks
for the presence of hydrocarbons.
Responsibilities
The process of mud logging involves five separate disciplines and responsibilities and they are
as follows: Assembling the necessary Geological Information to accurately interpret the data,
gathering the Gas Information from the well-bore, analyzing the drilling parameters as to their
impact on the interpretation process, gathering and analyzing drill cuttings, and constructing a
reliable end product – the Mud Log.
Geological Information is mainly composed of a 1)Prognosis, 2) Distribution list, a 3)
Correlation Log, and 4) a Staking Plat. The Prognosis, seen on the
left, is usually a one or two page document that the Company
Geologist estimated formation tops, reporting requirements, and
special instructions that will be required as the drilling progresses.
The Distribution List contains all the ‘interest’ owners in the well
and what information each is entitled to.
The Correlation Log is a copy of
an Electric Log from a nearby well
that allows you to compare your
mud log and more accurately call
tops and project upcoming formations. Each well location has to
be surveyed and staked as to its specific geographical location and
contains the legal description, directions to the site, and the
16
Shaker w/trap
“Ground Level” elevation which you will need to determine the wells geological relationship to
the Correlation Log.
The Staking Plat identifies the location of the well, in addition to the location of the offset wells
used for correlation. For horizontal wells, the direction of the planned wellbore is presented.
Well-bore Gas Analysis is accomplished with specialized
equipment that is designed to extract and measure the
increases and decreases in the amount of hydrocarbons
coming from the well-bore. To liberate the entrained
hydrocarbons from the drilling mud, we have a Gas Trap or
Agitator located on the shale shaker so that we have access to the drilling mud as it returns
from the well-bore.
Uses Wheatstone Bridge Uses IR
Inside the logging unit is a vacuum pump that pulls the gas sample
from the Trap through tubing and into the unit where it goes through
filtering process, then pulled across gas sensors that measure the
amount of hydrocarbons coming from the mud.
PALADIN uses specially designed software and hardware to gather and
record gas information along with drilling parameters. We previously
mentioned the ‘Wheatstone Bridge’. Although this technology has been updated since its’ initial
creation in the 1930’s, newer techniques for both
detecting and analyzing hydrocarbon gas have been
developed. The iBall Bloodhound, seen here, is the
instrumentation Paladin currently uses to large
measure. Unlike detectors using the Wheatstone
bridge, where the gases are ‘burned’ or used to cool a
heated wire, this technology uses infrared light to
examine the gasses passing through its’ analysis chamber, thus making the instrument both
17
intrinsically safe and not altering the
gas sample. Briefly, infrared light at
specific frequencies excite the
molecules of hydrocarbon gas thus
creation an absorption from the
infrared light in specific wavelengths.
By measuring this absorption, the
quantity of gas can be calculated.
Chromatography using infrared is accomplished in much the same manner as detectors using
the Wheatstone bridge. The gasses are passed through a material that separates the gases out
from the total gas sample based on their molecular weight. The lightest gas appears first,
methane (C1), followed by ethane, (C2), then propane, (C3), iso-butane, (iC4) and finally normal
butane, (nc4). The separated gases are passed in front of the IR detector and their quantity is
measured as described earlier. Again, there is no alteration of the gasses being analyzed.
Drilling Parameters are recorded along with Gases to aid in the interpretation process. Most
commonly, only depth and Rate of Penetration (ROP) are monitored because they are essential
for the proper lagging of the recorded gases. It is becoming more commonplace for the logging
unit to be furnished a WITS (Wellsite Information Transfer Specification) connection which
allows us to gather information on Rotary, Torque, Pump Strokes, Pump Pressure, Flow-line
sensor, and mud levels in the pits. All of these drilling parameters can contribute to a more
accurate assessment of the commercial viability of the project.
The Bloodhound software provides a direct display of this data as a standard part of the drilling
screen. In a later section of the manual, we will discuss in detail the operation and
interpretation of the Bloodhound.
Drill Cuttings Analysis is the most important part
of our evaluation process. A newcomer to the
industry would probably say that Gas Analysis
18
would be more important. However, the rocks contain all the answers, if you know what to
look for. You can see porosity, hydrocarbon staining, fluorescence / cut, and minerals that will
affect the ability of the zone to produce hydrocarbons. All these rock characteristics are
important in evaluating a formation for hydrocarbon content. Be aware, there is as much art to
this procedure is science. It takes many years of experience to be able to do this analysis well.
So don’t get discouraged if you are unable to see all the necessary rock properties immediately.
As you gain both knowledge and experience, the rocks will reveal more and more of what they
are saying about a given formation. However we do have other tools and procedures to aid in
the evaluation process that will be discussed in later sections of this manual.
The Mud Log is our end product and is a visual presentation of your skills as a Data Analyst. It
is a “permanent” record of the rock
formations and hydrocarbon content of the
well-bore that was collected during the
drilling process. Put as much information
on it as you can because, at some point in
the future, that bit of information could be needed to aid in evaluating the well in the future.
Adhere to the Standard Practices set by PALADIN and your mud log will be a usable tool to aid
in the evaluation process.
19
PALADIN Employee Professionalism From the earliest days of the oil industry to the mid 1970s, the ‘mudlogger’ was often viewed
by the industry in a less than good light. There was probably good reason for this feeling. The
stories are legion and beyond the scope of this text. However, the point is, times are different
now!
We are now in the 21st century. A great deal has changed within the oil industry as a whole and
with logging in general. Gone are the days when the term ‘mudlogger’ referred to a less than
desirable member of the drilling operation. It has been replaced by a professional, highly
trained individual whose knowledge and expertise are a greatly valued addition to the drilling
operation. Often the logger is the primary source of current drilling activity as well as
information about the subsurface and any potential hydrocarbon bearing formations. He has
become the ‘goto’ person on the rig for answers by drilling personnel and our clients.
We can define the level of individual necessary for today’s surface logging operations by five
key attributes. We call these the 5 tools:
INTELLIGENT
DEDICATED
METICULOUS
COMMUNICATIVE
STRONG WORK ETHIC
Indeed, these are what separate PALADIN from other logging companies. Since all logging
companies offer the same service, the choice of which company to use will come down to these
five key qualities as seen by our customers. Those companies who can offer this type of service
will flourish, while others will go the way of the dinosaur. Equally those employees that are able
to provide this type of work ethic will do well, while others will not.
Safety is first and paramount. We expect all our employees to work safely, with a continuous
eye for unsafe conditions. We are always aware that it is everyone’s responsibility to maintain a
safe work environment and ever cognizant that we have a “Stop Work Authority’ if a potential
hazard is identified.
The second item from our list of four qualities is Professionalism. A sense of Professionalism is
manifest in numerous ways. The most obvious way to see it is by wearing company coveralls
when out on location. This simple act lets others know that you take pride in your company,
20
yourself, and your work. In addition, it gives the employee an added sense of belonging that
can easily be lost when out on location for long periods of time with little or no contact with
other off-well PALADIN employees. Be it company coveralls, company hard hat, or other
company garments, all provide that same sense of connection, in addition to the look and feel
of a professional.
Another aspect of professionalism is Quality. Quality can be seen in many aspects of our work.
It means keeping the logging unit clean and in a work ready mode. This is important if the
client or other well sight personnel come into our work area. It is also important for our own
personnel, in addition to other visiting company employees. No one wants to have to clean
someone else’s mess! So keep the logging unit clean at all times for our customers, your work-
mates, and yourself. Here are more areas where Quality and Professionalism can be seen:
Catching samples on time and not stored up in a bucket.
Have all logs up to date.
Have correlation logs out and being used.
Always have the lights on and the logging unit working.
Be dressed appropriately for work.
Wear PALADIN coveralls whenever outside the unit.
Follow the company standards outlined in this manual.
Know your lag strokes (bottoms-up-strokes), current depth, and lag depth.
Keep up with rig activity.
Watch your instruments and be sure everything is working correctly.
Follow ALL PALADIN’s policies and procedures
Follow SAFETY guidelines and take online courses as prescribed
Evaluate all cuttings and gas carefully providing in depth analysis on your logs.
The logging unit is a mobile laboratory and should always be treated as such
From now on, District Managers and the General Manager will make spot checks of the
PALADIN field operations. If these guidelines are not being followed, you will be ‘reminded’, a
notification letter will be placed in your personnel file, and if the behavior is repeated,
termination will follow.
Following these guidelines is important for both YOU and our customers. We will all benefit
from this in the long term.
21
This is NOT the
ideal Paladin
Surface Logger!
22
Drilling Rig
For those people that have little or no experience on a drilling rig, our discussion of this all important topic will begin with an explanation of the different job titles you will meet during your early introduction to the oil field.
WHO’S WHO at the Rig
Geologist The Geologist is the earth scientist that developed the geology of the prospect and hired the logging company. As the logger for PALADIN, we work directly for the Geologist. We provide Daily logs, Morning reports, and other information on a daily basis as well as at the end of the well. Petroleum Engineer A Petroleum Engineer is the person within the exploration company responsible for the engineering design of the well. Petrophyscist Some of our clients will have engineers whose job it is to evaluate and prescribe the types of formation evaluation used on the well. These techniques include wire-line logging, core analysis, or other quantitative techniques. Company Man (Drilling Foreman) The ‘Company Man’ – Drilling Foreman is the well-site representative of the exploration company. Their specific job is cost control and day to day oversight of the drilling operation. The PALADIN logger on-site provides direct support to the ‘Company Man’ in terms of morning reports and gas analysis. Tool Pusher Toolpushers are directly in charge of the drilling rig, it crews and operation. They take their orders from the ‘Company-Man’ and work for the drilling company. Driller Drillers work for the Toolpusher and are responsible for the actual drilling operation. They operate the drilling station and control the minute to minute operation. Directional Driller The Directional Driller works for the ‘Company Man’ and is responsible for drilling any hole deviation or horizontal operations.
23
Mud Engineer Key to the success and operation of drilling is the drilling fluid, mud. The chemistry of this fluid is key to the efficient and safe drilling operations. The Mud Engineer is responsible for maintaining this critical chemistry and will provide a daily report of his evaluation. An example of this Mud Report follows.
24
Roughnecks Roughnecks work for the Driller as his crew and provide the physical part of rig operations during drilling. Roustabouts
These individuals provide basic operations tasks around the rig and are essentially unskilled.
DRILL RIG
As a logger, the Drilling Rig is the center of your Universe. Therefore it is
extremely important for you to understand its’ parts and function in order
for you to do your job. Many different types of rigs exist, but for the
majority of PALADIN operations, the standard land ‘triple’ is the type you
will encounter the most.
Note: A Triple refers to a ‘stand’ of pipe. A
joint of drill pipe is 30 feet long, like those
pictured to the right. A stand of drill pipe
would be about 90 feet. Notice the rig to
the left. A stand of drill pipe is standing in the derrick. Only a
‘triple’ drilling rig can hold a three joint stand.
The parts of a drilling rig are defined in this diagram. For actual photographs of each part, see
the examples below.
There are numerous parts to a drilling like the one pictured here.
Pay particular attention to item 16 and item
21. The Kelly, #16, provides the conduit
through which the drilling fluid enters the
drill string. Item 21 is the Rotary table which
rotates the drill string creating the cutting
action by the bit on the bottom of the hole.
The mud pumps that pump the fluid to the
Kelly are seen as number 20. Today these
are very large compared to those in the
diagram. Pictured here is the V-Door, the
Drillers Shack, and the Cellar. A closer look
at the Cellar reveals the Blow-Out
Preventers. This is the rigs first line of
25
defense against a pending blow-out. The blow-out preventers are comprised of the pipe rams
and blind rams. For more in-depth explanation, research the internet. This is a subject that is
much deeper than it appears on the surface.
A closer look of the rig floor is seen here with drill pipe extending above the rotary table and
out of the picture. The rig floor is where we find
the primary operation of drilling. Below you will
see the Kelly that was defined previously. With
today’s drilling rigs, the scale of the operation is
considerable greater than the one pictured in the
diagram on the last page. Seen here, the Kelly is pulled up from the
rotary table allowing the drill crew to work on the rig.
Whenever operations are underway on the rig floor, the driller is
manning his controls, referred to as the driller’s station.
Seen to the right, this position allows the driller to control all the hydraulic, rotating, lifting, and
other drilling operations of the rig.
On the rig floor, the device that actually controls the lifting of the
drill string is Draw Works. Connected to the traveling block, the
draw works is able to lift the entire weight of the drill string.
A better relationship between Kelly,
mud pumps and pits can be seen in
the diagram to the left. The Suction
pit provides drilling fluid to the mud
pumps which push the drilling fluid
down through the Kelly into the drill
string.
26
The mud pumps are the devices that actually force the drilling fluid down the drill string and
eventually up through the annulus. (For a more detailed analysis of
this operation, see the LAG calculation section of this manual.)
Here we see the mud pumps in their capacity of
Pulling mud from the suction pit and pumping it
into the mud line attached to the Kelly.
Once the mud reaches the bit, it is pumped into the space between the drill pipe
and the hold. This is called the Annulus, indicated by the arrows pointing up in
the figure to the right. The mud then continues up the Annulus to the surface
where it will eventually enter the Flow Line as seen below.
The two upward pointing arrows indicate the flow of the mud from the bottom of the hole
through the Annulus to the surface. Flowing out the Bell Nipple, the drilling fluid flows down
the Flow Line to the Shale shaker. In the diagram below, you can see the Gas Trap indicated.
The Flow Line enters the Possum Belly immediately below the Gas Tap. (We use the term Gas
Trap and Gas Extractor interchangeably). The screens on the ‘Shaker’ below the Gas Trap are
the place where we collect our cutting samples. As a PALADIN Surface Logger, you will become
extremely familiar with this location on the rig! Both your gas sample, via the gas trap, and your
cutting sample come from here.
As you get more and more accustomed to the
drilling rig over time, you will learn much more
detail about the operation of the drilling rig. For a
novice logger, the information provided here will
be enough to get you started doing your job.
27
A word of caution, the drilling rig is a very dynamic and potentially dangerous environment. The
PALADIN safety training will help provide insight into the potential hazards. Safety is paramount
to PALADIN.
Drilling Fluid (mud)
The whole subject of the drilling fluid is a topic for the advanced logger training. But it is still
important to have some basic idea what the terms are and what they relate to. Most rotary
drilling methods, with the exception of augering methods, require the use of drilling fluids.
Drilling fluids perform several functions. The primary functions include cleaning the cuttings
from the face of the drill bit, transporting the cuttings to the ground surface, cooling the drill
bit, lubricating the drill bit and drill rods, and increasing the stability of the borehole. In
addition, there are a number of secondary functions. Some of the more significant secondary
functions are suspending the cuttings in the hole and dropping them in surface disposal
areas, improving sample recovery, controlling formation pressures, minimizing drilling
fluid losses into the formation, protecting the soil strata of interest, facilitating the
freedom of movement of the drill string and casing, and reducing wear and corrosion of the
drilling equipment.
Previously in the Who’s Who section of the Drilling Rig, a common Mud Report was provided.
The following table will provide some insight into the terms used on this report, their meaning,
and why they are important.
Property Influences Desirable Limit
Density (Mud Weight)
In Pounds Per Gallon (PPG)
Drilling Rate
And hole stability
Lower limit 9 PPG
For Coast and offshore, 8.33 PPG
For Continental
Viscosity (vis) Cuttings Transport
Cutting Settlement
Circulation Pressures
Measured in seconds, 32-48
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Filtration Wall cake thickness <1/16th inch
Sand Content Mud Density
Abrasion to Equipment
Drilling Rate
< 2% / volume
pH (Acidity
or Alkalinity)
Mud Properties
Filtration Control
Hole Stability
Corrosion of Equipment
8.5-9.5
Neutral is 7
Calcium Content
(Hard Water)
Mud Properties
Filtration Control
< 100 PPM
As you can see, these are not all the properties found on the Mud Report. However this will
serve to provide a place to start in understanding the critical subject of the drilling fluid.
In the Advanced logging class, the topic of the drilling fluid will be studied more closely so that a
good understanding of its potential and importance can be seen.
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Basic Geology
Introduction
Geology is the study of the earth and its history. That history can be complex at times. But it
had a beginning 4.5 billion years ago. The earth was formed from the original cloud of material
that formed our sun, the
planets, and other bodies in the
solar system. Since then the
earth has undergone extreme
changes from a water world, to
an ice covered planetary
snowball, to a world with
constant volcanic eruptions
appearing as a planet on fire.
All of these events and many
more have lasted millions of
years and their evidence is all
around us and can be seen if you know what to look for.
As we drill a well, we are actually traveling back in time seeing the evidence of a world we
would not recognize today. All of these earth changing events in the history of the earth are
divided into specific blocks of time and can even be subdivided into smaller units based on
regional changes during each age.
Taken as a whole, this is the geologic time scale.
This almost unimaginable time scale can be seen
below and is broken down into Era, Period, and
Epoch. Displayed is the entire Geologic Time
Scale indicating the names, ages, and major
events that occurred in the past 4.5 billion years.
Take some time to look down the history of the
earth. For indeed you will see a continuous
microcosm of this each time you look through
the microscope at a sample coming from a depth
in the subsurface. ….a fleeting glimpse of a world
we never saw.
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31
Rocks Types
As a surface logger, you will see many different types of
rocks from the preceding geologic time scale in the wells
you will log for PALADIN. Three basic rock types exist;
Igneous (rocks formed directly from magma, molten rock),
metamorphic (rocks reformed from other rock types by
weathering, reburial, heat, and pressure), and finally
sedimentary (rock created by destruction, deposition, and
cementation of other rock types). However the
predominate type of rock will be Sedimentary. Sedimentary
rocks constitute marine sediments and are derived from
weathering and erosion of the continents and on a smaller quantity, on the deep sea floor.
These sediments are generally millions of years old. The exception of this is offshore where
extremely recent sediments will be encountered that may not even be consolidated into rock.
In this case, the sediments are only 10,000 to a few hundred thousand years old. The thickness
and composition of these beds is influenced by many factors such as marine currents, and
deposition by rivers like the Mississippi and others. These beds also reflect the relief and
climate of the adjoining landmass, the water depth at deposition, distanced from shore at the
time, the rate of subsidence of the shelf (slow or rapid). Through the distribution of recent
sediment on the continental shelves have been disturbed by the Pleistocene sheet (last ice
age), careful investigation indicates that the normal distribution is coarsest grain material near
the shoreline and successively finer material grading offshore. In the geologic past, the
continental shelf has been greatly expanded by the subsidence of the continents. Today we are
seeing the loss of continental margins by rising seas due to global warming coupled with normal
subsidence. These paleo-shorelines extend far inland from those of present day. The positions
of ancient shore lines may be marked by the edges of buried sedimentary layers and ancient
water depths, distance from shore, and other environmental factors may be interpreted from
features of the ancient sedimentary beds by comparison with features of recent sedimentary
layers.
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The key to understanding
sedimentary rocks is to
realize that all
sedimentary processes of
weathering,
transportation, and
deposition are aimed at
one goal - reaching the
three final end products
of all sedimentary processes, quartz sand, shale (clay), and limestone (CaCO3). The central idea
is summarized in the Simple Ideal Sedimentary Model.
Quartz sandstone
Shelf shale
Limestone with fossils
Imagine an average continental igneous rock, a
granodiorite, as at right (click picture to enlarge). It
contains quartz, and feldspar, and other minerals.
Now imagine we are going to do every sedimentary
process to that rock that it is possible to do, including
complete weathering, and complete transportation,
sorting and deposition. The results are always the same - quartz sandstone, shale, and
limestone separated from each other in different depositional environments: the beach, near
shelf, and far self.
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Model Processes
Sedimentary systems work this way because of two processes.
WEATHERING: Weathering is the breakdown of one more of the rock forming minerals, all are
subject to degradation (weathering into something else), except quartz. Quartz, for all intents
and purposes, does not weather and will survive in the system relatively unscathed.
There are lots of other weathering products, of course, but they are just details. The simple,
ideal model predicts three end products, quartz sand, shale, and limestone, which all together
compose the vast majority of sedimentary rocks.
Transportation and Sorting: The second
process is sorting during transportation. The sand
and clay, beginning as a poorly sorted mixture,
are separated more and more as they travel
down stream away from the source. Quartz sand,
which rolls and bounces along the bottom, does
not transport as easily as clay which travels in
suspension. And the CaCO3 is dissolved and therefore just travels with the water.
The result is, during transportation these three weathering products do not transport equally
well, and become separated. The final separation takes place at the ocean shoreline. Here we
see river transported sediment entering the ocean. Waves crashing on the beach keep the
sediment
continuously stirred
up. The quartz, being
relatively heavy, settles quickly to the bottom, the clay remains in suspension until it drifts to
the quieter near shelf, where if finally settles to the bottom to form shale.
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Finally, the dissolved CaCO3 precipitates out of suspension in the far shelf, beyond the range of
sand and clay to form limestone. The calcite is deposited because plants and animals extract it
from sea water and use it to build their skeletons. After death their calcite skeletons form the
limestone sediment.
Sedimentary Attractors
. An attractor is any state toward which a system naturally evolves.
Someone who is an attractive person (by temperament as well as physically) is an attractor
toward whom we are naturally drawn. Biological fitness is an attractor toward which species
evolve. A valley surrounding a hilly landscape is an attractor. A ball placed anywhere in the
landscape will roll down the hill toward the valley. It doesn't matter where the ball starts or
how fast it is rolling, it eventually ends up at the bottom of the valley - the attractor. (The
attractor is actually gravity since if the ball had its druthers, and the opportunity, it would fall to
the center of the earth, the center of gravity.)
In the sedimentary model quartz sandstone, shale, and limestone can be thought of as
"attractors." All the processes in the sedimentary system are "attracted" to these three end
products. And this is true regardless of what you start with.
The simple, ideal model begins with a granodiorite, but
any source rock has the same three attractors, and this
is true even if the components to make one of the
attractors is not present in the source rock. For
example, a source rock with no quartz cannot produce
a sediment with quartz, but that does not take away
from the fact that quartz is an attractor in the system.
Sandstone Maturity
Sandstone study is particularly important, not only because sandstones are common, but also
because they contain a lot of information. Near the sourceland sandstone contain lots of
incompletely weathered minerals and rock fragments. The more the sand transports the more
35
these weatherable components transform into clay and dissolved minerals (e.g. calcite), leaving
behind more and more quartz as the only remaining, unweathered sand grains. At the end,
then, all the rock forming minerals transform into other sedimentary minerals, except quartz.
Sandstone composition is thus a measure of how close a sandstone has gotten to the quartz
attractor - the end product
of the simple ideal model.
This leads to the concept of
maturity.
MATURITY - a relative
measure of how extensively
and thoroughly a sediment
(sand size and larger) has
been weathered,
transported and reworked
toward its ultimate end
product, quartz sand.
The definition of maturity makes it clear that our interest in sedimentary rocks is in their
evolution, and ultimately we want a classification that allows us to explore that evolution. The
simple ideal model can be achieved, however, only in a region that is tectonically stable
(tectonics has to do with earth movement, and the structures that result). The simple ideal model
is what tectonic stability gives you, and is about the only place that limestones are deposited.
Most clastic sedimentary rocks (i.e. sandstones and shales), begin their history in an area of
tectonic instability, a region of mountain building.
Thus, achieving the three sedimentary attractors of the simple ideal model is not easy, and
completely mature sandstones are not that common. To more fully understand sedimentary rocks
and their relationship of petroleum geology, in a coming section we will discuss the types of
sedimentary rocks, their depositional environments, and their description.
36
Basic Structural Geology and Plate Tectonics
As you drill the subsurface you will soon discover that these layers of rock you see are not
simple pancakes laid on top of each other. These beds of rock will appear broken, shrunk,
twisted, and even removed from well to well. The question is WHY!
Rocks are deposited in
successive beds, one on top of
the other over geologic time.
Unfortunately these uniform
structures don’t remain so
perfectly aligned for long.
Because the earth is an
extremely dynamic environment,
many other natural factors come
into play.
The earth’s surface is fractured into a number of tectonic plates that are in constant motion.
As these plates move and collide, the lithosphere buckles, warps, and is torn apart. When this
occurs, the Earth's surface shakes with great force, like that which accompanies earthquakes.
Volcanoes are common along many plate boundaries as well.
Plate Tectonics
Plate tectonics refers to the process of plate formation, movement, and destruction. It finds its
foundations in two theories, continental drift and sea-floor spreading. Continental drift
describes the movements of continents over the Earth's
surface. Sea-Floor Spreading refers to the creation new
oceanic plate material and movement away from the
midocean ridge. It was Alfred Wegener in the early 1900's who
brought forth the concept that the "shell" of the Earth's
37
surface was fractured, and these "pieces" drifted about. Blasphemy in the minds of scientists of
Wegener's day, some 50 years later his ideas were finally accepted. Wegener was able to piece
together (pardon the pun) several bits of information which led to his conclusion that the
present configuration of the continents is not the same as it was in the past. In fact, the
continents were one "super-continent" called Pangea.
Carefully examine the east coast of
South America and then let your eyes
drift to the west coast of Africa. It
looks like you could "fit" South
America up against Africa like a puzzle.
The same can be said for the fit
between North America, Africa, and
Europe.
When we slide the continents together,
some overlap between the land masses
occurs. This is possibly due to the
creation of exotic terrain, new land that
has been formed somewhere else and
moved to its present location. This
remarkable correspondence provides
circumstantial evidence for the theory of
continental drift.
All these movements of the crust, along with other process, break, bend, and warp the
subsurface rock beds. These features are what form the petroleum reservoir traps necessary to
hold hydrocarbons. We will examine the basic forms of these starting with the FAULT:
38
Faulting
A fault is defined as a fracture in a rock formation along which there has been movement of
the blocks of rock on either side of the plane of fracture. Faults are
caused by plate-tectonic forces defined previously.
Bedrock, the solid rock just below the soil, is often cracked along
surfaces known as planes. Cracks can extend up to hundreds of
kilometers in length. When tensional and compressional stresses
cause rocks separated by a crack to move past each other, the crack
is known as a fault. Faults can be horizontal, vertical, or oblique.
The movement can occur in the sudden jerks known as
earthquakes. Normal faults, or tensional faults, occur when the
rocks above the fault plane move down relative to the rocks below
it, pulling the rocks apart. Where there is compression and folding,
such as in mountainous regions, the rocks above the plane move upward relative to the rocks
below the plane; these are called reverse faults. Strike-slip faults occur when shearing stress
causes rocks on either side of the crack to slide parallel to the fault plane between them.
Transform faults are strike-slip faults in which the crack is part of a boundary between two
tectonic plates. A well-known example is the San Andreas Fault in California. Geologists use
sightings of displaced outcroppings to infer the presence of faults, and they study faults to learn
the history of the forces that have acted on rocks.
Folding
A layered rock that exhibits bends is said to be folded. The layered rock was at one time
uniformly straight but was stressed to develop a
series of arches and troughs. A compressive stress
compacts horizontal rock layers and forces them
to bend vertically, forming fold patterns.
39
Anticlines and Synclines
An anticline is a fold that is arched upward to form a ridge;
a syncline is a fold that arches downward to form a trough .
Anticlines and synclines are usually made up of many rock
units that are folded in the same pattern. The tip of a fold
is called the nose. The center axis of a fold is called the
hinge line and lies in the axial plane that separates the
rocks on one side of the fold from the rocks on the other
side that dip in the opposite direction. Extensive folding is
represented by a repeated pattern of anticlines and
synclines. Two anticlines are always separated by a syncline, and two synclines are always
separated by an anticline. One side of the fold is called the limb; a side-by-side syncline and
anticline share a limb. Frequently, an anticline or syncline can be identified only from the
systematic change in the dips of the sloping rock units from one direction to the other,
identifying the hinge line of the fold.
Plunging folds. Plunging folds have been topped by tectonic forces
and have a hinge line not horizontal in the axial plane. The angle
between the horizontal and the hinge line is called the plunge and,
like dip, varies from less than 1 degree to 90 degrees. Plunging
folds characteristically show a series of V patterns on a bedrock
surface.
Structural Basin and Domes
A structural dome, a variety of anticline, is a feature in which the central area has been warped
and uplifted and all the surrounding rock units dip away from the center. Similarly, a structural
basin is a variation of syncline in which all the beds dip inward toward the center of the basin.
Basins and domes can be as large as 100 kilometers across.
40
Open, isoclinal, overturned, and recumbent folds. A variety of kinds of folds generally reflects
increasing amounts of tectonic stress (Figure 3
). An open fold is a broad feature in which the
limbs dip at a gentle angle away from the crest
of the fold. Isoclinal folds have undergone
greater stress that has compressed the limbs of
the folds tightly together. The limbs of
overturned folds dip in the same direction,
indicating that the upper part of the fold has
overridden the lower part. Depending on where the
exposure is in an overturned fold, the oldest strata
might actually be on top of the sequence and be
misinterpreted as the youngest rock unit.
Recumbent folds, found in areas of the greatest
tectonic stress, are folds that are so overturned that the limbs are essentially horizontal and
parallel.
Unconformities
The concept of an unconformity arises from
two of the oldest principles of geology, first
stated in 1669 by Nicholas Steno:
1. Layers of sedimentary rock (strata) are
originally laid down flat, parallel to the
Earth's surface. That's the law of
original horizontality.
2. Younger strata always overlie older
strata, except where the rocks have
41
been overturned. That's the law of superposition.
So in an ideal sequence of rocks, all the strata would stack up like the pages in a book in a
conformable relationship. Where they don't, the plane between the mismatched strata—
representing some sort of gap—is an unconformity. There are four main kinds of
unconformity. I've drawn sketches of each, showing rocks of Pennsylvanian age overlain by
rocks of Triassic age. If you know your geologic time scale, you'll be asking, "where's the
Permian?" The answer may be very different in each case.
Angular Unconformity
The most famous and obvious kind of unconformity is the angular unconformity. Rocks
below the unconformity are tilted and sheared off, and rocks above it are level. The angular
unconformity tells a clear story:
1. First a set of rocks was laid down.
2. Then these rocks were tilted, then eroded down
to a level surface.
3. Then a younger set of rocks was laid down on top.
In the 1780s when James Hutton studied the dramatic
angular unconformity at Siccar Point in Scotland—
called today Hutton’s Unconformity staggered him to
realize how much time such a thing must represent. No
student of rocks had ever contemplated millions of years before. Hutton's insight gave us
deep time, and the corollary knowledge that even the slowest, most imperceptible geologic
processes can produce all the features found in the rock record.
Disconformity and Paraconformity
42
Now take away the second step: strata are laid down, then a period of erosion happens (or
a hiatus, a period of nondeposition as with the Pacific Bare Zone), then more strata are laid
down. The result is a disconformity or parallel
unconformity. All the strata line up, but there is still a
clear discontinuity in the sequence—maybe a soil layer
developed on top of the older rocks, or a rugged surface
where they were eroded.
If the discontinuity is not visible, it is called a
paraconformity. These are harder to detect, as you might
imagine. A sandstone in which trilobite fossils suddenly give way to oyster fossils would be
a clear example. Creationists tend to latch onto these as proof that geology is mistaken, but
geologists see them as evidence that geology is interesting.
British geologists have a slightly different concept of unconformities that is based purely on
structure. To them, only the angular unconformity and the nonconformity, discussed next,
are true unconformities. They consider the disconformity and paraconformity to be
nonsequences. And there's something to be said for that because the strata in these cases
are indeed conformable. The American geologist would argue that they are unconformable
in terms of time.
NonConformity
Here is a better match to the situation in the Pacific
Bare Zone. There is a body of rock
that is not sedimentary, upon which
strata are laid down. Because we
aren't comparing two bodies of
strata, the notion of them being
conformable doesn't apply. This kind of junction between two different
major rock types is a nonconformity
43
Fundamental Formation
Characteristics
Formation Water
Petroleum Geology begins and ends with the formation fluids. It is therefore very important to
understand this relationship. The most basic type of formation fluid is water. Two types of
waters are found in the subsurface: 1. Free Water & 2. Interstitial or irreducible water. Free
water is water that is free to move within the rocks. Interstitial water is chemically bound to the
mineral grains. It is often called irreducible water since it cannot be removed during production
of hydrocarbons from a reservoir.
There are several types of subsurface formation waters that are part of Free Water, they are:
Connate
Juvenile
Meteroic
Mixture of the three
Connate water can be defined as the fluid left behind during the original deposition of the
sediment. However even if deposited in a marine environment, Connate water it will differ
from seawater in both concentration and chemistry.
Juvenile waters are primarily magmatic in origin. That is they were formed during volcanic
activity associated with original ground water. They are not contaminated by Connate water
and are referred to as primary waters.
Meteoric water is water formed near the surface and result from the filtering of rainwater
through surface material. This means that their salinity will be low. These are often acidic due
to the dissolved atmospheric gasses present during deposition. If these waters are encountered
in carbonate sediments, their acidity will become
neutralized.
The Mixture of all three is simply a merging of
Connate, Juvenile, and Meteoric. These waters will
be much more difficult to define since they are a
combination of the three primary water types.
44
To the left we can see how the water and hydrocarbons go together to fill the pore spaces
within the rock.
Once it is understood that fluids occupy the spaces within a rock, we can begin a discussion of
the single most important topic in Petroleum Geology; Porosity and Permeability. By
understanding how porosity and permeability work together to yield hydrocarbons, we as
PALADIN will be better able to provide our customers with the best well-site formation
information possible.
Porosity
Porosity is the measure of the amount of void space existing within a rock. It is either expressed
as a ratio of pore space to solids or more commonly as a percentage within the rock. It is
presented using the Greek Letter phi , pronounced ‘fee’, and represented by Φ.
Types of Porosity
Catenary Those pores that communicate with other pores and have only one throat.
Hydrocarbons are flushed out by natural pressure and water drive. ‘effective porosity’
Cul-de-sac Pores with only one throat connecting to another pore.
May yield hydrocarbons as reservoir pressure drops during mechanical flushing…water flood, also ‘effective’ porosity.
Closed Pore with no connection to other pores.
Unable to yield hydrocarbons
Going further, there are two classifications of porosity; Primary and Secondary. Primary
porosity is formed during deposition of the formation. Secondary porosity is created after
deposition by both physical and chemical changes in the rock, diagenesis. (See diagram under
Factors Effecting Porosity Loss)
Permeability
The other primary property of a reservoir rock is Permeability. Porosity by itself is insufficient
for the recovery of formation hydrocarbons. A connection must be present between the pore
spaces within the rock in order for formation fluids to be recovered. Therefore, Permeability is
defined as the ability of fluid to pass between pore spaces. For reference, Permeability is
45
measured in millidarcys (md) and commonly range between 5 to 500 md for producing
reservoirs.
Having defined porosity and permeability, how can this be related and used by loggers in the
field? This is easy to understand when you consider the fact that a firm relationship resides
between porosity and permeability and the physical characteristics of cut drill cuttings we
examine on location.
Factors Affecting Porosity and Permeability
Texture Cutting sample texture, that is Grain Size, Grain Shape, Sorting, and Packing are closely related
to the rocks porosity and permeability. The rock texture is also related to the original
environment of deposition and also displays the changes that have occurred during later
changes in the formation by heat, pressure, and other diagenesis processes.
The two terms used most widely in Surface Logging for describing sample texture are Clastic
and Crystalline
A Clastic texture is a sample that has broken grains in a random arrangement. These are
particles that have been transported by wind, water, or ice some distance from they were
originally created. They are composed of cemented particles that have been subjected to
chemical or physical weathering. The four most important characteristics of clastic sediments
are size, composition, shape, and sorting. For logging operations, sorting is extremely difficult to
determine since samples are intermixed in their trip to the surface.
A Crystalline texture defines a rock where the grains fit together forming a solid appearance
under the microscope. Often we will see chert under the microscope with this appearance.
Grain Shape As seen in the figure below, grain shape is another major factor in the porosity and
permeability of a rock. Two aspects of grain shape are roundness and sphericity. Roundness is
defined as the degree of angularity of a particle. The sphericity of a particle is the degree of
measure to define spericial shape. It is thought that the porosity decreases with spehericity due
to the fact that the particles are more compacted than those that are less sphericial.
46
Both roundness and sorting are indicators of the length of time that a sediment is kept in
motion before burial. Like water, wind is a major factor in grain rounding. Picked up, rolled, and
thrown, wind works sand smoothing out grains round edges.
Grain Size According to texts, grain size should have no effect on porosity. However, in some coarse sands
we find higher porosities than fine sands. This is most likely due to both sorting and
cementation factors. Therefore it is always important to note grain size since it can have some
relation to porosity.
Permeability is directly affected by grain size. As the particle size decreases, permeability will
decrease as well.
Grain Sorting Sorting isn’t a characteristic Surface Loggers can normally identify. However, it is important to
Porosity. When the degree of sorting goes down, the inner pore spaces are filled by other
minerals and cementation. The permeability will equally decrease as well.
Grain Packing The way in which grains are packed and oriented have a lot to do with porosity. As sediments
are deposited under rapid burial their orientation and sorting
cause a significant drop in both porosity and permeability. For
this reason, the best reservoir beds are those that have a
gradual burial phase that allows the grains to adjust slowly to
compaction preserving the pore space and their inter
connections. This is clearly seen on the left. Here the pore
spaces are completely filled with secondary mineralization
that may or may not be removed by mechanical process found
in well stimulation.
47
NOTE: Later in this text we will do an in-depth analysis of these key sample characteristics and
how they are used in the description of the drill cuttings.
Porosity Loss Porosity is often decreased or lost entirely due to several factors that occur after deposition.
We briefly discussed texture in the relation to porosity. Poorly sorted sands with a lot of clay
mixed in compact easily and lose porosity much faster than a clean sand.
Sub-surface temperature will have an effect on a sands porosity. This is because as the
temperature rises with depth, chemical reactions occur, decreasing porosity.
Abnormal formation pressures will have an adverse effect on porosity for the same reason.
Mineral cementation between pore grains is another factor than can limit reservoir porosity.
Many other factors exist that are beyond the scope of this text.
POROSITY LOSS FROM PORE DIAGENESIS (Idealized Model)
This is an example of the effect diagenesis of the pore space due to changes in fluid velocity and
pore grain surface area. Notice that both final conditions result in decreased porosity in both
diageneic conditions. It is a safe assumption that the types of reservoir porosity experienced by
PALADIN logging crews will display some type of pore blockage due to diagenetic processes.
48
NOTE: It is very important to note that porosity can rarely be seen with equipment present in
PALADIN’s field operations. We can provide only an idea as to what the actual porosity might be
in a sample. Porosity and pore blockage is best seen in thin section or under the scanning
electron microscope. We present this information here only as a means of understanding the
complexity in the study of porosity.
Common Depositional Environments
Sandstones We have already seen how depositional environment have a major influence on porosity and
permeability. In order to obtain a better understanding of this relationship to porosity and
permeability, we will discuss a few of the more common types of depositional environments
and the reservoir rock to which they relate.
Sandstone textures and compositions may be used to interpret many things about the history
of the sand, including source area lithology, paleoclimate, tectonic activity, processes acting in
the depositional basin, and time duration in the basin. Remember that the source area is the
land which is weathering and eroding to supply sedimentary debris to the depositional basin.
The figure below serves as the legend for the graphics below.
49
Graywacke
Lithic sandstone is commonly known by the name of Graywacke. Under the microscope you will
normally see a sample composed of dark sand-sized rock fragments, with some mica, quartz, and
feldspar grains in a clay-rich matrix. Many of these types of sandstones are composed of sand-sized
rock fragments.
50
Graywackes are thought to originate in environments where erosion, transportation, and deposition
happen so quickly that minerals and rock fragments do not have sufficient time to break down into finer
constituents as seen in the above diagram. The Turbidity current can be thought of as a undersea
landslide. These poorly sorted sediments carry clay, sand, and slit together without much sorting. These
are dark gray or greenish brown with a dull luster; micaceous; angular white feldspar grains scattered
through the matrix and visible under the microscope.
Sub-Graywacke
Graywacke
e
51
Sub-Graywackes owe their better sorting to deposition by streams or normal marine currents.
Many of the production environments PALADIN serves where sands are the primary pay zones
are of this type. This sandstone is light to medium gray or brown; speckled and micaceous.
Arkose
Arkoses are derived from the
disintegrations of granite and
granite gneisses, and because
they are composed of quartz and
feldspar they resemble granites,
but the angular, fragmental
nature of the grains serves to
distinguish arkose from the
closely interlocking igneous
texture of granite. Arkoses occur
above uniformities in the
immediate vicinity of granitic
Sub-Graywacke
Arkose Sand
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terrains, or in thick deposits associated with conglomerates (containing granite boulders)
derived from granites or gneisses. The production zones within the Granite Wash of the Texas
Panhandle are of this type. The Arkose is usually gray, pink, or red in color; commonly
micaceous with angular chips of granite and feldspar visible with the microscope. These are
commonly coarse grained sandstones.
All three of these sandstone types are derived from a high and rising source area and are
deposited in a subsiding basin. A good example would be the river sediments from the Rocky
Mountains flowing into the Rio Grande and then deposited in the Gulf of Mexico.
The following rock types differ considerably from the previous set. Therefore we need a new
legend to assist in defining the constituents of this material.
The source and depositional area of quartz sandstone is closely associated with limestone.
Clastic and chemical constituents deposited as sediments are enclosed with dashed lines.
Vertical arrows indicate chemical constituents precipitated from solution, horizontal arrows
indicate marine currents. Sand-sized skeletal fragments compose the dunes, which are formed
by marine currents in a water depth of 15-25 feet. Little shale is deposited in any of these three
environments. All of these diagrams should be taken as generalities for the sake of a basic
introduction to sedimentary environments as seen by PALADIN logging operations.
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Quartz Sandstone
Quartz sandstones undergo a long reworking by the
surf and/or wind during which most of the feldspar is
destroyed and the quartz grains are rounded. These
sands are derived from a low source region and
deposited into a slowly subsiding basin. These
sandstones are light colored (white, yellow, or red);
not micaceous, with rounded quartz grains visible
under the microscope.
Limestone Most Limestones are clastic, composed of skeletal fragments of marine organisms, of lumps of
aggregation of calcareous silt on the sea floor, or of rounded carbonate grains called ooids.
Some Limestones have a very finely crystalline texture and were probably deposited in quiet
water as a lime mud. A good example of this can be seen in wells drilled in the near shore Gulf
of Mexico. These appear as a white mushy material under the microscope that will dissolve
completely in 10% HCL.
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Other types of Limestone are a combination of Dolomite, MgCO3, and Limestone CaC03, These
are called Dolostones. These rocks have a smooth appearance and will effervesce much slower
than Limestone but faster than pure Dolomite.
Under close inspection Carbonates
that appear to have spherical bodies
of carbonate called ooids,
pronounced OH oids, the rock is a
clastic limestone. Many clastic
limestones are composed of
fragments of fossil hard parts
cemented together with clear
crystalline calcite. The calcite will
sparkle if turned under the strong
light of the microscope. Those rocks
that have no evidence of clastic
material are simple termed limestone or dolostone.
Evaporites I have included the evaporates, not
as a hydrocarbon reservoir but for
explanation purposes since
PALADIN logging crews see so much
of this material. Salt, Gypsum,
Anhydrite are the most common of
the Evaporites. They occur as
crystalline forms and are purely
chemical substances that are
precipitated from water either
chemically or by organisms. These
rocks have been deposited in the
vicinity of rising land masses which would have contaminated the original sediment with mud
or sand. Salt and gypsum are deposited in restricted marine basins under an arid or semi-arid
environment. Sea water must evaporate about 1/5 of its original volume before gypsum will
precipitate.
Anhydrite
Limestone
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Common Sedimentary Rocks Shale - compacted clays. If they contain
quartz grains they are usually referred to as
sandy or arenaceous, while those containing
calcium carbonate are often called limey or
calcareous. Those containing large amounts of
organic matter are carbonaceous.
Carbonaceous shale are usually black and
some grade into lignite or coal. Shale grades
into siltstones and sandstones in the direction of the shoreline and into limestone seaward.
Breccia - a rock composed of the cemented angular fragments of other rocks. This type of rock
is very common along a fault zone. They sometimes grade into conglomerates when the
fragments are slightly rounded. Breccias are deposited very near their source; when the
fragments of which they are composed are carried a greater distance from the source, the
fragments are rounded through wear and a conglomerate results.
Conglomerate – like a breccia, is made up of cemented rock fragments but is distinguished
by its coarse, rounded fragments. The reason for this is that conglomerates are formed a
greater distance from the source rock than the breccia; thus, the fragments are rounded
Haynesville Shale
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through wear. Conglomerates are necessarily younger than the fragments of which they are
composed.
Chalk – is a special type of limestone; it is composed mainly of small shells and fragments
cemented together. Foraminifer’s shells constitute a large part of the material, but the
presence of shells or other organisms is common. Chalk is usually a soft, porous and white or
gray.
Marl – is formed when masses of shells and shell fragments accumulate on the bottom of a
fresh water lake. Marl is also the term used to describe calcareous shale in which clay and finely
divided particles of calcium carbonate are mixed. The name Marl is meant to include varying
compositions in different parts of the world.
Reef – is a type of limestone formed by fossilized corals and associated marine life. The
skeletal features of the organisms from which they are formed characterize these limestones.
Reefs are formed in tropical waters along the shore of landmasses and around islands. They are
probably formed in all of the ancient inlands seas of North America.
Coquina – a term usually applied to recent deposits of cemented shell accumulations.
Coal – Coal is formed by the compacting and partial decomposition of vegetable
accumulations. The alteration of vegetation into peat, lignite, and various other grades of coal
is a long process. The grade of coal is dependent upon the kind of material deposits and the
amount of alteration that has taken place.
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Glauconite - Glauconite is known to occur in flakes and as pigmentary materials. When used
in the morphological sense, the term
glauconite often refers to small, green,
spherical, earthy pellets. Some of these
pelletal varieties are composed solely of
the mineral described above, others are a
mixed-layer association of this mineral and
other three-layer structures.
Glauconite forms during marine
diagenesis, in relatively shallow water, and at times of slow or negative deposition. Glauconite
has been identified in both recent and ancient sediments. It is a major component in some
“greensand” deposits and has been used commercially for the extraction of potassium from
such sources.
Chert - A hard, dense rock of fine-grained silica. Chert is characterized by a dull and a splintery
to fracture, and is most commonly gray, black, reddish brown, or green. The term chert,
however, is preferred for the nodular deposits. Novaculite is a white chert of great purity and
uniform grain size, and is composed
chiefly of quartz; the term is mostly
restricted to descriptions of Paleozoic
cherts in Oklahoma and Arkansas, two
areas of interest to PALADIN.
Chert occurs mainly in three forms:
bedded sequences, nodular, and
massive. Bedded chert (called ribbon
chert if beds show pinch-and-swell
structure) consists of rhythmically interlayered beds of chert and shale; chert and carbonates;
or in some other types of formations. stratigraphically and cover areas of hundreds of square
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miles. When a supply of silica is available, chert forms in four ways: by replacement of mainly
carbonate rock; by deposition from turbidity currents composed primarily of biogenic silica; by
increasing the deposition of silica relative to terrigenous input, commonly by increased
productivity of biogenic silica; and by precipitation of silica from water under either
hydrothermal or low-temperature hyper-saline conditions.
Photomicrographs of Common Sediments
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Fossil
60
61
Mica LCM
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Pyritic Cement
63
Salt & Pepper Sand
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Tight Sand
Siltstone w/bedding plane
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LAG Determination We have provided a basic understanding of the type and occurrence of Sedimentary rock that
are common in drilling operations. Now we must consider those factors that are specific to the
environment we work in. Paramount to evaluation of lithology or gas in a drilling operation is
the understanding of how and WHEN material from a specific formation reaches the surface for
collection and testing. This process is referred to as LAG. LAG defines the length of time taken
to circulate a sample from a point in the well bore to the surface. Normally we need to know
the time and pump strokes to circulate cuttings or gas from the bit to the surface.
LAG Concept and Calculation
In order to understand LAG we must first understand the well bore. The geometry of the well
bore is key.
Annulus – Geometry of space occupied between any open hole, casing and the drill string in or out of the wellbore.
Annular Volume – The volume of the annulus in oilfield barrels (42 gallons US = 1 bbl) with or without the drill string in the wellbore.
Lag Methods
There are three methods that allow for the determination of lag
Connection Gas / Trip Gas
Carbide Bomb
Formula
CONNECTION GAS: …increase in gas that is caused after a connection is
made. When a connection is made, a new section of pipe is added to the
drill string. The circulation of the mud stops, allowing gas to accumulate in
the annulus. When circulating starts again, these bubbles rise to the
A
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surface and are read by our hotwire. Measuring the length of time from the point when the
circulation is restarted, connection depth, after making a connection to when the connection
gas is recorded by our hotwire is considered to be an accurate way to determine lag time. This
method assumes that the mud weight is near balanced with formation pressure. If the mud
weight is much higher that the formation pressure, no connection gas will be seen.
CARBIDE BOMB:. Carbide is a substance that produces a gas that can be detected by our
hotwire. Carbide gives off this gas when it comes into contact with water. The term “Carbide
bomb” comes from the way we prepare the carbide for the test. We have to make a package
that will keep the Carbide together as long as possible so that the gas that is formed by it is
sufficient enough to be read by out hotwire. We put a handful of Carbide in a paper towel and
then fold the towel around it so that it will fit in the middle of the drill pipe. We use a rubber
band to hold the paper towel in place. During a connection you can place the package in the
drill pipe and measure the time from when the circulation was started to when you read gas, be
sure to subtract the time it takes for the package to travel down the drill pipe. This is a very
efficient way to determine your actual lag time.
THE FORMULA FOR LAG: The formula is a mathematical way to figure the estimated lag. It
takes into consideration the size of the drill pipe, the length of pipe in the hole, and many other
parameters. The number the formula produces is usually very close to the actual lag time. The
only reason the formula can’t be 100% accurate is because we can’t know exactly how big the
hole is. As the hole is drilled, the walls cave in which changes the size of the hole. The only time
the formula produces the exact lag time is when there is no open hole to factor in. The formula
for lag is in the back of this manual.
Calculating Annular Volume To calculate the Annular Volume, it helps to construct a basic wellbore geometry diagram detailing the
lengths (depths), and the inside and outside diameters of each component of the wellbore.
These would include:
1. Surface and intermediate casings.
2. Liner (set near bottom and inside last casing).
3. Open Hole (the exposed rock below casing).
4. Type, grade, size and weight/foot of the string of drill pipe and bottom hole assembly.
Annular Volume in BBl.s of Segment = .0009718 * (ID² - OD²) * Length of Segment Where: ID = the inside diameter in inches (of open hole or casing) OD = the outside diameter in inches (of drill pipe or drill collars)
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(0.9718) = the constant for converting cubic inches into cubic feet and cubic feet into oilfield barrels of volume per linear foot of wellbore. Length of Segment = length of the drill string segment in feet. Annular Volume Calculation Example OD of drill pipe = 5 inches ID of casing = 13.625 inches Length = 1500 Using the above formula:
= (0.9718 *(13.625² - 5²) * 1500)/1000 = 234 bbls After having gone through this calculation we clearly do not know how much time it will take to get bottoms up, time from depth of interest to the surface. Now we need to know specific pump information in order to determine lag time.
Pump Output First, we need to know what the output of the mud pumps are, in barrels per stroke. By knowing the
pump output and how many strokes per minute, we can calculate the Lag. We need to know the
number of liners (either two in a duplex or three in a triplex pump), the diameter and stroke length of
the pump liner, and the pump efficiency (usually 92% - 95%) in order to obtain the pump output. The
personnel on the rig that have this information are the drilling supervisor, tool pusher, driller, derrick
hand, and the mud engineer.
Example: Triplex Pump (3 liners), Pump Efficiency = 95%, Pump Liner = 6.5”
diameter, Pump Stroke Length is 14”.
To calculate the output in bbl/stroke we have:
Tri-Plex Pump (3 pistons)
PO = (number of liners)*(pump efficiency)*(liner ID²)*(0.0009718)*(stroke length, in feet)
PO= (3)*(0.95)*(6.5²)*(1.167)*(0.0009718)
= (3)*(0.95)*(42.25)*(1.167)*(0.0009718)
PO= 0.137 bbl/stk Duplex Pump (2 pistons)
Note: Typically, most triplex pumps have a 12” stroke. Rare, oddball liners and stroke lengths will be encountered. This is why the 14” example stroke length is provided. In the event you have a typical triplex pump with a 12” stroke length, in the formula above, converting 12” in feet = 1 ft. squared is still
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1, therefore that number is not needed in the equation. In the event you have one of the rare pumps mentioned above, you will have the tools to figure your own pump output values.
Calculating the Sample Lag Now that we know the annular volume and the pump output in bbl/stk we can calculate the
amount of strokes and time it will take for the LAG.
LAG Strokes = Annular Volume (bbls) / Pump Output (bbls/stroke)
Example: Annular Volume = 1354 bbls Pump Output = 0.1591 bbl/stk Strokes (bit to surface) = 1354 bbl / 0.1591 bbl/stk = 8509 strokes To convert this to time, we have…. Pumps stroking at 100 stokes / minute
LAG Minutes = total strokes / total strokes per minute If the pump is pumping at 100 strokes per minute converted to time, we have: 95.09 min. = 8509 strokes / 100 strokes per minute
Sometimes there will be two pumps on the hole while drilling on surface where larger wellbores require
more lifting capacity of the drilled solids to surface. So with two pumps on the hole, you have to divide
the Annular Volume by the total strokes per minute for both pumps. Make sure that both pump output
values are calculated correctly for each pump. It is very common to have one pump with a smaller or
larger liner than the other.
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Lithology Description and
Hydrocarbon Analysis
Sample Preparation
Many factors influence the type and quality of the samples we are able to retrieve from the
well bore. Unfortunately this limits our ability to provide quantifiable data to our customers.
Understanding these limitations is important to providing the best service possible.
Sample Quality
The accuracy of the sample descriptions on a mud log are generally the direct measure of the quality of the samples. Clean, good quality samples are usually the exception rather than the rule. The logging technician must use his experience and knowledge of the area when interpreting samples, especially those caught by the drilling rig personnel. Sample quality is affected by:
Mud Viscosity
Viscosity is the ability of the drilling mud to flow. Water has a viscosity of 28. Drilling crews like to have a 28 viscosity because they can “make more hole” or drill faster. However, water does not carry samples back to the surface very well, so they have to pump “sweeps” every so often to clean the hole of drill cuttings. When that happens, you will get everything in the samples (large cavings, metal, pieces of rubber, pipe dope, etc.). You will get acceptable samples with a 35 viscosity, much better with a 50 or 60 viscosity.
Sample Collection
As the drilling mud carries the samples out of the hole, the flow of mud is discharged over a set of screens in the shale shaker that separates the drill cuttings and dumps them into a shale pit behind the shaker. Samples can be caught directly off the screen and is the best method when trying to catch a specific sample from a zone of interest.
The following images will provide an explanation of the role of the shaker in the sample collection process. You will also be shown both how and where samples should be collected.
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When catching samples on a “one-man” logging jobs, the drilling crews are responsible for catching the samples. However, it is our responsibility to see that the samples are caught correctly and on time. They will not understand lagged samples, so they usually catch them as 10 to 30 foot intervals are drilled. You always have to mentally lag the samples when writing descriptions. Oftentimes, the sample catcher will get busy with other duties and forget to catch the samples. When that happens, he may use the same batch of cuttings and fill 50 or 100 feet of sample bags and you will have the same samples over the entire interval. During “zones of interest” make sure that you are there to supervise sample catching.
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Screening and Cleaning of Sample
Large pieces of rock in samples are usually cavings from up-hole. Samples should be screened through a 10 mesh sieve before attempting to interpret them. Sand grains can actually fall through the 80 mesh sieve. When you are having difficulty finding sand in the samples, wash
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through the sieves and into a large pan or bucket. Very fine sand grains may be found in the container.
Washing Samples
There are different ways to wash samples. First it depends on whether the mud is water-based or oil-based. Either way, take care not to wash the samples too harshly.
WATER-BASED MUD: Most wells use water-based mud and washing the samples with rig water either inside the trailer or out by the shaker works fine. If you don’t have water hooked up to the trailer, put your sample in a 5-gallon bucket and fill it up a little with water from a rig hose or jug. Gently swirl bucket and pour the water slowly out leaving the sample at the bottom. Most rig hands that catch samples for you do it this way. If you have water hooked up to the trailer, you can wash the samples inside the trailer sink while using the sieve to sort the sample.
OIL-BASED MUD: When the rig is using oil-based mud, the samples get washed outside the trailer in a special sink that uses diesel fuel. PVC gloves are required for this. The samples are dried outside the trailer as well since samples from oil based mud smoke a lot as they are drying.
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Preparing Samples
THE SIEVE: We use the sieve to separate the big rocks from the small rocks in the sample. The small rocks are important because they are more likely to be coming from the bottom of the well rather than falling into the mud from the walls above the bit. Usually the small rocks in a sample are referred to as being “cuttings” as if to say they were “cut” by the bit, versus the larger rocks being called “slough” (pronounced sluff) as if they had fallen into the mud from the walls above the bit.
Once the sample is sifted through the sieve, lift the upper tray of the sieve off and run some water over the smaller rocks one last time to wash any remaining mud away.
Place a small spoonful of the sample in a steel tray for examining under the fluoroscope and microscope.
Place a small spoonful in a black plastic tray for quick reference later on.
Place several tablespoons of sample in a steel tray for drying and storing.
USING THE STAINLESS STEEL TRAY FOR EXAMINING SAMPLES
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Spoon out a small amount of the sample and place some on a stainless steel tray. Add a small amount of water and shake the tray to spread the cuttings evenly across the bottom. Pour off the excess water slowly. You can use a paper towel to soak up any extra water, or you can lean the tray against the wall with the smaller opening standing on a sponge.
Stainless Steel Sample Tray
USING THE BLACK PLASTIC TRAYS
In addition to using the steel trays, spoon a small amount (just enough to coat the bottom of the tray) into one of the chambers of the black plastic trays.
These trays are necessary for seeing many samples at one glance. The trays usually have ten compartments but some have less.
Label the trays so that you can keep track of the depths of the samples. Many of the trays already have masking tape on one end with various numbers. You can peel off those labels and re-label them yourself, or if the trays are labeled the way you like, leave them.
If you have ten black trays with ten compartments each you can label them 000, 100, 200, 300, and so on to 900, so you won’t have to re-label them each time you drill a thousand feet. For instance, let’s say you started filling the trays at 10,000 and now you are at 10,990’ and you just filled the last compartment on the “900” tray, just empty the “000” tray and it’s ready for the sample’s for 11,000 to 11,100. When you get to 11,200’, empty the “200” tray. You’ll be able to look at all the samples you have for the last thousand feet. If you do not have ten trays, just use all you have and re-label them as needed.
You’ll be able to see formation changes easier by using the black plastic trays. You can also slide the trays under the microscope and see the changes between the samples up close. If the geologist should happen to visit the trailer, these black trays provide easy access to the samples.
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Three ten-compartment trays side by side. Put masking tape on one end for labeling.
DRYING
There are two methods you can use to dry samples. Heat dry, (using the lamps) or air dry, (setting the samples out on the table or outside to dry slowly). Sometimes the oil company that hired us specifically asks us to air-dry the samples because heat-drying can burn up some
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possible gasses or oil still left in the cuttings. Air-drying is recommended when needing to examine dry samples in the fluoroscope and under the microscope.
NOTE: Looking at these samples when they are wet and then again when they dry gives you a better ability to accurately describe the sample.
CAUTION: When heat- drying, be sure to use the stainless steel trays and also understand that these trays get very hot and need time to cool before you touch them. You can use pliers or the sample tweezers to move the trays around while they are hot.
SAMPLE DESCRIPTIONS
Abbreviations
Abbreviations should be used for all descriptions recorded in the sample description column of the mud log. All sample descriptions are required to be done in upper case letters.
Order of Written Description
A standard order is required. This is done to build consistency within the company and readability by our customers. It also saves time obtaining specific information from descriptions. The standard order is beginning with the highest rock percentage:
Rock Type
Rock Percentage
Classification
Color
Hardness
Texture
Cement
Fossils and other accessories
Porosity
Staining
Fluorescence
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Cut
Examples of sample descriptions:
LS 60%: ool grst, brn, med & crs xln, arg, brach foss, glauc, gd intpar por, gd tn stn, bite yel fluor, gd strmg cut, gd thick tn ring stn when dry.
SS 40% : lithic, buff to wh, fn & med gr, fr sortg, ang, sli arg, embd fn mica & sh prtgs, fr lntgran poros, gd tn to lt brn stn, gd brite yel fluor, gd mlky/dif cut, thick lt brn ring stn when dry.
NOTE: These descriptions represent the standard format to be used on all logs unless specifically defined by the client.
Color
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Color of rocks may be a mass effect of the colors of the constituent grains, or result from the color of cement or matrix, or staining of these. Colors may occur in combinations and patterns, e.g., mottled, banded, spotted, variegated. It is recommended that colors be described on wet samples under ten-power magnification. It is important to use the same source of light all of the time and to use constant magnification for all routine logging.
Ferruginous, carbonaceous, siliceous, and calcareous materials are the most important staining or coloring agents. From limonite or hematite come yellow, red, or brown shades. Gray to black color can result from the presence of carbonaceous or phosphatic material, iron sulfide, or manganese. Glauconite, ferrous iron, serpentine, chlorite, and epidote impart green coloring. Red or orange mottlings are derived from surface weathering or subsurface oxidation by the action of circulating waters.
The colors of cuttings may be altered, after the samples are caught, by oxidation caused by storage in a damp place, insufficient drying after washing, or by overheating. Bit or pipe fragments in samples can rust and stain the samples. Drilling mud additives may also cause staining.
Texture
Texture is a function of the size, shape, and arrangement of the component elements of a rock.
1) Grain or crystal sizes. Size grades and sorting of sediments are important attributes. They have a direct bearing on porosity and permeability and may be a reflection of the environment in which sediment was deposited. Grain and crystal size classifications should be made using a standard film comparator. This comparator is small and handy and can be placed on top of, or adjacent to, cuttings in a sample tray so that a direct visual comparison of grain sizes can be made. Lower fine is designated by underlining (f)
2) Shape. Shape of grains has long been used to decipher the history of a deposit of which the grains are part. Shape involves both sphericity and roundness.
Angular — edges and corners sharp; little or no evidence of wear.
Subangular — faces untouched but edges and corners rounded.
Subrounded - edges and corners rounded to smooth curves; areas
of original faces reduced.
Rounded -original faces almost completely destroyed, but some comparatively flat faces may
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be present; all original
edges and corners smoothed off to rather broad curves.
Well-rounded - no original faces, edges, or corners remain; entire surface consists of broad curves, flat areas are absent.
3) Sorting. Sorting is a measure of dispersion of the size frequency distribution of grains in a sediment or rock. It involves shape, roundness, specific gravity, and mineral composition as well as size. A classification given by Payne (1942) that can be applied to these factors is:
Good: 1 or 2 size classes
Fair: 3 or 4 size classes
Poor: 5 or more size classes
Unconsolidated Sample Types
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Unconsolidated Angular Unconsolidated Sub-Angular
Unconsolidated Sub-Rounded
Cement and Matrix
Cement is a chemical precipitate deposited around the grains and in the interstices of a
sediment as aggregates of crystals or as growths on grains of the same composition. Matrix consists of small individual grains that fill interstices between the larger grains. Cement is deposited chemically and matrix mechanically.
The order of precipitation of cement depends on the type of solution, number of ions in solution and the general geochemical environment. Several different cements, or generations
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of cement, may occur in a given rock, separately or overgrown on or replacing one another. Chemical cement is uncommon in sandstones that have a clay matrix. The most common cementing materials are silica and calcite.
Fossils and Accessories
Microfossils and some small macrofossils, or even fragments of fossils, are used for correlation and may also be environment indicators. For aid in correlation, anyone making sample logs should familiarize himself with at least a few diagnostic fossils. An excellent reference for the identification of the more common macrofossils is “Recognition of Invertebrate Fossil Fragments in Rocks and Thin Sections”, by 0. P. Majewske (1969). Fossils may aid the sample examiner in judging what part of the cuttings is in place and what part is caved. For example, in the Gulf Coast region, fresh, shiny foraminifera, especially with buff or white color, are usually confined to Tertiary beds; their occurrence in samples from any depth below the top of the Cretaceous is an indication of the presence of caved material. It would be helpful for each sample-logger to have available one or more slides or photographs illustrating the principal microfossils which might be expected to occur in each formation he will be logging.
Accessory constituents, although constituting only a minor percentage of the bulk of a rock, may be significant indicators of environment of deposition, as well as clues to correlation. The most common accessories are glauconite, pyrite, feldspar, mica, siderite, carbonized plant remains, heavy minerals, chert, and sand—sized rock fragments.
Rock and Mineral Identification
Dilute HCL test for carbonates.
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There are at least four types of observations to be made on the results of treatment with acid:
1) Degree of effervescence: limestone (calcite) reacts immediately and rapidly, dolomite slowly, unless in finely divided form (e.g., along a newly made scratch). While the effervescence test cannot yield the precision of chemical analysis or X-ray, it is generally adequate for routine examination. Unless the sample is clean, however, carbonate dust may give an immediate reaction that will stop quickly if the particle is dolomite. Impurities slow the reaction, but these can be detected in residues. Oil-stained limestones are often mistaken for dolomites because the oil coating the rock surface prevents acid from reacting immediately with CaCO3, and a delayed reaction occurs. The shape, porosity, and permeability will affect the degree of reaction because the greater the exposed surface, the more quickly will the reaction be completed.
2) Nature of residue: carbonate rocks may contain significant percentages of chert, anhydrite, sand, silt, or argillaceous materials that are not readily detected in the untreated rock fragments. Not all argillaceous material is dark colored, and, unless an insoluble residue is obtained, light colored argillaceous material is generally missed. During the course of normal sample examination in carbonate sequences, determine the composition of the non-calcareous fraction by digesting one or more rock fragments in acid and estimate the percentage of insoluble residue. These residues may reveal the presence of significant accessory minerals that might otherwise be masked.
Oil reaction: if oil is present in a cutting, large bubbles will form on a fragment when it is immersed in dilute acid.
Etching: etching a carbonate rock surface with acid yields valuable information concerning the texture, grain size, distribution and nature of noncarbonate minerals, and other lithologic features of the rock. This is a laboratory procedure and is not done in the field.
Hardness
Scratching the rock fragment surface is often an adequate way of distinguishing different lithic types. Silicates and silicified materials, for example, cannot be scratched, but instead will take a streak of metal from the point of a probe. Limestone and dolomite can be scratched readily; gypsum and anhydrite will be grooved, as will shale or bentonite. Weathered chert is often soft enough to be readily scratched, and its lack of reaction with acid will distinguish it from carbonates. Caution must be used with this test in determining whether the scratched material is actually the framework constituent or the cementing or matrix constituent. For example, silts will often scratch or groove, but examination under high magnification will usually show that the quartz grains have been pushed aside and are unscratched, and the groove was made in the softer matrix material.
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Parting
Shaly parting, although not a test, is an important rock character. The sample logger should always distinguish between shale, which exhibits parting or fissility, and mudstone, which yields fragments which do not have parallel plane faces.
Slaking and Swelling
Marked slaking and swelling in water is characteristic of montmorillonite (a major constituent of bentonite) and distinguishes them from kaolin and illite. Some sandstones have water sensitive clays as matrix materials. High water loss drilling mud will cause these clays to swell and close off porosity and permeability. Clay identification is a very important aspect of our work.
Staining Technique for Carbonate Rocks
The distinction between calcite and dolomite is often quite important in studies of carbonate rocks. For many years several organic and inorganic stains have been used for this purpose, but with varying degrees of success.
Friedman (1959) investigated a great variety of stains for use in identifying carbonate minerals, he developed a system of stains and flow charts for this purpose. These vary in ease of application, but most are not practical for routine sample examination. The reader is referred to Friedman’s paper for an extensive discussion of carbonate mineral stains.
One stain that is applicable to routine sample examination being that is both simple and rapid, is Alizarin Red S. This stain can be used on any type of rock specimen, and it has proved especially useful in the examination of cuttings. The reactions to acid of chips of dolomitic limestone or calcareous dolomite are often misleading, and the rapid examination of etched chips does not always clearly show the calcite and dolomite relationships. Alizarin Red S shows clearly the mineral distribution. Calcite takes on a deep red color; other minerals are uncolored.
The figure that follows will provide a good procedure for using Alizarin Red to identify specific types of mineralogy in your samples.
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Alizarin Red coupled with Sodium Hydroxide, NaOH, is a good tool to use in identifying some specific rock types.
Tests for Specific Rocks and Minerals
Clays: Shales and clays occur in a broad spectrum of colors, mineral composition, and textures. Generally, their identification is done with ease; however, light colored clay is commonly mistaken for finely divided anhydrite. The two may be distinguished by a simple test.
Anhydrite will dissolve in hot dilute hydrochloric acid and, when cooled, will recrystallize out of solution as acicular needles. Clay remains insoluble in the hot dilute acid.
Anhydrite and gypsum are usually readily detected in cuttings. Anhydrite is more commonly associated with dolomites than with limestones, and is much more abundant in the subsurface than gypsum. At present, there appears to be little reason to distinguish anhydrite from gypsum in samples. Anhydrite is generally harder and has a pseudo—cubic cleavage; the cleavage flakes of gypsum have “swallow—tail” twins. Anhydrite can be readily recognized in thin sections by its pseudo—cubic cleavage, and, under polarized light, by its bright interference colors.
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The dilute hydrochloric acid test referred to above is a valid and simple test for anhydrite or gypsum in cuttings. Place the cutting(s) in dimple dish and cover with acid. Heat on a hot plate to 250°F ±(120 C ±) and wait for the sample to start dissolving. If anhydrite or gypsum is present, acicular gypsum crystals will form around the edge of the acid solution as it evaporates. If the sample contains much carbonate, a calcium chloride paste may form and obscure the acicular gypsum crystals. Dilute the residue with water, extract and discard the solution and repeat the test.
Salts are rarely found at the surface and generally do not occur in well samples. Unless salt—saturation or oil—base mud is used, salt fragments or crystals dissolve before reaching the surface. The best criteria for detecting a salt section are: (a) the occurrence of “salt hoppers” (molds of dissolved salt crystals in other rock fragments), (b) marked increase in salinity of the drilling mud, (c) a sudden influx of abundant caved material in the samples, (d) a sharp increase in drilling penetration rate, and (e) mechanical log character, particularly the sonic, density, and caliper logs. Cores are the most direct method of determining whether salt is present, but they are not usually cut in salt sections.
Salts are commonly associated with cyclical carbonate sections and massive red bed sequences. In the former, they are usually thin bedded and often occur above anhydrite beds. Potassium—rich salts, the last phase of an evaporation cycle, are characterized by their high response on gamma ray log curves.
Siderite is usually readily distinguished by its characteristic brown color and slow rate of effervescence with dilute HCL. The mineral often occurs as buckshot—sized pellets.
Ankerite is an iron mineral that is very difficult to distinguish without the aid of a stain such as Potassium Cyanide which turns the mineral an aquamarine color. It will react similar to dolomite in HCL acid.
Feldspar: The presence, quantity and type of feldspar constituents can be important in the study of reservoir parameters in some sandstone, particularly the coarse arkosic sands or “granite washes.”
Bituminous Rocks: Dark shales and carbonates may contain organic matter in the form of kerogen or bitumen. Carbonates and shales in which the presence of bituminous matter is suspected should be examined by thin section and pyrolysis—fluorometer methods for possible source rock qualities. Dark, bituminous shales have a characteristic chocolate brown streak, which is very distinctive.
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Hydrocarbon Analysis
The recognition and evaluation of hydrocarbons present in well samples is another of the more important responsibilities of the logging technician. He should be familiar with the various methods of testing for and detecting hydrocarbons that are outlined in the next section, and should use them frequently in the course of routine sample examinations. Cuttings with good porosity should always be tested for hydrocarbons.
Although petrophysical analyses may give a conclusive determination of the presence of commercial quantities of oil, it is the loggers’s responsibility to report and log all shows, and to see that good shows are evaluated. Positive indications of hydrocarbons in cuttings can be a decisive factor in the petrophysicist’s evaluation of a well.
Unfortunately, no specific criteria can be established as positive indications of whether or not a show represents a potentially productive interval. The color and intensity of stain, fluorescence, cut, cut fluorescence and residual cut fluorescence will vary with the specific chemical, physical, and biologic properties of each hydrocarbon accumulation. The aging of the shows (highly volatile fractions dissipate quickly), and flushing by drilling fluids or in the course of sample washing, also tend to mask or eliminate evidence of hydrocarbons. The presence or absence of obvious shows cannot always be taken as conclusive. In many cases, the only suggestion of the presence of hydrocarbon may be a positive cut fluorescence. In other cases, only one or two of the other tests may be positive. Hence, when the presence of hydrocarbons is suspected, it is very important that all aspects be considered. Listed below are some of the most common methods of testing for hydrocarbons in samples and cores that should be used by the geologist during routine sample examination.
Routine Hydrocarbon Detection Methods
Odor may range from heavy, characteristic of low gravity oil, to light and penetrating, as for condensate. Some dry gases have no odor. Strength of odor depends on several factors, including size of sample. Describe as oil odor or condensate odor. Depending on strength of odor detected, report as good, fair, or faint, in remarks column. Faint odors may be detected more easily on a freshly broken surface or after confining the sample in a bottle for 15-20 minutes.
Staining & Bleeding: The amount by which cuttings and cores will be flushed on their way to the surface is largely a function of their permeability. In very permeable rocks only very small amounts of oil are retained in the cuttings. Often bleeding oil and gas may be observed in cores, and sometimes in drill cuttings, from relatively tight formations.
The amount of oil staining on ditch cuttings and cores is primarily a function of the distribution of the porosity and the oil distribution within the pores. The color of the stain is related to oil gravity; heavy oil stains tend to be a dark brown, while light oil stains tend to be colorless.
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The color of the stain or bleeding oil should be reported. Ferruginous or other mineral stain may be recognized by lack of odor, fluorescence, or cut.
Reaction in Acid of Oil-Bearing Rock Fragments: Dilute HCL may be used to detect oil shows in cuttings, even in samples that have been stored for many years. This is effected by immersing a small fragment of the rock to be tested (approximately 1/2 to 2 mm diameter) in dilute HCL. If oil is present in the rock, surface tension will cause large bubbles to form, either from air in the pore spaces or from CO2 generated by the reaction of the acid with carbonate cement or matrix. In the case of calcareous rock, the reaction forms lasting iridescent bubbles large enough to raise the rock fragment off the bottom of the container in which the acid is held, and sometimes even large enough to carry the fragment to the surface of the acid before the bubbles break and the fragment sinks, only to be buoyed up again by new bubbles. The resulting bobbing effect is quite diagnostic. The bubbles, which form on the surface of a cutting fragment of similar size that contains no oil, do not become large enough to float the fragment before they break away, and the fragment, therefore, remains on the bottom. In the case of oil-bearing non-calcareous sandstone, large lasting bubbles form on the surface but may not float the fragment. The large bubbles result from the surface tension caused by the oil in the sample, which tends to form a tougher and more elastic bubble wall.
It should be pointed out that this test is very sensitive to the slightest amount of hydrocarbons, even such as found in carbonaceous shale; therefore, it is well to discount the importance of a positive test unless the bobbing effect is clearly evident or lasting iridescent bubbles are observed. The test is very useful, however, as a simple and rapid preliminary check for the presence of hydrocarbons. A positive oil-acid reaction alerts the observer to intervals worthy of more exhaustive testing.
Fluorescence: NOTE: Do not dry samples that will be used under the fluoroscope. This can destroy the hydrocarbon. Examination of mud, drill cuttings and cores for hydrocarbon fluorescence under ultraviolet light often indicates oil in small amounts, or oil of light color which might not be detected by other means. All samples should be so examined. Color of fluorescence of crudes ranges from brown through green, gold, blue, yellow, to white; in most instances, the heavier oils have darker fluorescence. Distribution may be even, spotted, or mottled, as for stain intensity range is bright, dull, pale, and faint. Pinpoint. The fluorescence is associated with individual sand grains and may indicate condensate or gas. Mineral fluorescence, especially from shell fragments, may be mistaken for oil fluorescence, and is distinguished by adding a few drops of a solvent. Hydrocarbon fluorescence will appear to flow and diffuse in the solvent as the oil dissolves, whereas mineral fluorescence will remain undisturbed.
Reagent Cut Tests: Oil-stained samples, which are old, may not fluoresce; thus failure to fluoresce should not be taken as decisive evidence of lack of hydrocarbons. All samples suspected of containing hydrocarbons should be treated with a reagent. The most common reagents used by the geologist is lighter fluid. This reagent is available at most stores and will give satisfactory results.
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To test cuttings or cores, place a few chips in a white porcelain-evaporating dish or spot plate and cover with reagent. The sample should be dried thoroughly at low temperature; otherwise water within the sample may prevent penetration by the reagents, thus obstructing decisive results. The hydrocarbon extracted by the reagent is called a “cut.” It is observed under normal light and should be described on the basis of the shade of the coloration, which will range from dark brown to no visible tint.
A faint “residual cut” is sometimes discernable only as an amber—colored ring left on the dish after complete evaporation of the reagent. A very faint cut will leave a very faint ring, and a negative cut will leave no visible color. The shade of the cut depends upon the gravity of the crude, the lightest crudes giving the palest cuts; therefore, the relative darkness should not be taken as an indication of the amount of hydrocarbon present. A complete range of cut colors varies from colorless, pale straw, straw, dark straw, light amber, amber, very dark brown to dark brown opaque.
The most reliable test for hydrocarbons is the “cut fluorescence” or “wet cut” test. In this test the effect of the reagent on the sample is observed under ultraviolet light, along with a sample of the pure solvent as control. The sample should be thoroughly dried before applying the reagent. If hydrocarbons are present, fluorescent “streamers” will be emitted from the sample and the test is evaluated by the intensity and color of these streamers. Some shows will not give a noticeable streaming effect but will leave a fluorescent ring or residue in the dish after the reagent has evaporated. This is termed a “residual cut.”
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It is recommended that the “cut fluorescence” test be made on all intervals in which there is even the slightest suspicion of the presence of hydrocarbons. Samples that may not give a positive cut or will not fluoresce may give positive “cut fluorescence.” This is commonly true of the high gravity hydrocarbons that give a bright yellow “cut fluorescence.” Distillates show little or no fluorescence or cut but commonly give positive “cut fluorescence,” although numerous extractions may be required before it is apparent.
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Generally low gravity oils will not fluoresce but will cut a very dark brown and their “cut fluorescence” may range from milky white to dark orange.
An alternate method involves picking out a number of fragments and dropping them into a clear one—or two—ounce bottle. Petroleum ether, chlorothene, or acetone is poured in until the bottle is about half full. It is then stoppered and shaken. Any oil present in the sample is thus extracted and will color the solvent. When the color of the cut is very light, it may be
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necessary to hold the bottle against a white background to detect it. If there is only a slight cut, it may come to rest as a colored cap or meniscus on the top surface of the solvent.
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Wettability: Failure of samples to wet, or their tendency to float on water when immersed, is often an indication of the presence of oil. Under the microscope, a light—colored stain that cannot be definitely identified as an oil stain may be tested by letting one or two drops of water fall on the surface of the stained rock fragment. In the presence of oil, the water will not soak into the cutting or flow off its surface, but will stand on it or roll off it as spherical beads. Dry spots may appear on the sample when the water is poured off. This, however, is not useful in powdered (air drilled) samples that, because of particle size and surface tension effects, will not wet.
Solid Hydrocarbons and Dead Oil: There has been much confusion, inconsistency and misunderstanding about the usage and meanings of these two terms. They are not synonymous.
Solid hydrocarbon refers to hydrocarbons that are in a solid state at surface conditions, usually brittle, and often shiny and glossy in appearance. There are a wide variety of substances called solid hydrocarbons with variable chemical and physical properties. The most significant of these variations is that of maturity. Some solid hydrocarbons, like gilsonite, are immature or barely mature oils, while others like anthraxolite represent the carbonaceous residue left after hydrocarbons have been overheated and thermally cracked. Anthraxolite is considered a thermally dead oil. Gilsonite, on the other hand, is certainly not a dead oil. It is a substance from which high quality gasoline, industrial fuel oils and an endless list of other products are produced.
The term “dead oil” has been used indiscriminately in the industry to describe oils that are either (1) solid, (2) nonproducible or (3) immobile. All of these definitions are deceptive and misleading. Some solid hydrocarbons are not dead oil. Many so called “non—producible oils” are now productive because of improved recovery technology, and there are numerous examples of “immobile oil” at surface conditions that is fluid and mobile at depth. Other factors that have been used to distinguish them are extremely variable and have lacked general agreement by industry. For example, whether or not positive indications of fluorescence, residual cut, and/or cut fluorescence are considered requirements, or whether the physical state of the oil is solid or tarry.
In view of the above it is recommended that usage of the term “dead oil” be applied only to thermally dead solid hydrocarbons that will not fluoresce, or give a cut or cut fluorescence. Whenever the term is used, qualifying data should be listed.
Generalizations
No “rules of thumb” can be used to relate the evidences of the presence of hydrocarbons to potential production. However, there are some generalizations that are worth noting.
1) Lack of visible stain is not conclusive proof of the absence of hydrocarbons. (Gas, distillates and high gravity oils ordinarily will have no visible stain).
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2) Lack of fluorescence is not conclusive proof of the absence of hydrocarbons.
3) Bona fide hydrocarbon shows will usually give a positive cut fluorescence (wet cut). High gravity hydrocarbons will often give a positive cut fluorescence and/or a residual cut, but will give negative results with all other hydrocarbon detection methods. (Minerals that fluoresce will not yield a cut).
4) The oil acid reaction test will give positive results when oil is present, but it is very sensitive and may give positive results in the presence of insignificant amounts of hydrocarbons.
INTERPERTATION ISSUES
Cavings may often be recognized as material identical to what has already been seen from much higher in the hole. This spalling of previously penetrated rocks into the ascending mud stream is particularly pronounced after trips of the drill stem for bit changes, drill stem tests, coring operations or other rig activities. It is suppressed by good mud control, but most samples will contain caved material. Soft shales, thinly bedded brittle shales, and bentonites cave readily and may be found in samples representing depths hundreds of feet below the normal stratigraphic position of those rocks.
Owing to differences in the hardness of rocks, the type and condition of the bit, and the practice of the driller, one cannot set any hard and fast rule for the size of true cuttings. Caved fragments tend to be larger than fragments of rock from the bottom, and they are typically rounded by abrasion. Flaky shape, freshness of appearance, sharp edges and signs of grinding by the bit may be used as criteria for the recognition of fresh cuttings. Casing points should be carefully noted inasmuch as they indicate to the geologist examining the samples what parts of the hole were open at various stages of the boring and thus were a potential source of cavings. Casing does not entirely eliminate uphole cavings. Some caved material is commonly cemented around the bottom of the casing and is likely to show up again in the mud stream while drilling deeper.
Re-circulation chiefly refers to sand grains and microfossils from previously drilled rocks that re-enter the hole with the mud stream and contaminate the rising sample.
Lost Circulation Material is a large variety of substances may be introduced into the hole to combat lost circulation difficulties. These include such obviously foreign materials as feathers, leather, burlap sacking, or cottonseed hulls, as well as cellophane (which might be mistaken for selenite or muscovite), perlite, and coarse mica flakes, which might be erroneously interpreted as formation cuttings. Most of these extraneous materials will float to the top of the sample tray when it is immersed in water, and so can be separated and discarded at once. Others may need more careful observation. Generally, the sudden appearance of a flood of fresh-looking material, which occupies the greater part of a sample, is enough to put the sample-logger on his guard. As a check, he can consult the well record for lost circulation
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troubles, and the kinds of materials introduced into the hole.
Cement fragments in cuttings are easily mistaken for sandy, silty, or chalky carbonate. However, most cements are of an unusual texture or color, frequently have a glazed surface, tend to turn yellow or brown when immersed in dilute HCL, and are usually full of fine black specks. The latter are sometimes magnetic, in which case the fragments of cement can be removed from the cuttings with the aid of a small magnet. If the identification of cement is questionable, the well record should be examined to determine where casing was set or cement poured.
Drilling Fluid In examining unwashed or poorly washed cuttings, it is often important to be able to recognize the drilling muds that were used. An inexperienced sample-examiner may confuse drilling mud with soft clay, bentonite, or sometimes gypsum or a carbonate. Thorough washing and rinsing in a pan of water will generally remove most mud contamination. If necessary, lithic fragments can be broken open to see if the interior (fresh) differs from the surface (coated).
Oil-base and oil-emulsion muds coat the cuttings with oil, and care must be taken to distinguish such occurrences from formation oil. They are generally recognized because they coat all cuttings regardless of lithology, rather than being confined to one rock type. Such contamination can sometimes be removed by washing the samples with a detergent or with dilute HCL. Lignosulfate muds may present problems in samples used in paleonological studies.
Oil Contamination, Pipe Dope, etc: Foreign substances, such as pipe dope, grease, etc., from the rig operations sometimes enter the mud stream. Oil may be used to free stuck drill pipe and, in some cases, a tank truck formerly used to haul fuel oil is used to haul water for rig use. In all these cases, the borehole can become contaminated with oil, which can coat the drill cuttings. When foreign oil contamination is suspected, cuttings should be broken and their fresh surface examined. Naturally occurring oil will tend to stain the chips throughout; contamination will remain on or near the surface of the chip.
Pipe Scale and Bit Shavings: Scale shavings of metal may also contaminate the samples, but they can be readily removed with a small magnet. They are usually rusty and rarely present a logging problem.
Miscellaneous Contaminants: Other lithic materials which may be present in cutting samples and obscure their real nature, or might be logged as being in place, include rock fragments used as aggregate in casing shoes.
Rock Dust: If samples are not washed sufficiently, a fine dust composed of powdered rock or dried drilling mud may cover the chips with a tightly adhering coat. In such cases, care should be taken that a fresh surface of the rock is described. Wetting the samples will tend to remove this coating, but if the chips are saturated with oil, the powder may still adhere to the surface
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even after immersion in water, unless a wetting agent or ordinary household detergent is used. These comments are particularly applicable to limestone and dolomite where the powdered rock film tends to be in the form of crystals that may mask the true texture of the rock. In this case, the best procedure is to break a few chips and obtain fresh surfaces for description.
Powdering is the pulverization of the cuttings by regrinding (failure of the mud to remove cuttings from the bit), or by crushing between the drill pipe and the wall of the borehole. It can result in the disappearance of cuttings from some intervals, and the erroneous logging of chalky limestone where none exists.
Where well-indurated shale sections are air drilled, the samples can be cleaned conveniently by washing them with care on a 60-100 mesh screen. This cleaning procedure should be required, where feasible, as the dust coating on particles will mask the true color, texture and even the basic lithology
Fusing: Shales drilled by a diamond bit may be burned and fused, resulting in the formation of dark gray or black hard fragments that resemble igneous rock.
Air-Gas Drilling Samples: Cuttings from wells drilled with air or gas instead of mud are usually made up of small chips and powder, which makes sample examination difficult. Often, a basic rock type will be difficult to determine because dolomite powder effervesces as readily as limestone powder.
Sample Lag Correction Error: Lag time is the time required for cuttings to travel from the bottom of the hole to the place at which they are collected. If new hole is drilled during this time interval, the depth assigned to the samples will be greater than the depth from which the cuttings originated.
Despite the many methods available for determination of lag time and for the correct labeling of depths shown on the sample sacks, the actual job is often done incorrectly, or not at all, by the person catching the samples, who is usually a roughneck at the well site. Subsequent sample studies are thus affected by significant discrepancies between indicated sample depth and true sample depth. As a result of these discrepancies (1) lithologies are plotted at incorrect depths, (2) interpolation of true depths becomes time consuming and requires unnecessary log manipulation, and (3) uncertainties as to the character of the formation penetrated may be introduced.
If erroneous lag correction is suspected or known, the geologist examining the samples should endeavor to plot the lithologic information obtained from the sample study at true depth. This can best be done with the aid of a penetration rate (drilling time) log or mechanical log. If the discrepancy from true sample depth is not determinable, or is questionable, the samples must be plotted as labeled, with an appropriate note in the remarks column. Lag correction is best controlled at the well site.
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Spread is the separation of large from small cuttings by relative slippage (also called elutriation or differential settling) in the mud stream, so that the cuttings of a rock drilling up into fine chips may overtake the cuttings of a rock drilling up into coarse chips during their journey up the borehole. This results in the wrong sequence of rock types or very mixed samples being recovered.
“Boiler-housing” or “Dog-housing” of Samples: Unfortunately, because of inclement weather, lack of interest or supervision, breakdowns, or fast drilling, the sample catcher (generally an assigned roughneck) will occasionally sack up a number of samples only once during his tour. However, he then labels the samples as if they were properly caught at specific intervals. This collection procedure is known as “boiler-housing” or “dog-housing.” Any logger can readily see the errors inherent in this practice.
SAMPLE DESCRIPTIONS Common Abbreviations
SHALE: color hardness texture luster shape fossils accessories
lt gy sft smth dull blky Brac Pyr
med sli frm vf subresin flky Gasto micromica
dk gy frm fn resin plty Crin mica
blk v frm med subwx splty mica
brn hd crs wxy slty
red brtl aren
mrn calcareous
mottling carbonaceous
Determine Color from WET sample
SANDSTONE: color, hardness, grain size, shape, sorting, cement, fossils, accessories, porosity, fluor, stain, cut, ring stn
COLOR HARDNESS
GRAIN SIZE
Shape Sorting Cement Access. Porosity
Fluor Stain Cut Ring stn
Clr Sft Lvfg Well rnd
Well srtd
Clay Chlor Ig Dull gold
Gassy Sli strm Thin
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Lt gy Friable Uvfg Rnd Gd srtd Calc Glau Pp Gold Lt tntn Slow strm
Thick
Med gy Frm Lfg Subrnd Fr srtd Dolo Pyr frac Dull yel brn Gd strm Bright
Bright wh
V frm Ufg Ang Pr srtd arg Siderite Yel Dif Dull
Off wh hrd Lmg subang Ankerite
Blue No vis cut
spotted
tn Umg Sh prtgs spotted
Frosted Lcrsg Ls frag
ucrsg Feld
bitum
Determine Color from WET sample
SANDSTONE: color, hardness, grain size, shape, sorting, cement, fossils, accessories, porosity, fluor, stain, cut, ring stn
COLOR HARDNESS
CRYSTAL LUSTER FOSSILS ACCESS POROS FLUOR CUT RING STN TEXTURE
Wh Sft Crytpo Dull Crin Pyr Microxln Min No vis Thin Chky
Off wh Sli frm Micro Erthy Brach Glau Ixln Gold Sli strm Thick Sub chky
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Buff Frm Vf Resin Gasto Mica Pp yel Slow strm Brt
Crm hd F Vit Pel Arg Vug Gd strm Dul
tn Med Worm holes
Aren Moldic dif Spotted
Brn crs crin Oomoldic splotchy
Mott Brach
Lt gy Gasto
gy oolites
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Chromatography
The Bloodhound and Wheatstone bridge detectors, like all modern gas equipment incorporates
a gas chromatograph. A gas chromatograph is a chemical analysis instrument for separating
gases in a complex sample. A gas chromatograph uses a flow-through narrow tube known as
the column, through which different chemical constituents of a sample pass in a gas stream;
(carrier gas, mobile phase). The gases move at different rates, depending on their various
chemical and physical properties and their interaction with a specific column filling (stationary
phase). The chemicals finally exit the end of the column. As they exit they are detected and
identified by either the IR detector of the type used by the Bloodhound, the classic Wheatstone
bridge detector or other means. The function of the stationary phase in the column is to
separate different components, causing each one to exit the column at a different time
(retention time). Other parameters that can be used to alter the order or time of retention are
the carrier gas flow rate, and the temperature. In a GC analysis, a known volume of gaseous or
liquid is injected into the "entrance" (head) of the column, usually using a micro-syringe (or,
solid phase micro-extraction fibers, or a gas source switching system). Although the carrier gas
sweeps the molecules through the column, this motion is inhibited by the adsorption of the
molecules either onto the column walls or onto packing materials in the column. The rate at
which the molecules progress along the column depends on the strength of adsorption, which
in turn depends on the type of molecule and on the stationary phase materials. Since each type
of molecule has a different rate of progression, the various components of the mixture are
separated as they progress along the column and reach the end of the column at different
times (retention time). A detector is used to monitor the outlet stream from the column; thus,
the time at which each component reaches the outlet and the amount of that component can
be determined. Generally, substances are identified by the order in which they emerge (elute)
from the column and by the retention time of the in the column.
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Molecular adsorption and the rate of progression along the column depend on the
temperature, the column temperature is carefully controlled to within a few tenths of a degree
for precise work. Reducing the temperature produces the greatest level of separation, but can
result in very long elution times. For some cases
temperature is ramped either continuously or in
steps to provide the desired separation. This is
referred to as a temperature program. Electronic
pressure control can also be used to modify flow
rate during the analysis, aiding in faster run times
while keeping acceptable levels of separation.
The rate at which a sample passes through the
column is directly proportional to the
temperature of the column. The higher the
column temperature, the faster the sample moves through the column. However, the faster a
sample moves through the column, the less it interacts with the stationary phase, and the less
the gases are separated.
NOTE: Whether the detector is
IR or a Wheatstone Bridge, a
column is used to separate the
component gases.
A number of detectors are used
in gas chromatography. The
most common are the flame
ionization detector (FID) and
the thermal conductivity
detector (TCD). Both are
sensitive to a wide range of
components, and both work
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over a wide range of concentrations. While TCDs are essentially universal and can be used to
detect any component other than the carrier gas, FIDs are sensitive primarily to hydrocarbons,
and are more sensitive to them than TCD. Both detectors are also quite robust.
In the flow system you have 3 filaments for the measuring of the different types of gas and
units of gas. The TC and CC filaments work in tandem coming from the Decompression
Chamber to measure the Total Gas (TG). The Thermal
Conductivity (TC) filament measures gas over 200 units while the
Catalytic Combustion (CC) or Hotwire filament measures gas from 0 to
200 units. There is also another CC Filament located after the
Chromatograph Column that measures gases C1 through C5. These gases
are:
C1 – Methane
C2 – Ethane
C3 – Propane
iC4 – Iso Butane
nC5 – Normal Butane
The Bloodhound software not only monitors the gas sample, coupled with data provided by rig
instrumentation, it connects that information with drilling parameters to identify where the gas
originated in the wellbore. Called the ‘LAG’, a term that will be discussed in detail later, this
depth is presented along with other pertinent information about the drilling operation. In
addition, the software presents considerable information about the operational state of the
Bloodhound to provide the user with a means for continuous diagnostics of the systems
operation.
Calibration
chromatogram
from the
Bloodhound
Calibration
chromatogram from
a Wheatstone Bridge
type detector.
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Understanding Gases in the
Circulating System Previously we identified and explained the standard gases PALADIN routinely monitors coming
from the well bore. As a reference, we monitor Total Gas plus the component gases Methane,
Ethane, Propane, Iso-Butane and Normal Butane. However, considerably more is involved in the
understanding and interpretation of the gases than previously stated. Here we will investigate
other factors that complicate the interpretation of these gases.
Sufficient evidence exists to suggest that misinterpretation of well-site gas detection data is
quite common. The question is often asked, “How big a gas kick should I expect to get from a
zone that will make a well?” Such misunderstanding may often be traced to a lack of familiarity
with the fundamental principles of gas detection and interpretation.
To illustrate these fundamental principles, a drilling model is presented to demonstrate the
effects of bit penetration. The model is analyzed to explain theoretical gas detection response
to penetration of a hydrocarbon bearing zone. Gas kick characteristics, as transmitted to the
surface by the drilling fluid, are specifically related to bit penetration. A careful analysis of the
drilling model derives four classifications of gas present in the drilling fluid. These are:
LIBERATED GAS
PRODUCED GAS
RECYCLED GAS
CONTAMINATION GAS
A strong case is presented to show that all drilling fluid hydrocarbons may be classified into one
of the four categories.
Definitions are provided for each type of gas.
LIBERATED GAS is defined as gas mechanically liberated by the bit into the drilling fluid as the it
penetrates the formation.
PRODUCED GAS is defined as gas produced into the drilling fluid from a specific zone in
response to a formation pressure which exceeds the opposing effective hydrostatic pressure.
RECYCLED GAS is defined as gas which has been pumped back down the hole to appear a second time
at the surface.
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CONTAMINATION GAS is defined as gas artificially introduced to the drilling fluid system from a
source other than the rock formations.
The total gas detector and the chromatograph are normally installed as companion instruments
at the well-site and provide a continuous monitoring of the drilling fluid and well cuttings for
the presence and composition of hydrocarbons.
Although cuttings gas detection and analysis is of considerable value in its own right, it is not
germane to the current paper and therefore will not be discussed.
Unfortunately the term “gas detection” has often proven to be misleading because it appears
to suggest that gas detection equipment is only of service in locating gas reservoirs. This is not
the case, as shown by Evans, Rogers and Bailey, (4) mature liquid hydrocarbon reservoirs are
characterized by rich compositions of all components in the gasoline range C4 through C7 with
a good distribution of gases in the range C2 through C4 plus reasonable quantities of C1. These
facts demonstrate that gas detection equipment should be more properly called hydrocarbon
detection equipment since it is effective in locating both gas and liquid hydrocarbon reservoirs.
A second unfortunate confusion of terms also leads to misunderstanding. To drilling
personnel, a “gas kick” refers to a volume of gas entering the mud system which is large enough
to disrupt normal drilling operations and constitutes a hazard. The most important factor of
concern in this case is the volume of the gas in barrels normally expressed as, “magnitude of
the kick.” To gas logging technicians, however, a “gas kick” is a significant increase in gas
detector response from increasing concentration of gas in the mud system. This “kick” is
recorded in “gas units” and usually has very little effect as measured by other mud monitoring
systems. “Kick magnitude therefore refers to maximum recorded units of gas and not to gas
volume. It should be clearly understood that this paper is concerned with the latter definition
when the term “kick magnitude” is used. A “strong gas kick” may be recorded by the gas
detector due to its high sensitivity when no other indications of the kick are observed.
Well Bore Model
Requisite to a clear understanding of the interpretation of mud-gas data is consideration of the
source of hydrocarbons as they occur in the drilling mud. To assist in this consideration, a
simple drilling model is proposed which illustrates the impact of bit penetration through
hydrocarbon accumulations. A series of cases is presented where variations in the
configuration of the mud-gas data indicate specific differences in the response of the
hydrocarbon bearing zone to bit penetration and subsequent rig operations.
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The model will show that the geometry of the gas kick recorded by the instrumentation and
plotted with respect to time is directly related to significant characteristics of the hydrocarbon
zone as well as the impact of concurrent drilling operations. It will become apparent that the
configuration of the gas kick as recorded directly from the drilling mud is of greater interpretive
significance than the magnitude of the gas kick. When instrument chart data recorded versus
time is digitized and plotted in graph format versus depth, the magnitude of the gas kick may
be faithfully reproduced but the configuration of the kick is usually lost.
Thus, it becomes obvious that basic and vital interpretation must derive from a detailed
analysis of the instrument charts themselves and not solely from a plotted graph. The basic
function of the plotted graph should be to collate, according to depth, pertinent data produced
from various sources. This graph then provides a broader understanding of the hydrocarbon
accumulation and a convenient means for future reference.
To illustrate these concepts, a diagrammatic technique has been employed which graphically
relates the gas detector response plotted versus time to the actual penetration of the rock by
the drilling bit through the penetration rate curve plotted versus depth. This technique allows
direct comparison of the geometry of the gas kick to actual rock penetration.
LIBERATED GAS
Full Hole Drilling
The previous
illustrates a typical
situation where a
bore hole is created
through a
hydrocarbon
bearing zone and
the total bottom
hole pressure (TBP)
is greater than the
formation pressure
(FP). During
penetration, the bit
continuously
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introduces to the mud system components of the rock contained in the cylinder defined by the
hole size and the thickness of the interval.
Liberated gas is therefore defined as gas mechanically liberated by the bit into the drilling fluid
as the bit penetrates the formation.
As shown, the penetration rate curve corresponding to the porous interval shows a
characteristic drilling break from 20 minutes per foot to 5 minutes per foot. Such drilling breaks
are often invaluable in determining the thickness of porous intervals. The hypothetical gas
detector response shows a typical record of the concentration of hydrocarbons in the mud
versus time.
The concentration of liberated hydrocarbons in the mud is primarily a function of the following
factors.
1. Penetration rate 2. Absolute pore volume 3. Formation pressure
Substantial increases in any of the three named factors will normally have a visible effect on the
gas detector response. In the normal case, the rate of penetration is the most important single
factor in determining the magnitude of the gas kick.
RECYCLED GAS
In the event that mud gas is not completely volatilized in the settling pit but is pumped back
down the hole, the gas detector may record a second appearance of a pre-existing kick. This
phenomenon is diagramed in figure1, where the liberated gas kick has recycled to the surface
for the second time and is designated R.
Recycled gas is therefore defined as gas which has been pumped back down the hole to appear
a second time at the surface.
Recycled gas may be identified by the application of certain tests. The recycle should be no
larger than the original kick but should be similar in shape. The composition of the recycled
kick may be misleading in that the more volatile hydrocarbons are often liberated to the
atmosphere in the pits and under the influence of a degasser. The result is the analysis of the
recycled kick shows a larger proportion of heavy ends.
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From the beginning of the primary gas kick to the beginning of the recycled gas kick in
circulating time is a good indication of the total circulating time of the mud system. Such direct
information may often be helpful in assuring the accuracy of an estimated lag time.
LIBERATION
Below the diagram demonstrates possible alternative explanations for instances where the
duration of the gas kick does not seem to extend throughout the entire period of probable
liberation as projected from other indicators such as the penetration rate.
In a type one gas kick
(TBP>FP) only liberated gas
would comprise the gas kick.
If the geometry of the kick is
solved in a manner consistent
with the principles derived in
figure 1, a significant variation
within the interval of the drilling
break becomes apparent. Two
alternative explanations are
suggested in (A) or (B) as shown in
figure 2.
(A) Since gas was mechanically liberated only from the top portion of the drilling break, it is probable to
assume that the best
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porosity occurs through that interval. The absolute pore volume is probably
diminished or absent through the bottom of the section resulting in no liberation. If
liberation should occur from the bottom of the zone and not from the top, this
explanation would be favored over (B) because gas does not naturally occur under
water in a contiguous reservoir. In case (A) the constant penetration rate
throughout the drilling break would probably reflect better bit performance in
sandstone than shale. The distinction between drilling porous and nonporous
sandstone appeared to be of little consequence by comparison.
(B) If indications suggest that the porosity does in fact continue throughout the Interval as delineated by the drilling break, it is probable that the absolute pore
volume is filled with water. This principle can be exceptionally helpful in
conjunction with log saturation indications in determining the gas-water interface
or transition zone.
PRODUCED GAS
The figure below illustrates the abnormal case where the total bottom hole pressure (TBP) is
less than the formation pressure (FP). The gas kick resulting from such a situation is
characterized by significant differences from those previously discussed and is designated a
type two gas kick.
This shows the usual situation where the
hole does not begin to make fluid
immediately upon penetration of the
zone but the gas kick commences at the
one normal lag time. Such kicks are
characterized by exceptional initial
magnitude and the continuation of the
kick beyond the time normally
anticipated for the termination for the
liberated kick.
If the source zone is clearly defined by
the penetration rate and other available
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geological data, it becomes apparent that the formation is contributing additional hydrocarbons
to the mud system beyond those mechanically liberated.
Produced gas is therefore defined as gas produced into the drilling fluid from a specific zone in
response to a formation pressure which exceeds the opposing effective hydrostatic pressure.
Significant contrasts in interpretation result from a type two gas kick.
(1) There is now no direct relationship between mechanical liberation and mud circulation, therefore, definitive analysis of the source zone thickness and quality becomes extremely difficult. The magnitude of the gas kick can no longer be related to the general significance of the source zone in comparison with other type one gas kicks.
(2) The presence of produced gas demonstrates conclusively that at least some degree of effective permeability is present. This direct evidence of permeability is in contrast to the absence of any definitive evidence in a type one kick where only mechanical liberation occurs.
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(3) Since produced gas is generally independent of mechanical liberation and its Attendant controlling factors, it is reasonable to expect that the configuration and magnitude of type two gas kicks encountered while coring would be generally independent of the mechanical characteristics of the coring operation.
CONTAMINATION GAS
Occasionally drilling operations require the introduction of oil in various forms to provide
additional pipe lubrication, etc. Oil base muds are often used to minimize formation damage
through elimination of excessive water loss. Diesel is the normal oil phase used in inverted oil
emulsion muds. Diesel in its natural state does not contain volatile hydrocarbons and therefore
retain some volatile gases. Hydrogen gas is often detected in the drilling mud resulting either
from the effect of an acid mud on drill pipe iron or associated with the setting action of cement.
Occasionally mud additives or various chemical reactions in the mud will provide other
hydrocarbons or combustible gases which may be detectable by well-site total gas detectors.
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All of these examples comprise combustible gas sources which are not indigenous to the rock
formations and must be identified accordingly when detailed interpretation is desired.
Contamination gas is therefore defined as gas artificially introduced to the drilling fluid system
from a source other than the rock formations.
After working around gas detection equipment for some time, rig personnel become aware of
what gas sources can be added to the mud to influence gas detector readings. One must of
course establish that the gas source was not deliberately introduced by a member of the drilling
crew.
At certain times mud conditions are such that the introduction of large volumes of air into the
mud system cause “pseudo gas kicks.” These kicks do not reflect increased gas concentration in
the mud but rather greater gas trap efficiency when the air-rich mud reaches the surface. This
phenomenon may occur after trips when a float is used or from kelly air introduced during
connections. Such pseudo kicks are often called “kelly kicks,” or have a distinct effect on “trip
gas kicks.” Trip gas will be considered in detail later.
The next diagram portrays a type two gas kick and suggests subsequent rig operations which can be
used to deal with an abnormally pressured interval with due regard to safety and optimized penetration.
CONNECTION GAS
In this hypothetical situation the
rig experienced a type two gas
kick. After continuing circulation
for some time, magnitude of the
readings continued to increase.
At that point a decision was
made to increase the mud
weight which eliminated the
produced gas and returned the
mud system to the pre-existing
background. The time scale is of
course very compressed in this
example and does not
accurately portray the time span
often necessary to eliminate
large quantities of produced and
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recycled produced gas. Subsequent to elimination of produced gas, a connection was made.
Evidence of the connection appears on the gas detector chart as a decrease in the carried
background reading due to no mud circulation during the connection. At approximately one lag
time after circulation was resumed, a kick occurred. This kick was deemed produced gas as it
was related to the connection and was not liberated from the formation being penetrated one
lag time before the kick.
Because there is no evidence of produced gas in the system while circulating, it is apparent that
the mud weight plus the annular pressure drop (APD) are sufficient to create a total bottom
hole pressure greater than the formation pressure. Therefore, the connection gas peak
experienced after the first connection subsequent to penetrating the gas zone may be related
predominantly to swabbing of the zone rather than to insufficient hydrostatic pressure.
Swabbing may occur when the kelly is raised for a connection. Because the annular pressure
drop is lost during periods of no circulation, the bottom hole pressure is equal to the
hydrostatic pressure for static mud systems.
This decrease of bottom hole pressure may be a factor in the magnitude of the connection
peak. Since the swabbing effect is not measurable, it would be difficult to ascertain with any
degree of accuracy the significance of connection gas peaks which result when bit movement
on connections extends above the gas zone.
On the next connection, however, when it was certain that not bit swabbing occurred, not
connection gas peak resulted. This fact suggests that the mud may be too heavy since not
produced gas resulted from loss of the annular pressure drop.
The mud weight was subsequently reduced until a moderate connection gas kick occurred with
no increase in background values while circulating. The formation pressure of the producing
zone is bracketed as follows: The formation pressure is approximately equal to or greater than
the hydrostatic pressure, however, the formation pressure is less than the hydrostatic pressure
plus the annular pressure drop. Such circumstances represent the optimum mud weight for
containing the zone yet providing positive evidence that the mud weight is not excessively high.
Subsequent reduction in mud weight resulted in measurable quantities of produced gas
becoming apparent in the mud system during circulation. This fact suggested that the
formation pressure was now greater than the total bottom hole pressure and that the mud
weight had been reduced too much. The mud weight was then increased to restore the ideal
condition of moderate connection gas peaks with no evidence of produced gas while
circulating.
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TRIP GAS
This general term applied to produced gas which characteristically occurs within one lag time
after a trip is completed and circulation has been resumed. Three basic factors influence the
presence, location, and magnitude of the trip gas kick.
(1) The loss of the annular pressure drop (2) The effect of bit swabbing the entire hole. This effect is of course influenced
to a considerable degree by such factors as the speed at which the pipe is tripped out of the hole, variations in hole size, the configuration of a packed hole assembly, and tripping out with a full hole core barrel.
(3) The time over which these factors influence the static mud system.
The basic principles previously discussed with regard to connection gas of course also apply to
trips. The most significant difference between trips and connections is the extreme
accentuation of these influences during a round trip as compared to the relatively minor
influence of a connection.
This accentuation of effect should immediately suggest the seriousness of ensuring absolute
control over any previously drilled zone exhibiting abnormal pressure characteristics before a
trip is attempted. It would be extremely foolish to suspend circulation and commence a trip in
the midst of a formation gas kick without first determining the source of the kick.
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WellSight The log drawing software is called WELL SIGHT. We use version 6x at Paladin. There are
differences between versions. The different versions are also specific to different versions of
Windows. For example…..
Well Sight Versions VS Operating System
Windows WS 6.3.5 WS 6.4.2
Win 7 X X
Win 8 X
Note: Because there are considerable differnces between versions, this creates certain
compatibility issues that we need to be aware of. For example, if a log is drawn in version 4x
and imported to version 6x, that log is automatically converted to version 6. You will not be
able to return to the log’s original version. We have had issues with this in the field when
someone accidently converted the log. The log had to be redrawn in the original version.
For version 6x, you will see these two icons on the desktop, the top icon is for
horizontal well and the bottom is for vertical wells. All versions we use require
he license key, a USB key inserted in the computer. If the key is not present, the
software will not run.
There are some key issues with data that all personnel should be aware. For
example:
Negative numbers in the DATA.DAT file will NOT import, 0 out negatives
Depths must be continuous
When starting a new log, the first
thing to do is define the units and
scale. For the horizontal log, the
default units is meters. You MUST
change this or the scales will be off.
Next the type of log will need to be
defined, 1”, 2”, or 5”. Select OK
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when done.
The basic log format will appear as seen below.
The next thing to be defined will be the various headers. From the menu, select HEADERS
from the drop down list. The first choice is MAIN HEADER. Select Main Header and fill it in as
seen below. Please follow this format for all the logs drawn. It will be necessary to gather this
type of information before beginning any new log.
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Once the Banner page is filled in with the correct well information, proceed to the next button,
OPERATOR. The Operator input page will appear as seen here. Again fill in the pertinent
information as seen here. Click OK when done. Use TAB and SHIFT+TAB to advance to the next
or previous field.
Use the Other Info section of the header to enter additional information that doesn't have a
field (e.g. formation tops or casing details).
The fields under Other Info are Cores, DST's and Comments and can be changed to whatever
information category you wish to use by simply highlighting the name (e.g. Cores) and typing in
the new name (e.g. Formation Tops). You can type any information into these fields that you
require.
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The Header dialog also allows you to import a custom banner into the header section of your
log printout. The banner must be created as a .BMP file in such programs as Paint (which is
included with Windows). Banners can be 1 to 4 inches in height and about 7 inches wide. Once
you have created the Banner, click Banner in the Header dialog and the Header Banner dialog
will appear. Now choose Open Banner File and a File Open dialog appears. In this dialog locate
your .BMP file and click OK. Your banner will now be printed at the top of your log header.
The next button selection is Geologist. Select this button and again fill in the correct information as seen
below. Again be sure you complete all the inputs as seen in this example. Please change the data to
match that of your individual well!
The last banner input is OTHER INFORMATION. This will be filled in with the type of information as seen
below.
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Click OK when done. The last button selection is CORE INFORMATION. Fill this data in only if cores are
run on
your
well.
Paladin Surface Logging, LLC
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Next select the depth range of the well you are logging. You will enter the depth at which you
started logging and the projected Total Depth for the well. If the well is deeper or shallower
than expected, you can always return to this input
screen and modify the values.
After defining the depth range, in the ENTER DATA, screen,
select the ROP scale. In most cases we will be logging using
MIN/FT. Select CLOSE when complete.
After all this basic information is entered, the specific design
of the log will have to be completed. Under LAYOUT on the
menu bar, select LAYOUT DESIGNER. The following definition
should be used as a standard within PALADIN for log
creation.
The LAYOUT DESIGNER seen below is the order PALADIN
requires for the layout of our logs. You can re-order the
curves by using the MOVRE UP and MOVE DOWN buttons to
the right of the window. To move a track, simply click on the
desired track highlighting it. Then click on the MOVE UP or MOVE DOWN button. Once you are finished
with the re0ordering of the tracks, they should appear as seen here.
Once you are satisfied with the track order, use the
following track definitions to setup the individual tracks
on the log.
The order of tracks displayed in the Layout Designer
defines the order of the tracks on the log. PALADIN has a
standard design which will be defined here. For now pay
particular attention to the ‘MOVE UP’ and ‘MOVE
DOWN’ buttons on the figure to the left. Highlight the
track you wish to move from the list of tracks on the left
hand side of the dialog. Now click on the Move Up or
Move Down button on the right hand side of the dialog.
The Move Up button will move the track up the list so
that it will appear further to the left side or top of the
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log. The Move Down button moves the track down the list or toward the right side or bottom of your
strip log.
NOTE: The following tracks and their definitions define the PALADIN standard.
Please pay strict attention to this format and use it on all your logs, horizontal
or vertical.
Track 1 – ROP
Track2- Depth
Track 3- % Lithology
Track 4- Chromatography
NOTE: Tracks can simply be ‘disabled’ by clicking the ‘+’ next to the curve name
and seen second in the list that appears, ‘ENABLED’, clicking on the check in the
box disables this curve.
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DEPTH TRACK
Each track has many options that define how the curve will appear on the log. Simply follow
these guide lines when defining each curve as seen here and on the curves to come.
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ROP TRACK
122
LITHOLOGY TRACK
123
TOTAL GAS AND CHROMATOGRAPHY TRACK
124
Seen below are the specific definitions for each of the chromatography curves found on the PALADIN
log. Please examine each definition and apply this to your log design.
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126
DESCRIPTIONS TRACK
The final base log should look like this. The next step will be to import the data from DATA.DAT onto the
log.
Importing ASCII or LAS Data Curves
Once you have created your new tracks or wish to use the existing tracks for data, you can
enter the digital data manually or use the Import function in the File menu. When you click on
Import four options will appear in the popup menu.
1. LAS imports data from Log ASCII Standard 2.0 files.
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Select LAS from the Import popup menu and the Import LAS File dialog will appear, using
windows, locate the File of data you wish to import data from. When the data file has been
identified and opened, the Import Data dialog appears.
Near the top of the dialog, the Data Step will be identified. Make sure the Data Step reflects the
data density you wish to present in your log. For example if the data in the file is recorded at
0.1 and you are importing data at 1.0 you will only be importing 10% of the data from the file.
You will see three columns of information in the lower left box titled Data Curves. Double click
the fist column to highlight the curve in your log and toggle between Yes or No (whether or not
the curve is selected).
The second column indicates the curve and column in which the data will be recorded to.
The third column identifies the column in the data file where the data will be imported from. To
select the column of data you wish to import, right mouse-click on the third column and a
popup menu of the available LAS curves will appear. Simply click on the curve you wish to
import. Once you have selected and identified the curves and data you wish to import, click the
Import button and the program will now automatically import the data. It is always a good idea
to check your log at this point to make sure the data is in the correct track and column.
2. ASCII imports data from tab delineated files or data files
Select ASCII from the Import popup menu and the Import ASCII File dialog will appear, using
windows, locate the File of data you wish to import data from. When the data file has been
identified and opened, the Import Data dialog appears.
It is a good idea to identify the Data Step from the ASCII file using a text editor such as
Wordpad. Make sure the Data Step reflects the data density you wish to present in your log.
For example if the data in the file is recorded at 0.1 and you are importing data at 1.0 you will
only be importing 10% of the data from the file.
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You will see three columns of information in the lower left box titled Data Curves. Double click
the fist column to highlight the curve in your log and toggle between Yes or No (whether or not
the curve is selected).
The second column indicates the curve and column in which the data will be recorded to.
The third column identifies the column in the data file where the data will be imported. To
select the column of data you wish to import, right mouse-click on the third column and a
popup menu of the available curves will appear. Simply click on the curve you wish to import.
Curve one is usually the depth but again it is a good idea to use a text editor to identify the
columns of data. Once you have selected and identified the curves and data you wish to import,
click the Import button and the program will now automatically import the data. It is always a
good idea to check your log at this point to make sure the data is in the correct track and
column.
3. Surveys imports survey data to the survey data dialog within the program
Select Surveys from the Import popup menu and the Import Survey File dialog will appear,
using windows, locate the File of data you wish to import data from. When the data file has
been identified and opened, the Import Data dialog appears.
You will see three columns of information in the lower left box titled Import Surveys. Double
click the fist column to highlight the curve in your log and toggle between Yes or No (whether
or not the curve is selected).
The second column indicates the survey field to which the data will be recorded.
The third column identifies the column in the data file where the data will be imported from. To
select the column of survey data you wish to import, right mouse-click on the third column and
a popup menu of the available LAS curves will appear. Simply click on the survey data you wish
to import. Once you have selected and identified the surveys and data you wish to import, click
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the Import button and the program will now automatically import the data. It is always a good
idea to check your log at this point to make sure the data is in the correct.
4. Descriptions imports description into the description track within the log
Select Descriptions from the Import popup menu and the program will allow you to locate the
File of text you wish to import description from. When the file has been identified and opened,
the Import Description dialog appears.
The descriptions will now be automatically imported. A tip for creating a file of descriptions is to
flag each description with a depth i.e. 1245-1255 and the program will place the description at
that depth. Descriptions may also be cut and pasted into or out of the log. Simply open a text
file and the strip log at the same time and either click between the files using the mouse or by
using the key command ALT and TAB
Once data has been added to the log, it should look something like the one below.
Please note that if you have difficulty importing data into the log, it is probably missing feet or
has too many feet in your data.dat file. You will have to go back and fix this for the data to
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import. Also be aware of the quality of the data in the rop and gas. Correct any inconsistencies
before importing the data.
Adding Lithology Symbols
With the mouse cursor over the Lithology track, right-click and select the rock type symbol you
want to use from the pop-up menu. This symbol now becomes the current symbol for the
lithology track.
Position the mouse in the lithology track and click and drag to add rock type symbols. If you
enter the wrong rock type, simply select the correct rock type and reenter it. If you want to
completely erase a rock type symbol, select the special symbol "BLANK" and click and drag over
the symbols.
Adding Lithological Accessory Symbols
To add a mineral accessory to the lithology track, right-click over the lithology track and select
the Mineral layer from the pop-up menu. The mineral layer now becomes the current layer for
this track. Right-click again and select the desired mineral accessory. The mineral symbol that
you choose now becomes the current symbol for the lithology track.
Move the mouse to where you would like to place the mineral accessory and click. You can
place symbols anywhere in the lithology track. You can place several symbols of the same type
without returning to the menu.
If you place a symbol at the wrong position simply click on the symbol and drag it to where it
belongs. To delete a symbol, click on it then press CTRL+DEL.
The Fossil, Stringer, and Texture symbols work the same way as the Mineral symbols.
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Entering Geological Descriptions
Select the size of text you want to use from the pop-up menu in the Geological Descriptions
track. You might use Normal for most descriptions and Large for formation tops.
To add a geological description, double-click the left mouse button in the track where you want
your description to appear. A text box appears with a blinking cursor. You can now type your
descriptions into the box as you would in a word processor, including using the mouse to select
text and the arrow, backspace, and delete keys.
If you do not like the text size you have chosen, simply right-click on the description box, then
select the text size from the pop-up menu. This will change your text size in the box selected.
You can create your text in any word processor and cut and paste it into a description edit box
using the Cut, Copy and Paste commands on the Edit Menu.
One way to switch between your word processor and STAR.LOG is to reduce the size of both
programs' windows so that they fit side-by-side on the screen. Another way is to leave both
programs' windows at full size and press ALT+TAB to switch between them.
Entering Engineering Data
Entering engineering data in the data curve track is done very similarly to adding geological
descriptions.
Before adding engineering data, select the desired text size from the Text Menu, or from the
pop-up menu for the curve track (use the right mouse button). Typically, you would use Small
so that the engineering data doesn't interfere with the data curves.
To add engineering data, double-click the left mouse button in the data curve track. You can
edit, move, and delete engineering text blocks the same way as for geological descriptions.
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Zooming the Log Diagram
If you require your log to appear larger on the screen for any reason, the program will allow you
to zoom in on that portion. Select View Menu|Zoom In (or use the key command Ctrl+I) and
the program will zoom in on that portion of the log. To zoom out select View Menu|Zoom Out
(or key command Ctrl+O) to view your log in larger sections. If you wish to return to the
original view of your log simply select View Menu|Zoom Normal Size (Ctrl+N).
Changing the Log's Depth Scale
If you have prepared a log in a scale which is not appropriate for your use, the program will
allow you to change the scale to a select group of alternate scales. Select Layout Menu|Depth
Scale and a dialog box will appear which will allow you to choose the scale you wish to change
your log to. Select the scale and press OK and your log will be converted to that scale. Before
printing a log with an adjusted Depth Scale, make sure you check the log for overwritten text,
crowded symbols, etc.
Surveys imports survey data to the survey data dialog within the program
Select Surveys from the Import popup menu and the Import Survey File dialog will appear,
using windows, locate the File of data you wish to import data from. When the data file has
been identified and opened, the Import Data dialog appears.
You will see three columns of information in the lower left box titled Import Surveys. Double
click the fist column to highlight the curve in your log and toggle between Yes or No (whether
or not the curve is selected).
The second column indicates the survey field to which the data will be recorded.
The third column identifies the column in the data file where the data will be imported from. To
select the column of survey data you wish to import, right mouse-click on the third column and
a popup menu of the available LAS curves will appear. Simply click on the survey data you wish
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to import. Once you have selected and identified the surveys and data you wish to import, click
the Import button and the program will now automatically import the data. It is always a good
idea to check your log at this point to make sure the data is in the correct.
Importing Photos
Photos require a separate track on the log. To add this track …
Select DESIGNER
Select PHOTOS
click ‘+’
Select ‘ENABLED’ [ click the box to enable]
Click ‘UPDATE’
Close ‘DESIGNER’
Goto EDIT
SYMBOL LIBRARIES
Under ‘SYMBOL LIBRARIES’, Scroll down to PHOTOS
Under ‘SYMBOLS IN SELECTED LIBRARIES’
Click ‘IMPORT’, use the open ‘BITMAP FILE’ and find the path where your images are stored.
In the PHOTO Track, right click the mouse and select your photo. A small box will appear with the image. When the check appears beside the image to save to the log, left click the mouse to place the image on the log.
You can move the image by selecting the image and placing it where it is needed.
To delete the photo, click the image to select it
Select ‘EDIT’ from the ‘MENU’
Click ‘DELETE SELECTION’
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Printing your Log File
Select File Menu|Print Setup to choose and configure the printer to be used. .LOG can print to
any raster printer (e.g. inkjet, dot matrix, or laser-writer), either color or black and white.
Select File Menu|Print. This opens a dialog for you to specify the type of printer you have
(color or B&W, page oriented or continuous feed), and what you want to print. You can choose
whether to print the log headers and symbol legends and/or the track headings. You can print
the entire log or any depth range of it. When you have made your choices, click OK.
Some printers work better than others for printing strip logs. If you encounter problems
printing your strip log, see the online-help topic "Trouble Shooting". If you are planning to buy
a printer to use with STAR.LOG, see the on-line help topic "Buying a Printer" for some general
advice and specific recommendations. (If you have access to the Internet, you can also look at
our web site for our latest printer recommendations.
NOTE: If additional assistance is required, use the HELP found in WellSight. This
section of the manual was created from parts of HELP. Considerable additional
information is available than what is found here. You are encouraged to check it
out for future reference.