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

28

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.

29

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.

30

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.

32

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.

33

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.

34

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

52

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.

53

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.

54

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

55

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

56

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.

57

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

58

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

59

Fossil

60

61

Mica LCM

62

Pyritic Cement

63

Salt & Pepper Sand

64

Tight Sand

Siltstone w/bedding plane

65

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

66

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)

67

(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

68

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.

69

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.

70

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.

71

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

72

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.

73

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

74

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.

75

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

76

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

77

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

78

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

79

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

80

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

81

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.

82

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.

83

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.

84

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.

85

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.

86

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.

87

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.

88

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.”

89

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.

90

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

91

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.

92

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).

93

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

94

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

95

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.

96

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

97

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

98

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

99

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.

100

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

101

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.

102

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.

103

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.

104

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

105

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.

106

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

107

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

108

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.

109

(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.

110

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

111

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.

112

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.

113

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

114

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.

115

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.

116

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.

117

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

118

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

119

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.

120

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.

121

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.

125

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.

127

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.

128

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

129

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

130

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.

131

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.

132

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

133

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’

134

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.