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Logging While Drilling Interpretation Training Package

United Kingdom Training Centre, UK

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ABSTRACT

Background With the dramatic increase in Drilling and Measurements activity around the globe there has been a large increase in the number of Logging While Drilling (LWD) personnel. Although it is crucial for each of these students to be trained on certain aspects of our operations, it is becoming increasingly difficult to fulfil all of the training requirements at the training centres because of the large volume of students to be trained, the demanding field requirements for rig-site personnel, and limitations on the number of places at schools. D&M may be able to reduce this load on the training centres by providing Engineers in the field with training material in the form of Learning Packages that can educate on important topics while they are at the rig site or in the base.

It is vital that the Logging While Drilling Engineers have a good understanding of log interpretation, as this will help them to be able to provide a superior quality of data to the client and also display a level of knowledge to the client that is able to portray a good image of Schlumberger Logging While Drilling.

Main Objective The primary objective of this documentation is to provide Logging While Drilling Engineers with a Log Interpretation Package that will act as a good reference as well as providing a solid training material package for Engineers in the field. This information can be considered as a modular Learning Package that follows a logical process, starting with the measurement environment, through to more complex interpretation issues that are dealt with by the client.

The modular format will allow students at different levels of understanding of LWD Interpretation to use only those sections that are relevant.

At present it is rather confusing for an engineer to try to get the big picture about log interpretation. Although Archie and Shaly Sand Interpretation SLPs exist, they do not tie very well into one another, nor into the rest of the picture of Log Interpretation and Quality Control. Very little relevant information exists for the ADN and there is no training material available for the interpretation of carbonate reservoirs, which happens to be a major growth area in the near future. By incorporating the material described in the index on the next page, we hope that engineers are able to gain an understanding of the material before coming to the school, allowing for more effective training at the training at the centres and possibly even a reduction of training days, or reallocation of time to topics like drilling mechanics and cell manager workshops.

Quantifiable Results

▪ Provision of a Learning Package that will assist LWD Engineers in their understanding of Interpretation issues.

▪ A ground breaking approach to training for LWD Interpretation that should help to enable LWD Interpretation to not only be a taught subject when students come to school but rather more of a question an answer session as students should already be aware of the basics.

Value The new Self Learning Packages will;

▪ Reduce the required training time and assist in the move towards e-learning, where appropriate. ▪ The existing documentation is in need of revision, this document will deal with areas that are lacking and

require updating. ▪ Provide students with a systematic approach to Log Interpretation. ▪ Assist Engineers in their understanding of Log Interpretation so that they are able to not only present a

more informed approach to the client but also improve the quality of Schlumberger Logging While Drilling Services.

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Table of Contents ABSTRACT............................................................................................................................. ...... 2

Table of Contents .......................................................................................................................... 3

Part-I Log Interpretation ......................................................................................................... ........ 6

Introduction ............................................................................................................................. ...... 7

1. The Gamma Ray Log ................................................................................................................. 8

1.1 The Gamma Ray Reading..................................................................................................... 8

1.1.1Plateau Gamma Ray .................................................................................................... 10

1.1.2 Spectral Gamma Ray................................................................................................... 10

1.2 Corrections to GR .............................................................................................................. 11

1.3 Gamma Ray Applications.................................................................................................... 11

1.3.1 Correlation .................................................................................................................. 11

1.3.2 Shale Zone Indication .................................................................................................. 13

1.3.3 Interpretation of Depositional Environment..................................................................... 13

1.4 Shaliness Determination ..................................................................................................... 14

1.5 Composition and Distribution of Shales ................................................................................ 16

1.6 Measurement Anomalies .................................................................................................... 18

1.6.1 Back reaming with Radioactive Sources ........................................................................ 18

1.6.2 Real Time and Recorded Mode Discrepancies............................................................... 19

Review Questions.................................................................................................................... 21

2. Resistivity............................................................................................................................. ... 22

2.1 The Resistivity Reading ...................................................................................................... 22

2.1.1 Electromagnetic Induction ............................................................................................ 23

2.1.2 Laterolog Resistivity Tools............................................................................................ 24

2.2 Invasion ............................................................................................................................ 25

2.2.1 Terminology ................................................................................................................ 25

2.2.2 Invasion Profiles .......................................................................................................... 26

2.2.3 Depth of Invasion ........................................................................................................ 26

2.2.4 Effects of Invasion on LWD Measurements.................................................................... 28

2.3 Depth of Investigation and Vertical Resolution ...................................................................... 29

2.4 Logarithmic Scales ............................................................................................................. 30

2.5 Curve Separation ............................................................................................................... 31

2.5.1 High Dielectric............................................................................................................. 32

2.5.2 Conductive Invasion .................................................................................................... 33

2.5.3 Resistive Shoulder....................................................................................................... 34

2.5.4 Resistivity Anisotropy................................................................................................... 35

2.5.5 Resistive Invasion ....................................................................................................... 37

2.5.6 Conductive Shoulder ................................................................................................... 38

2.5.7 OBM Drilling-Deep Fractures........................................................................................ 38

2.5.8 OBM Drilling-Shallow Fractures .................................................................................... 39

2.5.9 Eccentering................................................................................................................. 40

2.5.10 Polarization Horns ..................................................................................................... 41

2.5.11 Measurement Limitations ........................................................................................... 43

2.6 Corrections to Resistivity Readings...................................................................................... 44

2.6.1 Electromagnetic Resistivity Corrections ......................................................................... 44

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2.6.2 Laterolog Resistivity Corrections ................................................................................... 44

2.7 Applications of Resistivity Logs............................................................................................ 44

2.7.1 Qualitative Analysis ..................................................................................................... 44

2.7.2 Quantitative Analysis ................................................................................................... 45

2.7.3 Correlation .................................................................................................................. 46

2.7.4 Estimate Pore Pressure ............................................................................................... 46

2.7.5 Invasion Identification .................................................................................................. 46

2.7.6 Geosteering ................................................................................................................ 47

2.8 Archies Equation ................................................................................................................ 47

2.8.1 Need for Archies Equation................................................................................................ 48

2.8.2 Definitions....................................................................................................................... 48

2.8.3 Derivation of Archies Equation...................................................................................... 49

2.8.4 Calculation of RW ....................................................................................................... 52

2.8.5 Quick Look Calculation ................................................................................................ 53

2.8.6 Limitations of Archies Equation ..................................................................................... 53

2.8.7 Worked Example of Archies Equation............................................................................ 53

2.9 Review Questions .......................................................................................................... 56

3. Density and Porosity ................................................................................................................ 57

3.1 Reservoir Analysis ............................................................................................................. 58

3.1.1 Shale Caprock ............................................................................................................ 58

3.1.2 Gas Zone.................................................................................................................... 58

3.1.3 Oil Zone...................................................................................................................... 59

3.1.4 Wet Zone.................................................................................................................... 59

3.2 Density............................................................................................................................. . 60

3.3 Porosity..................................................................................................................... ........ 61

3.3.1 Neutron Porosity ......................................................................................................... 61

3.3.2 Density Porosity .......................................................................................................... 63

3.4 Nuclear Scales................................................................................................................... 65

3.4.1 Compatible Scales........................................................................................................... 65

3.4.2 Shifted Compatible Scales ............................................................................................... 66

3.5 Corrections to Neutron Porosity ........................................................................................... 67

3.5.1 Environmental Corrections ........................................................................................... 68

3.5.2 Eccentering Correction................................................................................................. 70

3.6 Density Corrections ............................................................................................................ 70

3.7 Density Image Interpretation ........................................................................................... 74

3.8 Review Questions .............................................................................................................. 81

4. Lithology Identification .............................................................................................................. 82

4.1 PEF Measurement ............................................................................................................. 82

4.2 Log Identification ................................................................................................................ 82

Part-II Advanced Interpretation .............................................................................................. 83

5. Reservoir Analysis ................................................................................................................... 84

5.1 Sandstone Reservoirs ........................................................................................................ 84

5.1.1 Composition................................................................................................................ 84

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5.1.2 Sandstone Depositional Environment ............................................................................ 87

5.1.3 Sandstone Log Interpretation Topics ............................................................................. 90

5.2 Carbonate Reservoirs......................................................................................................... 92

5.2.1 Carbonate Composition ............................................................................................... 92

5.2.2 Limestone Depositional Environment ............................................................................ 94

5.2.3 Limestone Log Interpretation Topics.............................................................................. 94

6. Crossplots ............................................................................................................................. .. 99

6.1. Effective Porosity Determination I ..................................................................................... .. 99

6.2 Effective Porosity Determination II ..................................................................................... 102

6.3 Permeability Estimation .................................................................................................... 103

7. Recoverable Hydrocarbon Estimation ...................................................................................... 105

7.1 Reservoir Thickness Calculations ...................................................................................... 105

7.2 Reservoir Area................................................................................................................. 106

7.3 Recoverable Oil Estimation ............................................................................................... 106

7.4 Recoverable Gas Estimation ............................................................................................. 107

Answers............................................................................................................................. ....... 108

Acknowledgements....................................................................................................... ............. 111

References ............................................................................................................................. .. 112

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Logging While Drilling Interpretation Training Package

United Kingdom Training Centre, UK

Part-I Log Interpretation

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Introduction

Logging while Drilling (LWD) data is capable of providing a means for the client to determine the location and quality of reservoirs within a wellbore, whilst the well is being drilled. This data will allow them not only to determine how profitable a well may be, but also make real-time steering decisions based on the LWD data while drilling is in progress. Although many of the borehole measurements are derived from Wireline technology, there are a few differences between the measurements made by Wireline and LWD logging that LWD Engineers should be aware of before commencing with operations.

LWD Engineers should have a good understanding of log interpretation to assist in their ability to Quality Control Logs that are produced in real time and recorded mode. This will help them to be able to provide a superior quality of data to the client and also display a level of knowledge to the client that is able to portray a good image of Schlumberger Logging While Drilling.

This manual is intended to provide LWD engineers with a training manual to assist in their understanding of the Interpretation of LWD Logs. It is not intended to be a step by step guide to LWD operations, but rather provide a big picture approach to LWD, from an Interpretation standpoint. The package has been divided into two sections;

▪ Basic Interpretation modules provide an introduction to LWD interpretation for new Engineers. ▪ Advanced Interpretation modules are intended for those that already have a basic knowledge

of interpretation. It will help to introduce engineers to the client‟s perspective of Log Interpretation.

Schlumberger LWD is able to provide high quality real time and recorded mode data to the clients. Real Time Data is very valuable to the client as it allows decisions to be made regarding the drilling of the well, whilst it is being drilled. This information is available, not only to geologists on the rig-site, but also to top executives sitting in Head Quarters around the globe through the use of InterACT* (Secure Broadcasting of Data from the wellsite by means of satellite transmission).

Real Time decisions may include;

▪ Geosteering options which could maximize the length of wellbore placed within the pay zone, allowing for increased production

▪ Core Point/Casing Point Identification. ▪ Drilling Optimization ▪ Real Time Update of Geological Models ▪ Hydrocarbon Zone Identification

Recorded mode (RM) logs are able to provide the client with information that may not have been critical to the client whilst drilling the well but may be important to the post well analysis. It also presents data at a higher data density than that which was available in real time.

LWD currently has a large number of measurements on offer to clients, although, none of which can be used in isolation. The client will need to consider a number of different measurements before they are able to fully understand a well. To allow for a better understanding of each of the measurements, they will be discussed individually. However, the big picture should not be forgotten, as the real value lies with the readings complementing one another.

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1. The Gamma Ray Log

Gamma Ray (GR) logs were not used during the early days of wireline logging but were introduced in 1940, after which they very quickly became a commonly run service. Gamma rays have a reasonable ability to penetrate through materials, which makes them an ideal candidate for the logging of natural radiation in the well bore because the gamma rays can travel not only through the formation itself (from within a few inches of the wellbore) and through the mud, but can even penetrate through the metal components of the tools before being detected by the measurement hardware.

Gamma Rays are a form of energy that is released by elements in the formation (predominantly, thorium, potassium and uranium) as a result of their radioactive decay.

The quantity of gamma rays released by the formation increases in accordance with the proportion of organic material in the rock. This is true in nearly all situations, with the exception of formations known as „hot sands‟, which will be discussed later on in this section. As a result, shales typically have a very high gamma ray reading while reservoir rocks (such as sandstone and limestone) tend to have very low gamma ray readings. The predominant radioactive materials in the formation have very long half lives (the time taken for half the number of atoms to undergo radioactive decay, which releases GR in the process), which is why they are still emitting gamma rays today (thorium‟s half life is said to be about three times more than the approximate age of the earth).

Thorium Half-life- 1.405×1010 years Potassium Half-life- 1.277×109 years Uranium Half-life- 4.468×109 years

These elements are the most abundant radioactive elements that can be found in the earths crust. They emit gamma rays into their surroundings continuously; these radioactive elements are concentrated in certain formations, most commonly in shales. It is due to the selective accumulation of radioactive elements in these formations that gives value to a Gamma Ray Log as a formation evaluation tool.

1.1 The Gamma Ray Reading

Gamma Rays are recorded by means of a scintillation detector. This detector records the number of gamma rays in counts per second (cps), where the number of counts is directly proportional to the quantity of gamma rays entering the detector. Before the GR reading can be presented, it will need to be configured by applying the corrections shown in figure 1.1.

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Figure 1.1: GR Conversion from Counts to API.

gAPI is the unit that is used to present the GR measurement. It stands for Gamma Ray American Petroleum Institute Units, where one unit is defined as being 1/200 of the response received when logging through the calibration blocks at the University of Houston, where the block is composed of a known quantity of Thorium, Uranium and Potassium. The unit gAPI is used to draw a standard between all logging tools in the industry as the counts received for a wireline tool will not necessarily be the same as those received by an LWD tools due to differences in their construction (detector size, collar thickness etc.). By presenting gamma ray measurements in terms of gAPI, a comparison between different types of GR logging tools is possible, although they are not always the same due to differences in the logging environment and the nature in which the measurement is recorded.

Typically Gamma Ray information will be presented as GR_ARC in Recorded Mode and ARC_GR_RT

in real time (when using an ARC tool). There are two types of GR logs that can be produced, Plateau Gamma Ray and Spectral Gamma Ray. Each of these will be discussed in more detail.

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1.1.1Plateau Gamma Ray

Plateau GR logs represent the total number of counts that are received by the GR sensor, irrespective of the energy of the incoming gamma rays. The more counts that are received at the detector, the higher the gamma ray reading that is presented on the log.

Individual Formations can be identified from their GR reading, shales are characteristic of high gamma rays while clean carbonates and sands have low GR readings. Values lying in between these extremes are either a mixture of shale and sand or a different type of shale that contains different quantities of radioactive elements.

The Plateau GR measurement is sufficient for the evaluation of the majority of wells as it allows geologists to identify regions of different gamma ray intensity. There are however, certain limitations to the plateau measurement, which is why the spectral GR log was introduced.

1.1.2 Spectral Gamma Ray

Spectral GR tools operate in much the same way as Plateau GR. However, they are able to discriminate between the gamma rays that are received from each type of element (Potassium, Thorium and Uranium). This is a specialized gamma ray reading that is required because of the presence of Uranium in certain formations. Uranium salts are soluble in water and tend to accumulate in porous zones (e.g. sandstone, limestone). These zones are often referred to as „Hot Sands‟. On a plateau GR log, such a zone would appear more like shale than porous sand or carbonate zone due to the high number of gamma rays being emitted by the Uranium.

Each GR has a specific energy level that depends on the type of element that it was released from. When using a spectral GR detector, it is possible to detect the energy level of each gamma ray. This is possible due to the energy of the incoming GR being directly proportional to the intensity of the energy pulse recorded by the tool (refer to OIL CD for further information on the operation of the Scintillation Detector). This allows the tool to determine the number of counts received for each of the elements, Potassium, Thorium and Uranium individually.

A spectral GR log is able to provide the GR readings for each of the elements that emit gamma rays. One of the reasons for running a spectral gamma ray tool is to identify the location of radioactive sands (which contain Uranium). Hot sands can now be identified by the unusually high contribution of gamma rays from Uranium, and low contributions from Potassium and Thorium. This log consists of a GR curve that is a combination of counts received from gamma ray emitted by Thorium and Potassium, correcting for the misleading high readings from the presence of Uranium.

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1.2 Corrections to GR

Drilling and Measurements makes the following corrections to GR

Bit Size

Tool Size

Mud weight

Potassium Content (of mud) The bit size and tool size are taken from the BHA that is entered into IDEAL. Mud Weight and potassium content are taken from the Real Time (RT) Parameters and Recorded Mode (RM) Parameters for RT and RM processing in IDEAL.

Mud Weight and Potassium content are taken from RT and RM parameters.

The corrections will have the following effect on the GR reading;

Increased Bit Size => Increased correction and GR Reading Increased Tool Size => Increased correction and Increased GR Reading Increased Mud Weight => Increased GR Reading Increased Potassium Content => Decreased GR Reading

1.3 Gamma Ray Applications

The GR log is very versatile in the industry as it is a passive reading that can be used in a wide range of environments (air, OBM, WBM, open hole and behind casing). There are a number of specific applications that make it very useful; these will be discussed in a bit more detail.

1.3.1 Correlation

Gamma ray logs are able to provide a reliable comparison between wells that are drilled in close proximity to one another. Geologists often use this curve to detect geological markers while drilling that are anticipated at certain points in the well. This helps them to orientate their geological models to the data that is seen in the well and as a result, forecast casing points, core points, reservoir depths and landing points.

Gamma ray Logs are also useful to help engineers to tie in data measured on different logging runs as they are able to match up the curve response on the individual runs (see Fig.1.2).

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Figure 1.2: Correlation between Current Well and Offset Well The example shown in figure 1.2 demonstrates how a GR log can be used to correlate data between adjacent wells (GR Filtered is shown here, this should only be presented to clients that request it). When using any curve to correlate data between different wells a TVD log must be used as the data is presented irrespective of the well profile. This will allow comparisons to be made between the wells.

In the example shown, two correlations have been drawn. The first correlation is at 8040ft TVD on the current well, where a GR peak of 36GAPI is displayed. On the correlation log (offset well), the same peak appears 5 feet higher and has the same magnitude. The second correlation is drawn at 8096ft TVD on the current well, which has a peak value of 70GAPI. The corresponding peak on the offset well is 4 feet higher and has a slightly higher GR reading. Notice that the baseline of both these logs are reading around the 105GAPI line, which should be expected as they are from wells drilled in close proximity to one another.

A conclusion could be drawn from this section of log that the formation tops (correlations) are coming in at around 4 feet TVD deeper in the current well than on the correlation log. This information would allow both drilling and geology departments to be able to make accurate decisions regarding the setting of casing points and determining the correct total depth (TD) as they will have the information from the offset well available to them

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1.3.2 Shale Zone Indication

Shales contain high quantities of radioactive elements, resulting in high gamma ray readings in shale zones. Reservoir zones are not usually associated with high gamma rays. Geologists are able to make a quick analysis of the zones of interest in a well just by looking at the gamma ray reading, high readings being of little interest while low readings may attract more attention as the may be potential pay zones.

Upper Shale Zone

Sand Zone

Interbedded Zone

Figure 1.3: Shale Zone Identification by means of GR.

Figure 1.3 demonstrates how shale zones can be identified by their high gamma ray readings, whilst sand zones can be identified by their low gamma ray readings. The „ratty‟ sections at the bottom of the Upper Shale zone and in the interbedded zone are alternating layers of shale and sand.

1.3.3 Interpretation of Depositional Environment

Gamma ray logs can be very useful to a geologist, providing clues which may relate to the depositional environment in which the formation was laid down. An example of this is a “bell shaped” gamma ray log, which could be associated with a maritime depositional environment where sea levels were rising (e.g. at the end of an ice age).

Larger particles require a lot of water turbulence to be transported. For this reason, as soon as a river enters a lake or the ocean the courser material will be deposited first. The lighter materials that would eventually form shale would be transported further out into the water body before they are laid down as sediment. So heavier sand grains would be deposited near the mouth of a river. As sea levels rise, the river mouth will retreat along with the rising shoreline, resulting in only lighter material, which contains more radioactive materials to be laid down. This would be a gradual transition from sand deposition to shale deposition.

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1.4 Shaliness Determination

Gamma Ray logs can be used on a quantitative basis to determine the volume of shale/clay in a formation. Shales have a major impact on certain measurements, as will be discussed in the relevant section (neutron porosity), it is for this reason necessary to determine the quantity of shale in the formation so that the appropriate corrections can be applied to remove the effect that shale has on the measurement.

Figure 1.4 Lithology Identification using GR

The gamma ray log is able to provide the Geologist with a good idea of how much shale there is in each

zone. The highest gamma ray reading is commonly referred to as GRMin , which is associated with a

formation that is 100% shale. The lowest gamma ray reading would be associated with formation that is 100% clean sand (or limestone). Anything in between would be considered a mixture of shale and sand (or limestone).

Shale is an impermeable sedimentary rock that has a major impact on drilling and the production of oil. For this reason it is necessary that a closer look is made at the composition and effects of shale and also to be able to quantify the shale in the formation.

The Volume of Shale in a formation can be defined as being the combined volume of clay and silt;

VSh VSilt VClay

The volume of shale can be calculated from a log by making the following definitions;

GRClean GR reading in Shale Free Zone (Reservoir)= GRMin

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GRShale GR reading in Shale Zone= GRMax

GRLog GR reading at point on Log at which Shale Volume Calculation is made.

GRLog GRClean (Linear Shale Volume Equation)

VShale

GRShale

GRClean

Using the values from the log shown in figure 1.4 and calculating the VSh in the Shaly Sand Zone;

GRClean 15GAPI

GRShale 135GAPI

GRLog 68GAPI

VShale 68 15

135 15

0.44

The calculation shown above assumes a direct relationship between the volume of shale and the GR reading, this is however, not always the case, and more accurate methods are available, each of which are suited to specific situations. Figure 1.5 shows a number of the calculation techniques that are

available and how their results would plot on a plot of VShale vs. GR reading (where 1 means that the

gamma ray reading is that obtained in shale, and 0 in the clean zone. Only three equations are discussed in this document, although there are more equations available.

Linear Equation: The linear method assumes a direct relationship between VShale and the GR reading.

The calculation is relatively simple, as has been illustrated above, although it is not very accurate. Steiber Equation: The Steiber equation was developed specifically for Miocene and Pliocene

sediments in South Louisiana, although it has been used to accurately calculate

formations in other parts of the world. It uses the equation;

VShale in similar

VShale 0.5x

1.5 x

Steiber equation

x= GR deflection, as shown on the x axis of figure 1.5. This can be calculated from;

GRLog

x GRShale

Larionov Equation: The Larionov Equation was developed for older rock types. There are two forms of this equation;

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VShale

VShale

0.33 2 2 x 1

0.083 23.7 x

1

Larionov Equation-Older Rocks

Larionov Equation-Tertiary Rocks

Figure 1.5: Shale Volume Calculation Techniques

1.5 Composition and Distribution of Shales

Shale is a rock that is commonly encountered in oil and gas wells, although it is more commonly associated with sand reservoirs than limestone reservoirs due to the depositional environment..

Shales are made up of a mixture of clay, silt, minerals and carbonates in varying quantities and structural arrangements. What is common to most shales however is that they are made up of very small particles that tend to be structured in such a way that the shale itself will not be very permeable, which will greatly influence reservoir characteristics, depending on how the shale is distributed in the reservoir.

The distribution of shales in reservoir sands will have a major impact on the ability of the reservoir to flow and produce oil. Figure 1.6 shows examples of a few types of shale distributed amongst sand particles.

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Figure1.6: Shale Distribution (Shaly Sand SLP) Clean Sand: Sand Reservoirs that are made up of clean sand or shale free zones will not be affected

by shale. These zones will have a GR reading that will be known as the Clean Sand GR Reading (

GRMin ).

Laminar Shale: Laminar shales will have a major impact on the flow characteristics of a reservoir. Shales are relatively impermeable due to the small and tightly packed particles that make up the rock. When placed in layers (laminations) within reservoirs they are able to greatly reduce the ability of the reservoir to flow and may even isolate one section of a reservoir from another and entirely stop any flow between the two sections.

Structural Shale: Structural Shales exist as separate particles of shale that will accommodate certain areas of the reservoir but will have far less effect on the flow characteristics of the reservoir. The effective Porosity is essentially unaltered.

Dispersed Shale: Dispersed Shale will occupy inter-granular spaces between sand particles in a reservoir. This type of shale will reduce the porosity and also reduce the permeability (ease with which fluids will flow through the formation) of the reservoir.

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Shales will also have a major affect on other LWD measurements. This will be discussed in more detail in the relevant sections.

1.6 Measurement Anomalies

Gamma Ray Logs are essentially very simple to interpret, however there are a few considerations for LWD operations.

1.6.1 Back reaming with Radioactive Sources

When a radioactive source is run in the BHA care should be taken when back reaming for LWD data on the trip out of the hole. The reason for this is that the source is continuously firing neutrons into the formation. This activates the formation when it is held stationary in any particular position for an extended period of time, such as during the breaking of a connection. This is only a problem when back reaming out of the hole as the radioactive source is positioned above the GR sensor.

Atoms in the area where the radioactive source was held stationary will become excited and will themselves release gamma rays for a few minutes until they return to their base state. The gamma ray sensor is positioned below the neutron source, so when pulling upwards the sensor will pass the point at which the activation occurred and subsequently report a higher reading than was shown on the trip in or whilst drilling. This anomaly will make correlation a bit more complex when logging out of the hole with a radioactive source. It is important to bring the issue to the attention of the wellsite geologist.

The intensity of the peak that appears on the GR log is proportional to the time during which the neutron source was stationary adjacent to the formation. It is also dependant on the time since the source was next to the formation as well as the types of elements in the formation as some are more readily excited than others.

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Drilling Reaming out of Hole Figure 1.7: Activation from Radioactive Source

The GR peak in the repeat log of figure1.7 is an example of the activation of the formation. A useful QC curve to display in combination with repeat section logs is the RPM curve, as shown in figure 1.7. The GR peak shown on the repeat section coincides with a zero rpm spike, which is characteristic of connections whilst reaming out of hole, and also positions where the neutron source was held stationary during the connection, causing activation of the formation. These GR peaks will repeat every 90ft, when working on a rig with triplet stands of drillpipe.

1.6.2 Real Time and Recorded Mode Discrepancies

It is possible for the information from Real Time and Recorded Mode to have discrepancies. These discrepancies can either be in terms of data being at different depths or the logs displayed are reading different values.

Discrepancies between Real Time and Recorded Mode where the depth does not match up (the GR reading is different but the shape is the same) are most commonly associated with Depth file problems. Remaking the depth file and also checking that the correct BHA is entered whilst processing the logs should have positive results.

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Discrepancies in terms of the value displayed on the log can either be caused by different environmental processing parameters, incorrect calibration and possibly the wrong scale factors used in programming the tools.

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Review Questions

1. What is the unit used in displaying GR on a log? 2. What are the primary elements that contribute to natural GR? 3. ARC GR is corrected for which Environmental effects? 4. Two types of GR sensors are available in LWD, which of these is used in the ARC tool? 5. Name 5 applications of the GR curve? 6. How is the Recorded Mode Channel GR_ARC attained from the counts received at the GR

scintillation detectors? 7. What is the purpose of calculating VSH? 8. Write out the form of the liner VSH calculation?

Answers at the end of the document.

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2. Resistivity

Resistivity measurements were first introduced by the Schlumberger brothers in 1928 whilst prospecting for metal ores in France. Their Experimental work began in their bathtub, filled with an assortment of rocks and later. Those early experiments developed into field tests around Europe and North Africa, but very rapidly developed as the value of Resistivity logs was realized by industry. By 1929, commercial electric logs were being run in the United States, Venezuela, Russia and the Dutch East Indies.

The first Schlumberger Log, was run in 1927 in Pechelbronn, northeastern France, it consisted simply of a Resistivity Log, as shown in figure 2.1.

The Resistivity log is a fundamental measurement in the oilfield, because hydrocarbons are very poor at conducting electric current, whilst formation water conducts electricity much better (although this will depend on the quantity of dissolved salts in the formation water, which leads back to the depositional environment).

Hydrocarbon Zones are characterized as areas of high resistivity as oil and gas do not conduct electricity. However, a high Resistivity is not always associated with Hydrocarbons because resistivity is not only dependant on the fluid filling the porous spaces of the formation but also on how well connected the fluid in the pore spaces are.

For this reason, a simple GR and Resistivity Log is insufficient to definitively determine the location of a hydrocarbon reservoir.

Figure 2.1: First Resistivity Log and also First Schlumberger Log

Resistivity logs play a vital role in quantitative analysis, which allows the client to determine the quantity of hydrocarbons in a reservoir. That information will be used to determine the future development of the reservoir and ultimately, also the value of the operating companies themselves as banks will be far more willing to loan money to a company that has proven reserves of oil.

2.1 The Resistivity Reading

The aim of running resistivity tools is to determine the uninvaded zone resistivity, RT. This would be a simple matter should one be able to measure the resistivity across a block of the formation, as one would do with a multimeter. However, the situation in a wellbore is a little more complex as the tool that

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will be doing the measurements is placed inside a wellbore that is surrounded by mud, and then formation that may have had a certain amount of mud invading into the pores of the rock, which would not have the desired RT value of the uninvaded formation.

Resistivity is the term used to refer to how well a formation will conduct electricity, it can be related to resistance by;

A

R r L

Where: R Re sistivityOHMM r Re sis tan ce(OHM )

A Aream 2

L Lengthm The value for r is calculated from the tools measurement, A/L, is merely a geometric correction that is derived from a computer model. The product of these two is represented as Resistivity.

Dry rock is essentially a non conductive material which would have a resistivity reading of infinity. The ability for a formation to conduct electricity is derived from the water that is contained in the pore spaces of the rock (except for a few situations where conductive metal ores can be found). Although the Resistivity is dependant on the water content of the rock, it is also dependant on the pore structure of the rock (how well connected the formation water is).

There are two types of resistivity logs that are in use in Schlumberger, Electromagnetic induction and Laterolog Resistivity Logs. These will be discussed in further detail in separate sections.

2.1.1 Electromagnetic Induction

Electromagnetic induction tools measure the resistivity of the formation by inducing a current in the formation surrounding the tool by means of an electromagnetic wave. As the current flows through the formation it undergoes two changes, which are detected at the receivers as phase shift and attenuation readings The phase shift and attenuation measurements are dependant on two factors of the formation, dielectric effect and the formation resistivity. At this point, an important assumption is made that the dielectric effect can be approached as a function of the formation resistivity (this is not true at high resistivities).

The phase shift and attenuation readings are then converted into resistivity readings through the use of transform charts, which were obtained by means of empirical methods (experiments). The results of these transforms are the phase shift resistivity and attenuation resistivity readings that are presented on our LWD logs.

The primary difference between phase shift Resistivity and Attenuation Resistivity is that Attenuation Resistivity is a deeper reading measurement.

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2.1.2 Laterolog Resistivity Tools

Laterolog tools pass a current through the drillstring and out through the bit into the formation, returning to the tool at some point above the Laterolog tool. Ohms law is used to determine what the Resistance is. A geometric factor is then taken into account, providing the formation Resistivity.

V = I x R Where; V=Voltage reading of the tool

I= Current that is flowing. R=Resistance

The bit acts as an electrode when using laterolog Resistivity tools. As the bit passes into a resistive zone, less current is able to flow, so a low formation Resistivity is assumed. As a conductive zone is entered, more current is able to flow, which is interpreted as a lower formation Resistivity.

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2.2 Invasion

Invasion is the term used to refer to the movement of mud filtrate from the wellbore, into the surrounding formation. This movement occurs due to the overbalanced drilling environment that is used to avoid wellbore fluids from entering into the wellbore and causing a kick. This invasion of mud filtrate will then have an influence on the Resistivity measurements that are made during logging operations.

2.2.1 Terminology

It is important that everyone in the industry is able to communicate with one another, for this reason, the following definitions have been made to refer to the wellbore environment:

Rm =Mud Resistivity

Rmc =Mud Cake Resistivity

Rxo =Resistivity of Invaded

Zone

Rmf =Resistivity of Mud

Filtrate

Rs =Resistivity of Adjacent

be

Rw =Wet Zone Resistivity

Rt =Uninvaded Zone

Resistivity

S xo =Water saturation of

invaded zone.

Sw =Water saturation of

uninvaded formation.

Figure 2.2: Wellbore Environment Terminology

Invasion occurs in formations that allow fluids to move (i.e. permeable formations). It is usually more common in reservoirs (low GR readings). Resistivity tools, commonly record resistivity data from a number of different depths of investigation. Those readings that are taken closer to the wellbore would be influenced more by the effects of invasion than deeper readings.

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2.2.2 Invasion Profiles

The invasion of mud filtrate causes a change in the Resistivity of the formation around the wellbore due to the displacement of formation fluids in the rock, with mud filtrate that has filtered through the mudcake. The Resistivity will either increase, or decrease, depending on what type of mud system is being used.

Water Based Mud (WBM)

A WBM system will cause a decrease in the Resistivity of the formation, provided that RT > Rmf . In a

wet zone, where the resistivity of the formation is the same as the mud resistivity, an increased resistivity will be noticeable for the mud cake and crossover zone resistivities, although this would only be a slight increase.

Oil Based Mud (OBM)

OBM invasion profiles cause an increase in Resistivity, predominantly in the shallower reading resistivities.

2.2.3 Depth of Invasion

The depth to which invasion occurs is dependant on the porosity of the formation. This is due to the process through which mud cake is built up on the borehole wall. Mud cake is built along the wall of the borehole due to the filtering out of the solids in the mud as mud filtrate moves into the formation. As the mudcake builds up, it starts to form a barrier that becomes increasingly impermeable for further invasion, until eventually, no further invasion can take place. For the mud cake to build up to the required thickness for no further invasion, a certain amount of filtrate would have had to have moved into the formation, this fluid would occupy the pore spaces in the formation, so the fluid would have to invade further in formations that have a low porosity.

Invasion is a process that will take place over a period of time. The speed with which it occurs is dependant on the permeability of the formation (how well fluid can travel through the formation) and also the amount of overpressure forcing mud filtrate into the formation. LWD Resistivity measurements are made soon after the formation has been drilled, when mud filtrate invasion is still a dynamic process (unlike wireline which is done a few days after drilling, when the invasion profile has usually reached its full extent). It is thus very beneficial to the understanding of log anomalies to make repeat passes over zones of interest to identify the development of the invasion profiles.

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Drilling Reaming

Figure 2.3: Effects of Invasion over time. The well shown in figure 2.3 was drilled through a gas zone in the section shown, using an OBM mud system. The GR and Resistivity log on the left was recorded whilst drilling the well. The data was processed in ARC Wizard using invasion inversion (more about this later), providing, Rt which is the uninvaded zone resistivity and Rxo the invaded zone resistivity. A repeat pass was done over the same section, and is shown on the far right of the figure.

The repeat section was done a number of hours after drilling the well, allowing for a period of time for invasion to occur before the repeat pass was done on the right. Notice how the resistivity readings have all moved to lower resistivity values although Rt, the calculated formation resistivity, still reads the same as it did in the drilling pass.

Invasion inversion also calculates the Depth of Investigation (DOI), to which the invaded zone has progressed. The middle section of figure 2.3 presents the calculated DOI for the drilling log (blue) and also the reaming log (red). The wellbore is shown as the black line down the middle of the track.

The pink shaded area is the difference in the DOI between drilling and reaming, indicating a deep invasion profile movement between the drilling and reaming of this well.

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2.2.4 Effects of Invasion on LWD Measurements

Mud invasion affects the shallower reading resistivities the most, with deeper reading resistivities being affected less due to their deeper depths of investigation.

The log shown in figure 2.4 is a good example of the application of a repeat log, On the drilling log (centre track), there appears to be a small amount of invasion as the P10H and P16H curves read lower than the deeper reading resistivity curves. This is most pronounced below 8800ft. The repeat log, taken some time after drilling the section, shows even further invasion, with the P10H curve now reading almost 10ohmm less than it did previously. The P16H also shows a 10ohmm reduction. The repeat section also shows a reduction in the Resistivity of the P10H curve along the majority of the sand section, indicating invasion along the entire length, although not that deep.

Drilling Repeat

Figure 2.4: Water Based Mud Invasion Profile

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2.3 Depth of Investigation and Vertical Resolution

It may appear that the deeper readings would provide the most accurate approach towards the Uninvaded zone Resistivity, RT. This is not always the case. Each of the readings provided by the tools help in the interpretation of RT, as each will have a different Vertical Resolution and Depth of Investigation, although there are benefits and shortfalls for each type of resistivity curve.

Depth of investigation: The distance from the wellbore wall within which the tool receives 50% of its signal. The remaining 50% is influenced by the area beyond the depth of investigation. Those readings with greater depths of investigation would be less affected by the wellbore.

Curve Depth of Investigation follows the following basic rules:

Attenuation Resistivity has a deeper depth of investigation, simply because it is a slightly more

focused measurement that Phase Shift attenuation and as a result is able to travel deeper into the formation, as shown in figure 2.5.

2MHz (High Frequency) readings have Shallower Depth of Investigation than 400kHz

Shorter spaced transmitters have Shallower Depth of Investigation.

Depth of Investigation increases with an increase in RT.

Vertical Resolution: Vertical Resolution is the thickness that a formation bed would need to be before the desired tool response can be attained. Two terms that are referred to in terms of Vertical Response are Qualitative and Quantitative resolution.

Qualitative Resolution is the thickness of a formation bed at which the tool will first start to show.

Quantitative Resolution is the thickness that a bed would need to be, for the tool to be able to read to at least 90% of the Formation Resistivity.

Figure 2.5: Depth of Investigation for Phase and Attenuation Resistivities

Depth of Investigation is influenced by the following rules (an increase in Vertical Resolution is referred to as a poorer response):

Attenuation Resistivity has a poorer Vertical Resolution than Phase Shift Resistivity.

400kHz (Low Frequency) has a poorer Vertical Resolution than 2MHz (High Frequency).

Vertical Resolution becomes poorer with increased transmitter spacing.

Vertical Resolution becomes poorer with an increase in RT

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Figure 2.6: Vertical Resolution of Phase and Attenuation Resistivities.

2.4 Logarithmic Scales

Resistivity Curves are presented on Logarithmic Scales, as shown in Figure 2.7, these are used to enable a large range of data to be presented on a manageable range. It does this by compressing data towards the end of each decade (a decade is made up of ten divisions, in Figure 2.7, one decade would start at 0.2 through to 2), making features on the logs easy to identify.

Figure 2.7: Logarithmic Scales

Figure 2.7 shows the readings at the bottom of the log for a log scale of 0.2 to 2000. The scale shown here is widely used, although some clients will request scales of 0.2 to 200 or 0.2 to 20. When changing the log scales, it is important to ensure that the number of decades corresponds with the scales put on the log. In the Figure 2.7 there are four decades, which correspond to the scale shown. However, for every zero that we remove from the log scale, one decade has to be omitted. For a scale of 0.2 to 20, only two decades will be presented. An easy way to check if the number of decades corresponds to the scale used is to count each line from the starting scale to the end, which should correspond to your end scale reading.

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2.5 Curve Separation

When using Resistivity tools it is a common practice to use measurements of different depths of investigation to provide an approach to what Rt may actually be. Both the Laterolog and Induction tools are able to provide more than one resistivity reading, each reading has its own depth of investigation. In the ideal situation all these measurements would read the same value. However, the area around the wellbore may be affected by the wellbore and fluids within the wellbore, and as a result deeper readings will often be more representative of the unaltered formation resistivity. Although in thin beds, where the volume of investigation of the deep readings may be high, the deep readings may never come close to the formation Resistivity as they will be affected by the adjacent begs. In this case, the shallower readings would be more accurate.

The induction tools of today are capable of recording 20 different Resistivity readings, which are able to give us a better understanding of what the Uninvaded Zone Resistivity (Rt) will be. Due to the differing volumetric influence of each of the receivers, each of the Resistivity curves are influenced slightly differently, causing a separation in curve responses. There are however, a number of characteristic curve separation responses that give us a better understanding of what geological structure or anomalies is being encountered at the respective separation points. The curve separation figures 2.8 and 2.9 below give us a methodical means of interpreting Resistivity Curve Separation.

Figure 2.8: Curve Separation Deep>Shallow Figure 2.9 Curve Separation Shallow>Deep

Each of the effects will be discussed and examples provided. Please remember, the measurement range:

▪ Phase Shift Resistivity range; 0.2-200 OHMM ▪ Attenuation Resistivity range; 0.2-50 OHMM

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2.5.1 High Dielectric

Resistivity readings made by Induction resistivity tools are dependant on two properties of the rock: Conductivity (Conductivity = 1/Resistivity) and the Dielectric Constant. To be able to convert the Phase shift and Attenuation readings made by the tool into useful Resistivity Readings, the dependence of the

reading on the Dielectric effect needs to be eliminated. To do this, about 300 samples of sandstone and limestone samples were taken and the values for the dielectric effect and resistivity of each of the samples were measured. The results from each sample were plotted and a curve fitted through the values. The best fit line was then defined in terms of the

formation resistivity, RT , as shown

in figure 2.10.. In doing this, a critical assumption is made that the dielectric effect can be related as a function of the formation resistivity. This assumption is however, not true in formations that have a higher or lower dielectric constant than that which was charactorized from the equation relating resistivity and the dielectric constant. A resistivity value will be determined, but it will be wrong.

Figure 2.10: Relationship between Resistivity and Dielectric Constant

Cause - There are certain shales around the world that display an unusually higher dielectric effect dependence than that which was assumed in the Resistivity transforms that are used.

Effect – The curves stack deep to shallow with the shallow readings being erratic, but also with the highest values. Attenuation Resistivity readings also read greater than Phase Shift Resistivity. (This effect is also known as Dispersion and the curve stacking can be seen in the diagram on the left). The greater the curve separation, the greater the uncertainty in the Resistivity transform.

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Solution - The 2MHz Attenuation Reading would be the most accurate approach to the true formation Resistivity (Rt). However, ARC Wizard can be used to run Dielectric proceeding to solve for Rt.

Figure 2.11: Dielectric Effect.

The log shown in figure 2.11 with curves stacking deep to shallow, and erratic readings appearing at high resistivities, which would suggest dielectric effect influence.

2.5.2 Conductive Invasion

Cause-Invasion occurs in porous zones due to the effect of drilling with overbalanced mud to prevent an influx of formation fluids into the wellbore. The mud filtrate that invades into the formation may have a different Resistivity than the fluid that it is replacing.

Effect-This effect is most visible in high Resistivity reservoirs (reservoirs are permeable and would allow invasion to occur), when using mud with low resistivities (Rt > Rm). Consider looking at the GR curve to give an indication of how porous the formation may be (sands are generally permeable whilst shale is not).

Solution-The problem may be rectified by using ARC Wizard to process for

Invasion Inversion that will provide the Rt, Rxo and DOI readings.

Where; Rt =Uninvaded Zone Resistivity

Rxo =Invaded Zone Resistivity

DOI=Depth of Investigation

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Figure 2.12: Conductive Invasion

The Resistivity log shown in figure 2.12 shows a GVR (GeoVISION Resistivity) log that was drilled with WBM, which has 5 different depths of investigation, which can be interpreted in much the same manner as an ARC log with the various depths of investigation. For the GVR, the depth of Investigation from deepest to shallowest is as follows:

Bit Resistivity>Ring Resistivity>Deep Button>Medium Button>Shallow Button

In the log shown, the Curves stack, shallow to deep, with the deep curves reading a higher Resistivity than shallower curves, suggesting water based mud invasion.

2.5.3 Resistive Shoulder

Cause- This effect occurs when drilling parallel or very close to a resistive bed layer. The deeper readings, which also have a lower resolution, will now not give a good reading for Rt as they will be influenced by the nearby conductive bed.

Effect- Resistive Shoulder beds will cause the Deep reading attenuation shift Resistivity to read higher than the deep reading phase shift, as shown in Figure XXXX. The presence of nearby beds could be identified through the use of images and relating what is seen, to a TVD, that will give an idea how far

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away these layers may be from the wellbore at any point along the well.

Solution- The effect may be removed by processing using INFORM to find Rt. INFORM is a software package available through DCS (Data Consulting Services).

2.5.4 Resistivity Anisotropy

Cause- This anomaly will occur when the relative dip angle (angle between tool axis and formation bed) is more than 50 degrees and the tool is in the vicinity of thin bed layers that have contrasting

resistivities. The separation between curves will increase as the relative dip angle decreases and all the Resistivity readings will read higher than the true formation Resistivity, Rt.

Effect- Anisotropy is a measurement anomaly that will cause the Resistivity curves to separate evenly so that the Deep reading Phase shift Resistivity has the highest reading, down to the Shallow Attenuation Resistivity with the smallest, as shown in the figure to the left.

Solution- This effect can be corrected by using ARC Wizard to process for anisotropy to give.

Rh = Horizontal Resistivity (Presented as Rt )

Rv =Vertical Resistivity

The relative dip angle of the tool is shown in figure 2.13. It is defined as being the angle between the tool axis and a line drawn perpendicular to the formation bed. This angle should be at least 50 degrees for resistive anisotropy to be displayed.

The curve separation will increase with an increase in relative dip angle.

Figure 2.13: Relative Dip angle and Bed Boundary

The log shown in figure 2.14 shows the 2MHz Phase Shift Resistivity curves reading higher than the Attenuation Resistivity and also stacking shallow to deep. The 2MHz Attenuation Resistivity is stacking and so is the 400KHz. This identifies the anomalies as resistivity anisotropy.

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Figure 2.14: Resistivity Anisotropy-Example 1

Figure 2.15: Resistivity Anisotropy and Measurement out of range-Example 2, OBM

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2.5.5 Resistive Invasion

Cause- This type of anomalies will be most prominent in reservoirs of low

Resistivity, such as wet sands where Rm > Rt (Mud Resistivity is

greater than the Uninvaded zone Formation Resistivity) and where there is sufficient permeability for mud filtrate to displace formation fluids.

Effect- Resistive Invasion will cause the shallow phase shift Resistivity to read the highest, and the Deep Attenuation, to read the lowest.

Solution- The problem may be rectified by using ARC Wizard to process

for Invasion Inversion that will provide the Rt , Rxo

Rt =Uninvaded Zone Resistivity

Rxo =Invaded Zone Resistivity

DOI=Depth of Investigation

and DOI readings.

Figure 2.16: Resistive Invasion The sand shown in figure 2.16 shows an interesting invasion profile. Water based mud was used in this well, the log shows the 400KHz Attenuation curves stacking together. The 400KHz Phase Shift Resistivity curves show a small amount of separation while the 2MHz Attenuation and Phase Shift Resistivities are widely separated with 2MHz Phase Shift Resististivy reading higher than the 2MHz

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Attenuation Resistivity, which indicates a resistive invasion profile, which is referred to as a WBM

resistive invasion profile, with Rmf RW .

2.5.6 Conductive Shoulder

Cause-This effect occurs when drilling parallel or very close to a conductive bed layers. The deeper readings, which also have a lower resolution will now not give a good reading for Rt as they will be influenced by the nearby conductive bed.

Effect-Conductive Shoulder beds will cause the shallow reading phase shift Resistivity to read higher than the deep reading, which in turn is higher than the attenuation Resistivity.

At times it may be difficult to differentiate between Conductive Invasion and Resistive Shoulder Beds, the solution to this is to take note of where the curves begin to stack on top of one another, if they do at all. In the case of Conductive Shoulder bed, there may be no stacking as all curves could be

effected by the shoulder bed, however when invasion is the case, the deeper reading curves may be able to see past the zone of invasion so they may start to stack on top of one another. The GR curve should also give idea of the permeability of the zone (shales are non permeable while sands are permeable).

The presence of nearby beds could be identified through the use of images and relating what is seen, to a TVD, that will give an idea how far away these layers may be from the wellbore at any point along the well.

Solution-The effect may be removed by processing using INFORM to find Rt. INFORM is a software package available through DCS (Data Consulting Services).

2.5.7 OBM Drilling-Deep Fractures

Cause- Fractures may not be present while drilling the well. However they may develop afterwards. They can be detected by making repeat passes to check for changes in the Resistivity response. Repeat passes may reveal that shallow fractures have developed into deeper fractures, or areas that had all the curves overlaying may show signs of fracturing. The response from fracturing is not always uniform and will spike more around the fracture than at others. Deep fractures are greater than about 20-30 inches in radius. Shallow radius fractures cause the shallow to read higher than the deep.

Effect-Deep fractures when using OBM will cause the curves to separate in different configurations for Rt >1 Ohmm. 400KHz is less affected that 2MHz.

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Solution-A solution to this type of separation would be to do a repeat pass (time lapse logging) to determine the repeatability or progression of the fractures, whilst still taking into account, the APWD reading during each logging pass. A higher APWD reading would cause the fractures to open wider and perhaps also reach deeper.

Figure 2.17: Real Time Log Showing Deep Fractures. Figure 2.17 shows an example of a log with Deep Fractures with OBM (InTouch Ticket 3841398). Notice that there is no variation in GR.

2.5.8 OBM Drilling-Shallow Fractures

Cause-Fractures may not be present whilst drilling the well, however they may develop at a later stage. These can be detected from making repeat passes to check for changes in the Resistivity response.

Repeat passes may reveal that shallow fractures have developed into deeper fractures or areas that had all the curves overlaying may show signs of fracturing. The response from fracturing is not always uniform and will spike more around the fracture than at others.

Effect- When drilling with OBM shallow fractures will cause the Shallow Reading Curves to separate, and also for them to read the highest Resistivity as they will be exposed to the OBM. However, the deeper reading curves will not be as adversely affected. The 400kHz reading will be less affected.

The curve separation chart shown on the left is what would be expected for

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Shallow Fractures with Rt > 0.2 Ohmm.

The log shown in figure 2.18 was drilled with OBM, at 7788ft it shows the 2MHz shallow Phase Shift Resistivity curves reading higher than the deep. The same stacking is present with the Attenuation Resistivity, suggesting that the effect seen in the log, is a shallow fracture. The second anomalies at 7792ft show the deep reading Phase Shift Resistivity reading the highest, which may suggest that the fracture is deeper than that at 7788ft.

Figure 2.18: Shallow Fractures

2.5.9 Eccentering

Cause-This effect will occur when there is a vast contrast between Rt and Rm and OBM is used. It occurs due to the LWD tool not being properly centred in the wellbore and a stronger signal travelling through the mud than in the conductive formation. This effect will become more pronounced at low resistivities.

Effect-Eccentering will cause the resistivity curves to separate with the deep reading Attenuation reading having the highest resistivity, as shown below.

Solution- The deeper reading 400kHz curves (Low frequency) would be able to provide a better reading as they have a deeper depth of investigation and would be less affected. Blended Resistivity would,

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however, provide the best reading to present to the client as it will present a mixture of 2MHz and 400kHz that is relatively unaffected by Eccentering.

Figure 2.19: Eccentering of ARC tool in OBM The log shown in figure 2.19 shows the 2MHz Phase Shift Resistivities as being very erratic in the low GR zone of the log. The 2MHz Attenuation Resistivities are not affected as much while the 400KHz curves are not affected and show that the Resistivity in the low GR zone is very low, which identifies the anomalies as Eccentering.

The scales shown on the Resistivity plots have been shifted in this example, which allows for an easier identification of which curves are separating (if this were not done, one could not see with too much ease, as most of the curves would simply overlay).

2.5.10 Polarization Horns

Cause-Polarization horns are measurement anomalies that occur at high relative dip angles at bed boundaries, becoming more pronounced with increasing relative dip angles. The two formations at the bed boundary must also have a large Resistivity contrast. The effect starts to appear when relative dip

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angles exceed 60degress. The High Frequency Phase Shift readings are most affected by the anomalies.

Figure 2.20: Polarization horn. Effect-The Polarization horn shown in figure 2.20, shows that the 2MHz Phase sift Resistivity reading is affected most by the anomalies (two horns appearing, one at 8890ft, the other at 8902ft), the 2MHz Attenuation reading only shows on reading, whilst the 400KHz curve is affected least (lowest intensity peak). The intensity of the polarization horns is dependant on the Resistivity contrast between the beds and the relative dip angle of the tool. Invasion can diminish the polarization effect (making the transition less sharp.

Solution- ARC Wizard is not able to remove Polarization horns. When present, ARC Wizard will display a Multi Effect Flag. Under no circumstances should these values be edited out of the data, many clients actually use Polarization horns to identify their bed boundaries as the horns will appear exactly at the bed boundary.

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2.5.11 Measurement Limitations

Cause- Resistivity measurements are limited, due to the the physics and nature of the measurements. Exceeding the limit will still provide a reading from the tool, although the accuracy of the measurement will not be entirely verifiable. Laterolog limitations are:

▪ Phase Shift Resistivity range; 0.2-200 OHMM ▪ Attenuation Resistivity range; 0.2-50 OHMM (16in-20ohmm, 22in-30ohmm)

The diagram below is an example of the Attenuation Resistivity exceeding the limit.

Figure 2.21: Measurement Limitations Effect- The example shown in figure 2.21 may occur due to the limitations on the ARC tools measurement response. The ARC measurement range is as follows;

Attenuation Resistivity: 0.2ohmm - 50ohmm Phase Shift Resistivity: 0.2ohmm - 200ohmm

The 2MHz Phase Shift Resistivities stack very well, 2MHz Attenuation Resistivities are however stacking shallow to deep and may be affected by invasion. The 400 KHz readings are however starting to become erratic, the Resistivity at that point is around 70 Ohmm, which is outside of the limitations for Attenuation Resistivity.

Solution- Extended resistivities may be used that provide a lot more stable response at far higher resistivities.

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2.6 Corrections to Resistivity Readings

2.6.1 Electromagnetic Resistivity Corrections

Electromagnetic Propagation tools Resistivity responses can be corrected for Borehole effects. Although Borehole Compensation is not a correction but rather an averaging, it has also been included in this section.

-Borehole Compensation: This correction helps to remove the effect of enlarged boreholes. Washouts and cave-ins cause the wellbore to be enlarged, which in turn causes the mud to have a larger influence on the reading. The correction is done by averaging out the reading from each of the transmitters, with its corresponding transmitter on the opposite side of the receivers. Please refer to the ARC SLP for more details.

-Borehole Correction: This corrects for the effect that the mud has on the readings. The inputs are bit size in the BHA and the mud Resistivity that is obtained from the Electronic Mud Tester box. If Oil Based Mud is used, merely input 1000Ohmm.

2.6.2 Laterolog Resistivity Corrections

Laterolog Resistivity measurements are corrected for geometric effects. Engineers should be aware that the bit resistivity is only valid when the bit is on bottom drilling.

Inputs for the geometric correction include BHA configuration, mud type, tool size and bit size. These inputs are used to convert the resistance measurement made by the tool into a resistivity measurement, as spoken about in section 2.1 of this document.

2.7 Applications of Resistivity Logs

Resistivity logs are considered a basic log for wellbore logging, due mainly to the wide application and ease with which the measurements can be made. A number of the applications of Resistivity logs will now be discussed.

2.7.1 Qualitative Analysis

Qualitative Analysis is used to locate hydrocarbon zones from information provided on logs.

Hydrocarbons zones can be identified with the resistivity measurement, although they cannot completely confirmed without the use of the Density/Porosity Log.

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A wet zone will appear as on a Resistivity log with a low Resistivity reading as water has a very low Resistivity. Hydrocarbon zones however, have a high Resistivity reading due to oil and gas being very poor at conducting electricity.

Figure 2.22: Composite Log of Hydrocarbon and Wet Zones.

The Log Shown in Figure 2.22 is a good example of the Resistivity curve being used to locate hydrocarbons. Two reservoir sections can be seen in this log. The GR shows two clean zones of low GR. Looking at the corresponding Resistivity curves in those zones:

Top reservoir: The Resistivity reading is high, which is a good thing if you are drilling for oil, although the presence of oil is confirmed by the crossover in the Density and Porosity logs, which will be covered in the next section. The Invasion profile that can be obtained from the different depths of investigation can give us a useful insight into how well this zone may produce oil.

Bottom reservoir: This has a low Resistivity reading, which means that it is filled with water. The Density and Porosity Curves also display no crossover (more about this later).

2.7.2 Quantitative Analysis

Quantitative analysis is used to determine the quantity of oil in the reservoir. Hydrocarbon zones that are identified by means of Qualitative analysis will never contain only oil and gas. There will always be a small amount of bound water that is held by capillary action onto the rock particles, and also a varying amount of free water which will be produced along with the hydrocarbons if the zone were produced. The implied costs of separating and treating this water when it is on surface would need to be taken into account before a decision is made to produce the zone to determine if it will be financially rewarding or not.

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Clients will use equations to calculate the amount of hydrocarbons in a reservoir from information that is read off logs. The most commonly used equation is Archie‟s Equation, or at least a modified form of it. Archie‟s equation will be studied in more detail at the end of this section.

2.7.3 Correlation

As was seen in the GR log, correlation of information between wells is useful for identifying formation tops that allows the well profile to be adjusted whilst the well is being drilled. The topic is dealt with in more detail in the GR Correlation section.

Resistivity curves will add an additional feature that would help geologists in their correlation.

2.7.4 Estimate Pore Pressure

As sediment is added on top of older sediments, the added weight compresses the formations deeper down, which in effect will reduce the pore spaces available for water and hydrocarbons. The reduced

amount of water in the formation will result in an increase in the Resistivity.

This effect will become more noticeable when Resistivity is plotted on a very compressed TVD scale, as shown in Figure 2.23. Notice the trend of an increasing reading as TVD increases. This process is referred to as dewatering.

Although the exact pore pressure can not be determined from Resistivity, the trend can at least be monitored whilst drilling. You can see a deviation from the “normal” trend at the bottom of this log.

Figure 2.23: Dewatering Effect.

2.7.5 Invasion Identification

Invasion identification is a useful indication of how well a potential pay zone will flow once the well has been completed. Reference to the Invasion section of this package would be beneficial to understanding how invasion occurs.

Invasion can be identified from Resistivity logs as a separation in the readings from each of the different depths of invasion, although care should be taken not to confuse this with measurement anomalies like anisotropy, eccentering, shoulder bed effect, as has been described in the section dealing with Resistivity curve separation.

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t

When using LWD tools to measure invasion profiles, they have the added benefit of being able to provide the client with time lapse logging where the development of the Invasion profile can be monitored by means of repeat passes (reaming over a section). Wireline is typically done a few days after drilling is completed. By that stage, the invasion profile may have even dissipated.

A common means of identifying movable formation fluids is by means of the RXO

RT

calculation.

2.7.6 Geosteering

Geosteering is the term used to describe the steering of a well from the information obtained from LWD measurements sent uphole in real-time. The GVR (GeoVISION Resistivity*) tool is the most appropriate tool for Geosteering it provides measurements very close to the bit. In fact Bit Resistivity is able to provide a qualitative measurement right at the bit.

Geologists use the information attained from LWD measurements in real-time to determine where the most appropriate well placement would be to maximize production from a well. This information would then be passed onto the Directional Driller who would steer the well in the desired direction.

2.8 Archies Equation

The Resistivity log, in combination with a porosity reading, can provide a drilling company with valuable information regarding how much oil a reservoir can produce, and also how much water will flow out with the oil and gas. This was made possible by an equation developed by Gus Archie, a former Shell employee, who conducted a number of experiments and was able to relate the water saturation of the formation with the formation Resistivity, porosity and Connate Water Resistivity (Water in wet zone). The Archie Equation is:

SW n

a RW

m R

Where: SW

RW

Water Saturation of the zone of interest (Expressed as a decimal fraction).

Resistivity of Wet Zone Water (Ohmm @ degF). Please note that this is not RO , which

will be discussed a little later in the section.

Formation Porosity (fraction, this will be introduced shortly)

a Tortuosity Constant (Usually taken as 0.81 for Sand Stone and 1 for Lime Stone)

m Cementation Exponent (Usually 2)

n Saturation Exponent (Usually 2)

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2.8.1 Need for Archies Equation

Prior to Archie developing his empirical equation, now known simply as Archie‟s Equation, logs were used simply as a qualitative measurement, which indicated areas of hydrocarbons as high resistivities, and no further analysis could be done regarding the quality of the reservoir. Operators drilling these wells would run the Resistivity logs and then try to produce from the high Resistivity zones, with a mixture of success.

The reason for the limited success in simply producing from high Resistivity zones is due to the fact that the Resistivity reading alone is not sufficient to determine if a zone is truly a good pay zone (producible hydrocarbon zone), as other factors will also play a role in determining its quality. Archie soon found out from his experiments which properties of the reservoir will influence the quality of a pay zone. These experiments will be discussed in a bit more detail but first, a detailed look needs to be paid to some definitions.

2.8.2 Definitions

Volumetric Fractions: A reservoir is made up of rock particles (assume this reservoir is sandstone, in which case the grains would be made up of quartz), with the spaces between these particles being filled with Gas, Oil or Water, as is demonstrated in figure 2.22. Water is more dense than oil and gas, so over time it will settle to the bottom of a reservoir as is shown at the bottom of the left diagram. Gas is lighter than oil, so it will settle at the top of the reservoir. Oil has a density between gas and oil, and as a result will lie between the two layers if it is present.

If you were to compress the quartz grains in the cube shown on the left of figure 2.24 into a solid cube of quartz and gather all the fluids together, the fluid portion could be defined as the porosity ( ) of the formation. This would leave the fraction of solid quartz as 1- (this would be the matrix)

The fluid portion can be split into two parts, the portion of the porosity that is contained by water:

SW (Water Saturation)

The remaining portion of the porosity is occupied by Hydrocarbons, which is defined as:

Figure 2.24: Volumetric Fraction

1- SW (Hydrocarbon Saturation)

Porosity: This can be defined as being the ratio of the volume of the non solid material in a cube of material to the volume of the solid material (The spaces between rock particles).

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PoreVolume

100

TotalVolume It can be presented as a fraction from 0-1, where a porosity of 0 means that the material is made up of only solid material and 1 means that there is only fluid. It is also possible to present porosity as a percentage, where 0.2 =20% although this may be confusing when talking about a 10% increase in porosity, this could mean;

1. Assuming the original Porosity was 20%

20% +10%=30% Porosity or

2. 20% 110% (or 0.11)=22% Porosity

For this reason, one does not use the term % when talking about porosity, but rather Porosity Units (PU), which are in fact identical to Porosity in percentage (which we do not refer to when speaking about Porosity).

Water Saturation- SW The fraction of the porosity that is occupied by water.

Hydrocarbon Saturation- S H

by hydrocarbons.

1- SW = The remaining portion of the porosity that is occupied

Zone Resistivity- R T = Resistivity of Uninvaded Zone formation (beware, this is not always the

deepest reading Resistivity).

Resistivity of Wet Zone- R O = This is the R T measurement in the wet zone, where

(Do not confuse this with RW )

SW 1

Resistivity of Water in Wet Zone- R W = Resistivity of Wet zone fluid (Do not confuse this with

RO )

2.8.3 Derivation of Archies Equation

Archie conducted a number of experiments to try and find if he could find a relationship between the Water Saturation, Formation Porosity, Formation Water Resistivity and the Resistivity measured at each point along the wellbore. Most of his experiments were conducted on core samples, although for ease of understanding we will consider a simple plastic block that has electrodes connected to each side, which are attached to an ohmmeter, as shown in the figure below. The Ohmmeter reading gives the true Resistivity of the block, RT .

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Experiment 1

The empty cube is filled with distilled water (no ions to allow flow of current). There is no solid material so

porosity is 100%, nor are there hydrocarbons so SW is

1.

Block Contents Distilled Water

SW 1

S H 1- SW 0

100 PU

Result RW = RT

Experiment 2 Salt is added to the distilled water in the cube, this allows ions, the Resistivity decreases until no more salt will dissolve in the water.

Block Contents Saline Solution

SW 1

S

H

1- SW 0

100 PU

Result

RT = RW 0

From these results, Archie was able to make the following relationship;

RT RW

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Experiment 3 Archie then removed a portion of the water, replacing it with an equal portion of oil. Repeating this with different volumes of oil each time, he found that there was a direct relationship between the Water saturation and RT

Cl-

Na+

Na+

Cl-

Block Contents Saline Solution and Oil SW <1

Cl-

S H >1

100 PU

Result

1 RT

S W

Experiment 4 Archie then went back to the original saline solution that he had in experiment 2, he then added dry sand to the saline water, allowing the water that was displaced to flow over the sides of the cube. As he added more sand, he found that there was a

corresponding change in RT and was able to make

the relationship shown below.

Block Contents Wet Sand

SW =1

S H =0

<100 PU

Result

1 RT

Archie also found that RT varied for different types of sand grains, even though the porosity remained

the same. To accommodate for this, he introduced three constants, a, m and n.

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O

m

a = The Tortuosity Factor, which takes into account the shape of the path that current would need to travel through the block.

m = The Cementation Exponent, which takes account of the degree to which individual formation particles are bonded together.

n = The Saturation Exponent

By incorporating all of his results into one equation, Archie was able to define the generalized form of the Archies Equation;

S n

W aRW

R m

T

Unless otherwise specified, the following value are used for the constants.

a= 0.81 for Sandstone a= 1 for Limestone m= 2 n=2

2.8.4 Calculation of RW

RW can be calculated by using Archies Equation in the wet zone. RT is defined as being RO in the wet

zone, which is referring to the Resistivity of the Formation and water in the wet zone, which can be read

off the log in the wet zone. SW is equal to 1 as the wet zone contain only water.

In the wet zone, Archies equation is defined as follows;

RT RW

SW 1

1 aRW

R m

R RO

W

a

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W

m

m

m

T

2.8.5 Quick Look Calculation

Should the porosity reading be the same in both the wet zone and pay zone and a, the Tortuosity factor is also assumed to be the same (same rock type), then a simplification can be made to Archies equation;

R RO

In Wet Zone- a

In Pay Zone-

S n

W aRW

RT

substitute for RW

from wet zone

S n

W

a RO

R m a cancel out a and

m

S n

W RO

RT

2.8.6 Limitations of Archies Equation

Archie‟s equation assumes that the constants a, m and n are known. M and n are usually assumed to be equal to 2, although these values may vary, especially in carbonates (from 1.6 to as much as 3 or 4). For a more accurate approach to what the constants may be, it may be necessary to take core samples.

The formation Resistivity is an important input into Archie‟s equation. However there are numerous influences that may prevent an accurate reading from being obtained. Resistivity anisotropy, invasion and thin bed responses are but a few examples that limit the accuracy of the calculations obtained from Archie‟s water saturation equation.

Shale has a major influence on both the Resistivity and porosity of the formation. Archies equation has been designed for shale free environments.

2.8.7 Worked Example of Archies Equation

Archies Equation provides clients with useful information regarding the quantity of water (both bound and free) that is contained in a reservoir, this will allow strategic decisions to be made on which zones to produce from.

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Figure 2.25: Reservoir drilled with OBM in Sandstone

Figure 2.25 shows an example of a well that has been drilled through a reservoir that contains a pay zone and a wet zone below it. Before approaching any quantitative analysis on the log, you would need to identify which Resistivity curve should be used in the interpretation.

The log shows that the 2MHz Phase Shift readings are stacking shallow to deep, with the deeper reading curves reading higher Resistivity. The Attenuation Resistivity is also reading less than the Phase Shift Resistivity. This suggests that the effect that is causing the separation is Anisotropy, which can be solved by means of ARC Wizard which will provide a horizontal and vertical Resistivity, which is reading close to the Resistivity of the 2MHz 40in Phase Shift Resistivity in this case.

Archies equation will be used to calculate the water saturation at 10775ft (red line).

In the wet zone, shown on the log at the low Resistivity at 10890ft

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m

2

Sandstone is being drilled so a =0.81

In Wet Zone- R RO

W

a

2

0.17 0.81

0.0713 Ohmm

RO 2 Ohmm

17PU = 0.17

In Pay Zone-

S n

W aRW

R m

0.81 0.0713

0.023 1000 0.05

2

T

RT 1000 Ohmm

4PU = 0.04

SW 0.023 = 0.15

A water saturation of 15% means that this would be a zone of much interest for production.

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2.9 Review Questions

1. What is the definition for Vertical Response 2. How does the thin bed response for Attenuation Resistivity Differ from that for Phase Shift

Resistivity? 3. Describe the four rules of thumb for the Depth of Investigation. 4. Describe the four rules of thumb for Vertical Resolution. 5. What factors will affect the depth of Invasion whilst using LWD? 6. List the applications of Resistivity Logs. 7. Read off the Resistivity Reading at each of the points shown;

8. From the Log shown below, calculate the water saturation at 12135ft MD. Assume Sandstone Formation.

Answers at the end of the document.

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3. Density and Porosity

Density and Porosity are very useful measurements as they not only provide geologists with measurements reflecting the bulk density of the formation (the density of a unit volume of rock, including the rock particles and fluids within the pore spaces) and porosity, but they can also be read in relation to one another to help to differentiate hydrocarbon reservoirs from zones which, on a GR, resistivity log, may appear to be reservoirs (e.g. tight quartz streaks).

Porosity refers to the percentage of the formation that is occupied by pore spaces, which could contain water or hydrocarbons. This measurement is important to the client as it will allow them to determine the quantity of oil in the reservoir, which will be used in their estimations of how much oil will be recoverable and how much revenue will be generated.

Density refers to the mass per unit volume of the formation, which includes the matrix (rock) particles and fluid within the pores of the rock matrix. This is referred to as bulk density. It is also possible to derive a porosity measurement from density. This is referred to as density porosity.

------------ Shale Zone ------------

Sand Zone

Gas

------------

Sand Zone

Oil

------------ Sand Zone Water ------------

Shale Zone

Figure 3.1: Reservoir Demonstrating Shale, Gas, Oil and Water Zones.

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3.1 Reservoir Analysis

The log shown in figure 3.1 shows an illustration of a well drilled through a reservoir containing an impermeable shale cap and a thick sand zone. The reservoir has gas at the top, and oil and water at the bottom. Each of these zones will be discussed in more detail below.

3.1.1 Shale Caprock

The shale at the top of the illustration shown is a good example of a shale cap rock, which has a very low permeability, causing the hydrocarbons to be contained within the reservoir section below, and not being allowed to escape to the surface.

Shale is characterized on logs by a high GR reading. The low Resistivity and the porosity reading is influenced by what is known as the Shale Effect. The reason for this is due to the large amount of bound water which is present in shales, which slows down the neutrons from the neutron source, causing less neutrons to return to the detectors, which in turn is interpreted as high porosity.

Bound Water: Bound water is the water that adheres to the surface of clay (shale) particles by capillary action. Clay also contains water present in the pore spaces that is not able to escape due to the characteristic low permeability of clays. These two types of water are referred to as bound water.

3.1.2 Gas Zone

Gas will form in situations where the maturation of hydrocarbons occurs above 1500 C. When present, gas will accumulate at the top of the reservoir due to the relative low density of the gas in comparison to oil and water.

Gas is present in porous zones, which are characterized by low GR readings and high resistivity, as they do not conduct electricity. The neutron porosity reading is affected by what is referred to as the Gas Effect. This zone has an unusually low Neutron Porosity due to the large numbers of neutrons that return to the detectors as a result of the low Hydrogen Index in gas.

When entering into a hydrocarbon zone, the density and neutron porosity curves will cross over one another, as shown in figure 3.2 at 10062 ft. This is commonly referred to as crossover and is often shaded when plotted on logs to allow for easier recognition of gas hydrocarbon zones. When gas is present and the correct log format and processing has been done for the type of formation, then there will be a large separation between the Density and Neutron Porosity readings. In certain situations the separation may not be large enough to clearly determine if the zone consists of gas or oil. A rule of thumb that applies in that case is that a separation of more than 3 PU between Neutron Porosity and Density Porosity (more about these later) can be interpreted as a gas zone.

To find what the true porosity of the formation will be, the client will need to apply what is known as a Gas Correction, which will be discussed in further detail later in the interpretation section of this document.

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3.1.3 Oil Zone

Oil, when present, will be positioned in between the Gas and Water Zones, due to the density of oil being between that for water and gas.

Oil zones are characterized by the same low GR, high Resistivity and crossed over readings as shown for the gas zone. However, there will only be a slight separation between the density and neutron porosity readings as shown in figure 3.2 from 11010 ft to 11030 ft. Oil has a higher Hydrogen Index (HI) than gas which will cause neutrons to loose more energy, resulting in less neutrons returning to the detectors. This is interpreted as a higher Neutron Porosity being displayed than in gas.

3.1.4 Wet Zone

Should water be present in a reservoir. It will always be positioned below the hydrocarbons as it is heavier than gas and oil. It is characterized by a low resistivity due to the presence of conductive fluids. The HI of water is higher than that of oil, which results in fewer neutrons returning to the detectors. This is interpreted as a larger Neutron Porosity reading than in oil.

A wet zone is easily identified from the density and porosity log by the neutron and density logs overlaying one another in clean limestone formation. This effect is shown in figure 3.2 from 11 040 ft to 11058ft.

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Figure 3.2: Shaly Reservoir

The log shown in figure 3.2 shows an inter-bedded shale-sand reservoir containing gas, oil and water (as it would appear). The large density/neutron porosity crossover in the top sand zone is due to the gas effect, with a few thin beds containing gas down to 11 010 ft. At this point, the crossover is not as pronounced as in the upper sand, due to the presence of oil (11010 ft to 11030 ft). Further down, the low resistivity and absence of crossover are due to the presence of conductive water.

3.2 Density

The purpose of the Density measurement is to provide the client with a bulk density reading that can be used in calibrating seismic measurements to make Vertical Seismic Plots (VSP). Density can also be converted into a porosity reading, known as density porosity (more about this at the end of the module).

Density is measured by means of gamma rays that are fired into the formation and measuring how many return to the detectors (density windows). A high number of gamma rays that return to the detectors is associated with a low density as more gamma rays were able to pass through electron cloud than would be expected in a dense formation.

The application and interpretation of this measurement will be discussed in more detail later in this document.

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3.3 Porosity

Porosity is referring to the ratio of the volume of the void spaces in a rock to the total volume of the rock.

PoreVolume

100

TotalVolume

Sand Particle

Shale/Clay

Oil

Ineffective Porosity

Effective Porosity

Bound Water

Figure 3.3: Sandstone Porosity The sand matrix shown in figure 3.3 demonstrates a number of parameters that should be understood when dealing with reservoirs;

▪ Ineffective Porosity - The portion of the total rock volume that is occupied by void spaces that

are enclosed, and as a result will not contribute to any flow.

▪ Effective Porosity - The portion of the total rock volume that is occupied by void spaces that are not enclosed, and as a result, will contribute to flow.

▪ Total Porosity – The total porosity includes both the effective and ineffective porosity. ▪ Bound Water - Water that will not be able to flow from the reservoir due to the action of

capillary forces between sand particles and adjacent water particles.

3.3.1 Neutron Porosity

Neutron Porosity can be determined by firing neutrons into the formation and measuring the quantity returning to the tool. Pore spaces are most often filled with either water or hydrocarbons. Empirical evidence has provided a means of correlation between porosity and the hydrogen content of the fluid in the pores.

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A neutron has approximately the same size as a hydrogen atom, which is a primary building block of water (H2O) and Hydrocarbons. The similar mass of neutrons and hydrogen atoms means that neutrons will loose a lot of energy when travelling through areas with a high hydrogen content (Hydrogen Index), due to collisions with particles of a similar size allowing for a large transfer of energy and subsequent slowing down of the neutrons. These neutrons are either absorbed by the formation or a small portion return to the neutron detectors where they are recorded as counts. The lower the number of neutrons returning to the tool (counts), the higher the assumed porosity.

Hydrogen index is the ratio of the number of hydrogen atoms in the formation to that contained in water at 25degC and 1 atmosphere of pressure.

The Neutron Porosity reading that is measured by the tool is corrected for environmental and eccentering effects, and is referred to as the Apparent Neutron Porosity reading. This is the value that is presented to the client. Apparent porosity is not necessarily the true porosity of the formation due to due mainly to the shale and gas effects. For this reason it is good to be able to differentiate the reading made by the tool from the true formation porosity by calling the tool‟s porosity reading Neutron Porosity, which will be interpreted by Geologists appropriately.

More will be discussed about the environmental influences and corrections that are applied to this reading in a later section.

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f

3.3.2 Density Porosity

The Neutron Porosity measurement is affect by a large number of environmental influences (e.g. shale and gas). For this reason, it would be beneficial to obtain an independent porosity measurement that is based on another measurement principle to assist in the interpretation of formation porosity. A cube of formation is made up of rock particles and porous space, which is filled by either hydrocarbons or water, as shown in figure 3.4.

Figure 3.4: Porous cube of Formation

The cube of formation shown in Figure XXXX is made up of;

Quantity Density Rock Matrix Formation Fluid

1-Φ Φ

ρ ma

ρ f

Φ = Formation Porosity (Fraction of Fluid) ρ f = Density of Fluid in Formation ρ ma = Density of Rock Matrix 1- Φ = Fraction of cube occupied by Rock ρ b = Density of both rock matrix and fluid in pore spaces

To calculate the density of the cube shown in figure 3.4 (density of both rock matrix and formation fluids, referred to as Bulk Density), the following calculation can be made:

Cube Density = Bulk Density = Fraction of cube filled with fluid x Fluid Density + Fraction of cube filled with rock x Rock matrix density

=> ρb = Φ × ρ f + (1-Φ) × ρ ma .

The equation shown above, now relates the bulk density of the cube to the porosity and fluid and matrix densities. Rearranging this equation to solve for the porosity will result in:

ma b

D

ma

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This equation provides a means of deriving a porosity measurement, referred to as density porosity (ΦD) from the density reading, herewith follows a brief description of how this is done in practice.

ρ b is the density measurement that is recorded by the LWD tool. ρ ma is the density of the matrix being drilled (specified by client, 2.65 g/cm3 for Sandstone,

2.71 g/cm3 for Limestone)

ρ f is the density of the fluid in the pore spaces, this can be obtained from the client who would have got the value from fluid and core sample.

Density porosity can be read directly off the density/neutron porosity log, using the neutron porosity scale, provided that the log was processed with the corresponding formation to what is actually in the hole and plotted accordingly on compatible scales. Should incompatible scales be used, it is possible to add a Density Porosity curve to a log.

The example that follows will illustrate how density porosity is calculated from the equation derived above. The example was processed using a Limestone Matrix and, it is also plotted on Limestone Compatible Scales, for these reasons, we can read off the Density Curve on the Neutron Porosity Scale as Density Porosity.

Depth A Neutron Porosity = 32PU

Density Porosity = ma b

ma f =

2.65 2.05 2.65 1

=0.36 = 36PU

Density Porosity =32PU (Read off Log)

Depth B Neutron Porosity = 55PU

Density Porosity = ma b

ma f =

2.65 2.29 2.65 1

Figure 3.5: Calculation of Density Porosity

=0.22 = 22PU

Density Porosity =21PU (Read off Log)

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3.4 Nuclear Scales

The logs shown at the start of this module (in figure 3.1) provided an easy means of identifying gas, oil and water zones. This identification is made simply by identifying the presence of crossover between the density and neutron porosity readings. For this interpretation method to work, the following criteria have to be met:

Data was processed with the same matrix type as the formation that was drilled.

Compatible Scales are used to present the log.

3.4.1 Compatible Scales

If these two conditions are met, the density and neutron porosity readings will overlay in a clean water bearing zone and the density reading can also be read straight off the porosity scale to give a density porosity reading (refer to end of this module).

The matrix type that is used to process for neutron porosity can be changed in the recorded mode processing inits sheet. This should be set to the matrix type that is specified by the client (Limestone, Sandstone or Dolomite).

The compatible scales for Sandstone (figure 3.6) and Limestone (figure 3.7) are referred to as Sandstone and Limestone Compatible scales respectively. Compatible scales need to be used at all times when presenting density and neutron porosity data on a log and should be set to the type that was specified by the client.

Figure 3.6: Sandstone Compatible Scale Figure 3.7: Limestone Compatible Scale

A compatible scale has, on the right hand scale, a density reading that corresponds to the zero neutron porosity at that point. This means that the density reading should correspond to the density of the matrix material.

Sandstone = Quarts = 2.65 g/cm3

Limestone = Calcium Carbonate = 2.71 g/cm3

Dolomite = Magnesium Carbonate = 2.87 g/cm3

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The left side is then presented with a porosity of 60PU and a bulk density that is 1g/cm3 lower than the matrix density on the right.

3.4.2 Shifted Compatible Scales

There are certain clients who will request modifications to the general rule stated above and display, for instance sandstone formations, calculated with Limestone matrix on Sandstone compatible scales or possibly even totally incompatible scales.

15000

15100

Figure 3.8: Implication of using the incorrect scales when presenting nuclear data.

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The purpose of shifting nuclear scales (presenting data on incompatible scales) is to ensure that the density and neutron porosity readings will overlay in clean water bearing reservoir rock. All hydrocarbon zones will display crossover, allowing for simple interpretation.

It is also possible that clients will request one of the scales to be shifted. An example of this would be to represent TNPH on a scale of 45PU to -15PU. In this case, if we were in a Sandstone formation and processed the log using sandstone, then we would want to ensure that we are reading the density of sandstone (2.65g/cm3) at 0 PU. We would have to shift the Density scale to display from 1.8g/cm3 to 2.8g/cm3. This is referred to as a shifted Sandstone compatible scale.

This reservoir was drilled in sandstone formation, although the log was originally plotted on limestone scales, as shown in figure 3.8 in the third track next to the resistivity.

According to this log, to the casual observer (who is only looking for crossover in yellow, indicating hydrocarbons), it appears that there is oil throughout the section from 1503ft to15102ft. On closer inspection however, the resistivity shows that there is a high resistivity zone only from 1503ft to 1550ft, with the lower section reading a low resistivity (water). This error could lead to a client perforating over the entire section and producing vast quantities of water.

The same log was replayed with compatible sandstone scales as is displayed in figure 3.8 on the far right hand side. This time, the presented data is in agreement with the resistivity log, showing crossover only along the section of high resistivity, with the wet area below showing water on the density neutron log.

Whenever clients request to have shifted scales presented, the quick reference below can help to confirm if scales are compatible.

ρmax = ρma - X

60

Where

X = Neutron-derived Porosity for the right side of the scale (PU) ρma = Matrix Density (g/cm3) ρmax = Bulk Density Value for the right side of scale (g/cm3)

3.5 Corrections to Neutron Porosity

There are two corrections that are applied to the Neutron Porosity: Environmental and eccentering corrections.

The environmental correction is influenced predominantly by borehole size and mud properties while the eccentering correction is dependant on the stabilizer size and hole size (bit or caliper).

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3.5.1 Environmental Corrections

Neutron Porosity is corrected for the following Environmental Corrections in IDEAL. :

▪ Bit Size (borehole size) ▪ Mud Temperature ▪ Mud Hydrogen Index ▪ Mud Salinity ▪ Formation Salinity (if known) ▪ Eccentering

Wireline does not apply corrections to neutron porosity in the same way that D&M do, this will contribute to differences between their measurements.

Corrections to the neutron porosity measurement are done using the chart shown in figure 3.10. The mud hydrogen index in the third step can be derived from the chart in figure 3.9.

Although the corrections are done by the acquisition system, each of the values needs to be entered manually for the corrections to be made. The Figure 3.9 is given to help provide an understanding of how the corrections are done to TNPH and also show which environmental effects have the largest impact on the reading.

The first step in calculating the environmentally corrected TNPH reading is to calculate the Mud Hydrogen Index

. Figure 3.9. Mud Hydrogen Index Calculation

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The Mud hydrogen index that is used in applying the TNPH correction can be calculated from Figure 3.9, using Mud Type, Mud Weight, Mud Temperature and Mud pressure as inputs. The Barite line is used to read off the first point on the mud weight chart at the bottom, provided that Barite was the weighting material used for the well. Bentonite is not as commonly used as Barite, although it is not able to provide weight above 10lbm/gal. The mud hydrogen index can be read off the chart, as shown by the red line, starting at a mud weight of 14 lbm/gal. When intercepting the Barite line, read straight up to the base of the next chart from where you follow the curve angle until the mud temperature is reached. The reading is then carried upwards towards the next chart, where the direction of the lines is followed until the Mud Pressure downhole is reached. The Mud Hydrogen index can then be read off as a fraction and can be used as an input in the next chart.

Figure 3.10: Mud Hydrogen Index Calculation

The environmental corrections made to the TNPH readings are calculated from Figure 3.10. The apparent Neutron Porosity is the uncorrected reading recorded by the tool. A vertical line is then drawn down to the value of the influencing factor is reached, a line is then followed parallel to the blue lines until the base of the chart is intercepted, at which point the process is repeated for each of the environmental effects until the corrected TNPH value can be read off the base of the chart. The example shown in the figure is for the following readings;

TNPH = 39PU Borehole Size = 10 in.

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Mud Temperature = 200oF Mud Hydrogen Index = 0.78 Mud Salinity = 50kppm Formation Salinity = 50kppm

Environmental Corrected TNPH = 33PU

From Figure 3.10, it can be seen that an increase in each of the corrections will have the following effect on the TNPH reading:

Increase in Hole Size => Decrease in environmentally corrected TNPH Increase in Mud Temperature => Increase in environmentally corrected TNPH Increase in Mud Pressure => Increase in environmentally corrected TNPH Increase in Mud Density => Decrease in environmentally corrected TNPH Increase in Formation Salinity => Decrease in environmentally corrected TNPH Increase in Mud Salinity => Decrease in environmentally corrected TNPH

The impact of each of these effects on TNPH can be determined from the slope of the line, with Hole Size having the biggest influence. So we would expect to have large corrections in washed out hole sections (look out for calliper readings increasing).

3.5.2 Eccentering Correction

Eccentering is a correction applied to the TNPH reading to correct for the effect of gravity or other forces that keep the tool from being centred in the wellbore. It becomes more significant in larger hole sizes, especially when running a slick tool, as the tool is no longer centred in the wellbore, and neutrons are able to travel more readily through the formation (at the point of contact than through the mud).

IDEAL uses the ratio of counts received at the near and far banks to calculate a value known as the Thermal Neutron Ratio (TNRA).

This correction is automatically applied in real-time using the BHA as a reference, particularly the stabilizer size (IDEAL will assume a larger degree of Eccentering in a deviated well for slick tools). In recorded mode, the stabilizer and hole size are input manually and the Eccentering Corrections are applied to the Recorded Mode TNPH. A common problem is that Engineers miss inputting the stabilizer correctly in the BHA (the default in IDEAL is a slick tool), which will result in up to 8PU differences between the real-time and recorded mode logs, depending on the hole size.

Increased Eccentering Correction: Increases TNPH

3.6 Density Corrections

Ideally, Drilling and Measurements would be able to derive a density measurement from only one spectral gamma ray. However, due to the effect of hole rugosity standoff may occur, which results in varying amounts of mud being present between the detector and the formation. The density reading is a

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very shallow reading, penetrating only 1 to 2in from the face of the window, so any standoff will result in errors being introduced into the measurement. To compensate for this borehole effect Schlumberger uses two spectral gamma ray detectors and a corrections algorithm known as Spine and Ribs correction.

The Spine and Ribs correction uses the measurements from the short and long spacing detectors and applies a correction known as ∆ρ (drho). The Spine (as shown in figure 3.11) is defined as the line along which the counts from the detectors will plot when the detectors are in good contact with the formation wall, for various formation types. Sandstone, which has a lower density than limestone would plot higher up the spine than limestone as more gamma rays can travel through the formation and thus more counts are received.

When standoff occurs, the ratio of counts from the Short Spacing (SS) and Long Spacing (LS) detectors will not plot along the spine (they will not read the same density), but rather somewhere to the side, depending on the mud weight (heavy mud plots on the left of the spine while lighter mud plots to the right). The tools algorithm will then attempt to return the reading to the spine by following a line parallel to the ribs that are shown in figure 3.11. The plot shows how heavy mud‟s will result in a negative drho, whilst the lighter mud‟s on the right, result in a positive drho.

Figure 3.11: Spine and Rib Correction Chart

It is only possible for the tool to correct for standoff up to the limit where both of the detectors are reading only mud, at which point the ratio of the counts will be able to once again plot along the spine, although now no correction is possible as the tool is unable to use the ribs to correct for the effect of standoff.

The best density reading is obtained when the tool is flush with the formation wall. LWD engineers would recommend that the tool is run stabilized to improve the contact of the sensors. However, due to directional control, the client may decide to run the tool slick, which increases the standoff and so reduces the quality of the measurement. Washed out or enlarged holes will also result in standoff which will also degrade the quality of the reading. Presenting a reliable caliper in conjunction with the density

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measurement will help in the interpretation of density measurements as it would be expected that ∆ρ (DRHB for ROBB, DRHO for RHOB) would read higher in enlarged wellbore sections.

Increased Standoff: Increased ∆ρ, also resulting in a less reliable density reading

Figure 3.12: DRHB correction-QC Curve ∆ρ can be used as a quality control curve to quantify how accurate the density curve is. Although ∆ρ is a correction for standoff, the larger the correction that is made, the less reliable the density curve would be. Figure 3.13 shows a log with and large DRHB value below 10050 ft. Notice how the density curve also starts to deviate from its original reading of 2.45 g/cm3, despite no obvious change in the formation no change in GR or neutron porosity). Another useful quality control curve has been added onto this log, the RPM_ADN curve in the depth track indicates that there was no RPM during the drilling of the same zone below 10050 ft. This assists in the interpretation of the increase density reading in this zone as it is clear to anyone looking at the log that the section was drilled whilst sliding and the density windows, which require close contact with the formation may have been orientated upwards where there was a slight standoff, resulting in the Near and Far Density detectors reading different density readings. A positive ∆ρ is shown on the log, this effect occurs in lighter muds. Standoff in light mud‟s mean that gamma rays were able to flow relatively unhindered through the mud which results in higher count rates at the detectors and results in a lower density reading than would have been attained if there was good contact with the formation wall.

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Another quality control curve that would be very useful on a log presenting density is a caliper reading. Density is very sensitive to standoff, it would be a lot easier to identify erroneous density readings due to standoff that is caused by washouts or enlarged boreholes if this curve is included.

Every Density/Porosity Log should contain the following Quality Control curves to assist in the Interpretation of log responses;

∆ρ

CRPM (Collar Rotations per minute)

Caliper

Figure 3.13 illustrates the effect that sliding has on ADN Density data. The log shows two slide sections, the first from 3508ft to 3533ft and the second slide section from 3575ft to 3608ft. These slide sections can be identified from the ADN RPM curve shown in the depth track (zero rpm whilst sliding). In both slide sections presented it can be seen that the density and PEF readings suddenly change at the start of each slide section, reading erroneous values until the start of rotation. The density data shows a drastic decrease in the value being recorded. The reason for this is due to the orientation of the density windows pointing up into the mud, which allows more gamma rays to return to the detectors due to the lower density, which is interpreted as a low density reading. DRHB does not show excessive deviation due to both windows reading purely mud, which means that both windows read the same density.

Figure 3.13: Effect of Sliding on Density measurement

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There are two options that could be used to avoid the problem of poor density data when sliding with a motor:

Running ADOS (Azimuthal Density Orientating Sub) -The ADOS is a sub with a rotatable inner mandrel that can be used to align the density windows to the bottom of the hole (good contact with the formation) for the dominant sliding orientation.

Reaming over slide Sections - Upon completion of drilling, it is a common practice to ream (rotating faster than 30 rpm) out of hole over slide intervals. This would ensure that there is good contact with the formation along the entire slide section, this should not be necessary if ADOS was used in the correct manner.

3.7 Density Image Interpretation

A density image is a graphical display of the density measurement around the wellbore. The density measurement made around the wellbore is colour coded, with higher density zones having darker colours and lighter colours indicating lower density, as shown in the colour scale at the bottom of the log shown in Figure 3.16.

Images are made possible by means of what is known as an azimuthal system. The azimuthal system allows sensors that are oriented on one side of the tool to record data and also orientate that data, relative to its position around the wellbore. The ADN tool is capable of recording 16 different measurements around the circumference of the wellbore, as is shown in figure 3.14.

As the tool rotates around the wellbore, it records density data for each of the 16 sectors (bins) around the wellbore, the tool then moves to a deeper depth and the process is repeated again but for a different depth.

Figure 3.14: ADN Azimuthal measurement.

The image data that is recorded is orientated towards the top of hole in deviated wells and magnetic north in vertical wells. This information is presented on logs by cutting the wellbore along the top of the borehole and unrolling the wellbore until it is a flat piece of paper, as shown in figure 3.15. When looking at an image log, depth increases moving down the log, the centre of the log is the bottom of the hole and the sides of the hole are now the top. The right hand side of the image shown correlates to the left side of the wellbore. Refer to figure 3.15.

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Figure 3.15: Density Image presentation in 2 Dimensions (Flat Paper)

Figure 3.16: Quadrant and Image Log

Sliding Section

The log shown in figure 3.16 shows quadrant measurements in the first and second tracks. Quadrant measurements are simply the average of the readings in the top, bottom, right and left quadrants of the wellbore. These are beneficial to clients as they are able to identify which quadrant is detecting new responses first. The image logs shown are for PEF on the left and density on the right. The 16

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measurements at each depth can be seen at each depth and the corresponding responses on the quadrant density log can be identified on the image with a lot more ease and detail.

The images shown were recorded whilst drilling using a motor assembly. The green section at the top of the log is a slide section where there was no rotation. An rpm curve would be useful on this log, as it would on any ADN log as it would indicate how reliable the reading was.

Images are useful as they provide:

▪ Borehole Stability insight (Fracture identification and mode of failure) ▪ Evaluation of rock texture (High resolution like in OBMI) ▪ Structural and Sedimentological analysis (Dip identification)

Figure 3.17 gives a good representation of how bedding planes as well as fractures will appear on an image log. The top of the graphic shows a bedding plane and a fracture intersecting the wellbore, as would be measured by the tool.

The middle graphic demonstrates how these features would appear when the wellbore is cut along the top of the hole. The bottom shows the same features but in this case, completely flattened on a 2D paper.

The direction of the image features indicates the orientation of the wellbore relative to the formation beds. If a wellbore intersects a bedding plane and the features appear first on the bottom of the wellbore and later on the sides and top, it is interpreted as drilling down dip. Should the top of the image display the features first, it indicates drilling up dip. The length of the feature is related to the relative dip angle of the tool and the bedding plane.

Figure 3.17: Wellbore image in 2D

A simple rule to remember, when you feel down, you frown and have a sad face as shown in Figure 3.18, notice the same features on the image when drilling down dip. When you are happy, you smile and are feeling up, the same features are on the image.

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Drilling

Down Dip Drilling Up

Dip

Figure 3.18: Image Orientation indicating bedding dip orientation. The borehole trajectory shown in figure 3.19 will produce an image similar to the one shown at the bottom of the figure. Three new features can be identified from this image, a fracture, bull‟s-eye and an inverted bull‟s-eye.

Figure 3.19: Image and Borehole Trajectory.

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Formation dips can be calculated from image logs. Figure 3.20 shows a simple diagram that is going to be used to illustrate drilling down dip.

Figure 3.20: Formation Dip calculation from Image Logs.

1 H Apparent Dip = tan

Dt

1 Dt

Relative Dip = tan H

True Formation Dip =Apparent Dip – Wellbore inclination

Where

H = Image Height (shown in figure 3.21) B = Relative Dip angle A = Apparent Dip angle = Well inclination DT = Measurement Diameter (ADN, DT =Stab Size +2 1in, GVR, DT =Stab Size +2 1.5in)

Image Height

Figure 3.21: Image Height Calculation

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A very important assumption that is made in this calculation is that the formation is being drilled perpendicular to the strike angle of the bed, as shown in figure 3.22.

Figure 3.22: Dip and Strike Calculation.

Strike - This is a horizontal line drawn on a bed, its orientation is expressed in degrees from north.

Dip - The angle between the strike and the bedding plane.

At times, due to erratic motion of the BHA while drilling a well, the logging tools may not always lie at the bottom of the wellbore, but rather climb erratically up the sides of the borehole. Unless extremely heavy muds are being used, the highest density will always be recorded when there is good contact between the detectors and the borehole wall. This means that the best density will not necessarily be the density derived from the bottom quadrant of the hole, and presented as ROBB.

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Figure 3.23: Image Derived Density

ARC Wizard in IDEAL is capable of providing a better density measurement than ROBB to compensate for this effect. This measurement is referred to as Image Derived Density, IDD, as it is derived from density images. It is a computed density calculated from the tool path around the wellbore, as shown in figure 3.23, where the green line indicates the path of the IDD.

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3.8 Review Questions

1. List two advantages of plotting neutron/density logs on compatible scales. 2. What are the requirements for being able to read density porosity off the neutron porosity

scale? 3. Which environmental effects will cause an increase in neutron porosity? 4. Name three quality control curves that should be included on all ADN logs to assist in their

interpretation. 5. Describe the function of each of the curves referred to as quality control curves. 6. Study the reservoir section shown in figure 3.24 and answer the following:

Figure 3.24: Limestone Reservoir Section

6.1 Is the log plotted on a Limestone compatible scale? 6.2 Can density porosity be read off the Neutron Porosity Scale, if so, what does it read? 6.3 What is causing the large separation of resistivity curves in this zone?

6.4 Calculate the density porosity at XX00, how does it compare to the value read off the log at the same point for Neutron Porosity? 6.5 What is causing the large difference between the Density Porosity and Neutron Porosity?

7. What is the limestone compatible density scale if the neutron scale is 43 to -17 p.u.

Answers at the end of the document.

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4. Lithology Identification The most commonly used lithology indicator is the measurement known as the Photoelectric Factor (PEF). Although the reading is affected by the porosity of the formation, the influence is only minor, unlike in the case of the density measurement.

4.1 PEF Measurement

PEF is derived from the gamma ray counts returning to the scintillation density detectors. There are a number of different PEF curves that could be presented to the client;

▪ PEU-PEF in upper quadrant ▪ PEL-PEF in left quadrant ▪ PER-PEF in right quadrant ▪ PEB-PEF in bottom quadrant ▪ PEF-Average PEF reading around the wellbore

PEF is very sensitive to the barite content in mud. Barite is a weighting agent that is added to the mud to increase the hydrostatic pressure of the wellbore. As a result, the amount of barite in the mud is related to the mud weight. PEF limitations are as follows:

Mud Weight > 9.5ppg PEF data should be dealt with cautiously. Mud Weight > 10.5ppg PEF data is invalid and must not be presented on logs.

PEF is a very shallow reading measurement which is very easily affected by standoff, especially when using heavy mud weights. For this reason, it is rather common to present the PEB value as the tool is most often lying on the bottom of the wellbore (check images).

4.2 Log Identification

The PEF reading has specific values in each formation type. Although these are affected slightly by the variance of porosity and subsequent formation fluids, the deviation is not profound. Typical PEF values for each formation can be found in figure 4.1, alongside the matrix density for each of the lithology‟s.

Figure 4.1: PEF readings in Common Formations.

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Logging While Drilling Interpretation Training Package

United Kingdom Training Centre, UK

Part-II Advanced Interpretation

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5. Reservoir Analysis

Reservoir interpretation is a key skill that should be attained by all involved in recording and analysing LWD data. LWD engineers will be able to portray a more advanced level of understanding of what is contained in the logs they are making and they will also be more capable of identifying unrealistic log responses which results in improved service quality.

The majority of the earth‟s hydrocarbon reserves are contained in either Sandstone or Limestone formations. Each of these formations will have vastly differing characteristics, and as a result will give unique log responses.

5.1 Sandstone Reservoirs

Sandstone reservoirs are estimated to contain around 50% of the earths hydrocarbon reserves (Berg, R.). A thorough understanding of both the composition and structure of the reservoir is required before optimum production from a reservoir can be attained.

5.1.1 Composition

Sandstone reservoirs are made up of grains of rock, primarily quartz, that are bound together with varying degrees of cementation (how well individual grains are bonded together). Cementation occurs due to the precipitation of carbonate and silica onto and between the sand grains. The individual sand grains that make up sandstone have sizes predominantly in the range of 0.25mm to 2mm in diameter. Particles larger than this would form rocks known as conglomerate; particles smaller than this would form siltstone and claystone.

Quartz - This is a mineral that is made up of crystallized Silicon Dioxide (SiO2), which has a density of 2.65g/cm3. It is one of the most common minerals making up the continental landmasses.

Sandstone reservoirs can also contain varying quantities of shale, which will have a major impact on the ability of the reservoir to produce hydrocarbons. The amount of shale present and its distribution within the reservoir are important properties that will need to be established for the optimal development of a reservoir. These properties depend on the environment in which the shale was deposited.

Shale - The word shale is a broad term that is used for sedimentary rocks that originate from the clay, silt and carbonates in varying quantities and structural arrangements. It is made up of very fine particles that will have a major impact on the porosity and permeability of a reservoir. Common types of shale that are encountered are kaolinite, montmorillonite and illite.

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Texture The texture of sandstone is an important property that will also influence the porosity and permeability of a reservoir. Texture refers to a number of rock properties including, grain size, sorting, orientation and packing structure of the individual sand grains. This information is obtained from core analysis.

Sorting Sorting is one of the most important properties that will dictate the permeability in sandstone. It refers to

how well the particles are segregated in terms of their size. Sandstone is said to be well sorted when all the particles of a particular size are gathered together. The amount of sorting that has taken place is directly related to the depositional environment.

Figure 5.1: Sorting of reservoir particles

The diagram on the left of figure 5.1 shows a reservoir that has been well sorted as it contains particles of only one size. To the right, there are particles of two different sizes, which, as can be seen, has a direct impact on the porosity of the formation.

Packing Packing will also have a large influence on both porosity and permeability. It refers to the contact that each grain has in relation to surrounding grains. A formation that is well packed, will have very little intergranular space and as a result, less porosity and most likely also less permeability.

Square

Packing

Rhombic

Packing

Figure 5.2: Effects of packing on Permeability and Porosity. The two cubes of sandstone shown in figure 5.2 are both identical in size and each also contain exactly the same amount of particles. The only difference between the two cubes is the packing orientation. The cube on the left has a square packing structure where there is minimal contact area between adjacent particles and as is shown, a large porous space. The cube on the right has a tight rhombic packing, particles have a large number of contact points and the resulting porosity is very much lower than for the square packing. Notice how much less volume the same amount of particles fills space in the second cube. The rhombic packing structure will result in a higher density as more rock particles can fit into the same volume of space.

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Composition Sandstone can appear in a variety of colours due to variations in the composition of the rock. Rocks that contain purely quartz will appear as a pale white colour. Residual hydrocarbons may give it a grey tinge while red may indicate the presence of an oxidized ore, such as hematite (iron ore). The presence of other minerals and particles will assist in the interpretation of the depositional environment of the reservoir and as a result, provide a better understanding of how to exploit the reservoir. The formation shown in figure 5.3 has two differing shades of sandstone. The area towards the exposed section shown has a pale white colour, suggesting a clear quartz rock, one third up the rockface, the colour changes to red, suggesting a high content of oxidized material but also a change in the depositional environment from the deeper formations.

Red-Sandstone containing Oxidized material

White-Quartz

Figure 5.3: Coloured Sandstone-Clarence South Africa

Porosity The porosity of any reservoir rock will determine the quantity of hydrocarbons that can be contained in the pore spaces

Porosity -The ratio of the volume of void space to the volume of solid material. Intergranular porosity, like that found in sandstone is referred to as Primary Porosity. A second type of porosity, known as secondary porosity is predominantly found in calcite (limestone) reservoirs. It exists as voids that were introduced after the deposition of the formation, in the form of vugs and fractures. Primary porosity in Sandstone can be calculated from the equation;

Vpore

100 VRock

For a sandstone, the porosity will vary from 30PU to 40PU for shallow formations that have not had that much pressure applied from the overburden rock to 10PU to 25PU for rocks that have been exposed to greater depths at some stage.

Porosity in sandstones is typically divided into two parts, primary and secondary porosity;

Primary Sandstone Porosity - Primary porosity in Sandstone includes the void spaces

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between solid particles.

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Secondary Sandstone Porosity - Additional void space can be made available for fluid occupation after lithification has occurred. This may occur due to leaching of certain minerals from the formation and removal of calcite by means of weak acidic formation fluids. This type of porosity is more likely to have a profound effect in Limestone reservoirs.

Permeability The permeability of a rock refers to how well a fluid is able to flow through the rock. This will determine how well a reservoir will allow the hydrocarbons to escape.

Permeability is measured in Darcies, which relates the flow path of a fluid and porosity of the rock with the ability of a fluid to flow through the rock. The Darcy is a large unit. As a result reservoir permeabilities are typically in the millidarcy range. A list of some common permeability ranges is shown below:

Granite: 0.0001 mD – 0.001 mD Limestone: 0.01 mD – 0.1 mD Sandstone: 1 mD – 10 mD

Highly Fractured Rock: 1105 mD - 110

8 mD Permeability ranges shown above are reported for the flow of water. The viscosity of hydrocarbons will vary according to its composition and as a result, will have different permeability values than water.

Formation permeability values can be obtained from Core Analysis, although Schlumberger does have an LWD tool (proVISION*) that is capable of providing this information whilst drilling.

5.1.2 Sandstone Depositional Environment

Understanding the depositional environment of reservoir rocks is very important to the production of a well. It will not only affect the properties of the rock (e.g. porosity and permeability) but also the distribution of the sandstone reservoir material, as is illustrated in figure 7.1.

Sandstone is a sedimentary rock that is formed from the deposition of eroded material. For this reason it is often referred to as a clastic rock. The eroded material is transported from the point of origin by various transport media.

Clastic Rock - A rock that has been formed from eroded fragments of other rocks.

The transportation media of eroded materials include water, wind and wave action. The transportation of material occurs in high energy environments, with larger particles being the first to be deposited as the energy of the transport medium reduces. The deposition of eroded material usually occurs in layers that are referred to as laminates for layers that are thinner than 1 cm and beds, when thicker than laminates.

The deposition process and subsequent changes that occur before lithification occurs are primary factors that determine the shape of a sandstone reservoir.

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Lithification – The process of by which sediments are converted into rock. It occurs under high pressures, typically when the sediments are buried deeper in the earth by subsequent layers being added above. As the pressure increases on the sediments, particles are often forced closer together and fluids are forced out (this process is referred to as de-watering in shales). Cementation will also occur to varying degrees. Both compaction and cementation will result in a decrease in porosity.

The reservoir size and shape are important for maximum exploitation of a reservoir. The oil in place and its recoverability is also closely related to the size and shape of a reservoir and thereby influence all field development decisions.

Well logs can be most accurately interpreted when they are studied in conjunction with core samples from nearby wells as well as cutting samples. The samples will provide valuable clues to the depositional environment which can be tied into the log responses observed.

GR Logs will display a lower reading as the quantity of sand in a zone increases. This is referred to as coarsening, when dealing with Sandstone as the Shale content typically drops with increased sand particle size (this has to do with the depositional environment)

Two primary depositional environments exist, marine and terrestrial environments. Each will be discussed in a little more detail with one or two examples discussed in each.

Marine Deposition

Marine sandstone deposits originate from a number of different environments, these include;

▪ Deltas ▪ Beach Sands ▪ Turbidites ▪ Offshore sandbars

Figure 5.4: Marine Deposition Environments (Montaron, B)

Deltaic sands are deposited at river mouths where a river enters a sea that does not have significant currents that will remove the deposited material. Material is deposited due to the transition from a high energy transport media in rivers, to a low energy area where there is not sufficient flow to maintain the particles in suspension.

Deltaic sands are characterized by thin laminates that are inclined slightly due to the deposition on a fan shaped structure that is buried deeper along the edges of the structure. They will display a coarsening of material, and lack of shale when moving upwards through the formation, which is due to the increased flow regime as the delta front progresses. The GR log will, as a result have a classic funnel shape.

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Figure 5.5: GR Response in Deltaic Sand Turbidite sands are sediments deposited as a result of density flow, which is the flow of suspended material due to the higher density of water containing the suspension than the surroundings.

Beach Sands and Shoreline Sands are deposited by means of wave action. Their depositional structure is closely related to the rise and fall of sea level over time.

Terrestrial Deposition

Terrestrial sand deposits occur in the following environments:

▪ Rivers ▪ Lakes ▪ Alluvial fans ▪ Glaciers ▪ Deserts (Eolian Sands)

Eolian Sands Eolian sandstone is formed by the deposition of sand by means of wind transportation. Common features include dune and ripple formation. The resulting reservoir will have laminates of sand that are spread over an entire dune surface and inclined at around 300 inclinations when dealing with sand dunes (slip face angle).

The porosity in Eolian sands can vary greatly due to the laminates, which will contain differing properties which may even result in permeability anisotropy.

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5.1.3 Sandstone Log Interpretation Topics

Before quantitative analysis can be made on a well, two measurement effects will need to be corrected on the neutron porosity reading.

The corrections that will be discussed can easily applied to a reservoir section by performing the following steps:

1. Extract the relevant information from the recorded mode CS-Depth files by making a

LAS file containing; Depth, GR, Density porosity, Neutron porosity

2. Choose values for GRmin and GRmax, as described in the VSH

Module 3. Import the LAS information into Excel 4. Perform the calculations shown below for each depth interval

calculation in the GR

Shale Effect Corrections Sandstone reservoirs are usually associated, to some degree or other, with shale, which has a major effect on logs.

The Resistivity is distorted by the presence of shale as they contain varying amounts of conductive minerals. This topic will not be discussed further, although it is worth mentioning.

The real problem with shales is the effect that they have on the porosity and permeability of a formation. When dealing with neutron porosity, the readings show extremely high values in shale due to the bound water that is present. The porosity that was attained from LWD tools is termed apparent neutron porosity, simply to differentiate it from the true porosity of the formation.

Although shales may appear very porous from their log response, they do not contribute at all to the reservoir porosity and in fact reduce the overall reservoir porosity. The bound water that is contained in shales is contained within small disconnected spaces that will not contribute to any flow when trying to produce from a well. For this reason, that portion will need to be removed from the tools response to give an effective porosity reading.

Effective Porosity- The portion of the total volume that is available for the flow of fluids. It will read less than the total porosity.

The volume of shale is determined from the GR log, this is discussed in detail in the first module of this

package, please refer back for an understanding on how to calculateVSH .

Once VSH

as follows;

has been determined, the corrections to both Neutron and Density Porosities can be made

NCorr

DCorr

N VSH NSH

D VSH DSH

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Where

Mattric SH

DSHr Matric

SH

N Neutron Porosity reading off log

D Density Porosity reading calculated from log response

NSH

Matrix

NCorr DCorr

Neutron Porosity reading read off log in 100% Shale Zone

Matrix density that was used in calculating density porosity in RM Processing

Corrected Neutron Porosity that can be used for Analysis

Corrected Density Porosity that can be used for Analysis

Gas Effect Correction Gas Effect is a measurement anomaly that occurs due to the low Hydrogen Index (HI) that is present in gas zones. A low HI will means that more neutrons return to the detectors, which is associated with a lower Neutron Porosity, causing an unusually large separation between the density and porosity readings.

The Gas Effect will need to be corrected before the client is able to determine the quantity of gas in the formation. This effect can be removed by applying the 3/5/8 equation to determine what the effective porosity will be.

The Neutron and Density Porosity that is used in this equation will need to have been corrected for shale effects, as discussed in the section dealing with Shale Effect, prior to being used here.

Effective 3 NCorr 5 DCorr

8 The above equation tends to provide accurate Effective Porosity readings for drilling data. However, when using ream data, it would be more accurate to use the 2/7/8 equation as it takes into account a slight correction for the effect of invasion.

Effective 2 NCorr 7 DCorr

9

A log generated from the Effective Porosity calculations shown above will now provide a reading that will be useful to produce the well. This value can now be used for petrophysical analysis.

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5.2 Carbonate Reservoirs

Carbonate reservoirs are said to account for more than 40% of all oil in place worldwide. A number of large reservoirs in the Middle East are present in Carbonate formations and should draw a lot of attention to their evaluation.

5.2.1 Carbonate Composition

Carbonate rock is formed by the sedimentation of marine organisms and is made up of carbonate minerals. There are two types of carbonate rock that are commonly encountered in the oilfields as reservoirs: Limestone and dolomite (often referred to as dolostone).

Limestone in composed predominantly of Calcite (CaCO3) and is formed by means of the deposition of marine invertebrates that settle to the ocean floor when they die. Limestone deposition is a very slow process and may take 1000 years to deposit 2 to 4 cm of sediment.

Dolomite is composed predominantly of CaMg(CO3)2 and is formed by a process known as Dolomitization.

Dolomitization is the process whereby Limestone is transformed into Dolomite when brought into contact with Magnesium Salts. The magnesium salts are transported by formation water, which brings about a progressive transformation:

Limestone — Dolomitic Limestone — Calcareous Dolomite — Dolomite

Porosity Carbonate porosity occurs in two different forms. Firstly there is the intergranular pore space, as is characteristic in Sandstone porosity, and then there is a second type of porosity in Limestone known as vugs. Vugs are simply holes, similar to those appearing in Swiss cheese, that form in Limestone. They can vary in size from sub millimetres to a few centimetres across. Voids larger than this can form, although they are referred to as cavities and can be up to man sized spaces in the rock.

Figure 5.6 shows a sample of limestone that displays a high quantity of vugs due to the presence of shells from organisms, deposited during the deposition of sediments. This photograph was taken of rock used in the construction of the Houston City Hall (take a drive Down Town after class one evening, it is worth the drive).

Figure 5.6: Limestone Vugs

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Permeability Permeability in Limestone can be extremely low in uniform limestone. Often production techniques in these formations include fracturing to induce more flow from carbonates. Dolomite tends to have a better permeability than limestone, this is mainly due to the smaller volume occupied by the material formed by the process of Dolomitization.

Porosity and permeability in Carbonates can be a very complex matter. Choquette and Prays have done a study on this topic, they classified the rock into groups, as is shown in figure 5.7.

Figure 5.7: Choquette and Prays Classification For good permeability readings, it is important that the porous sections in the reservoir are interconnected, as is shown for the fracture, channel and cavern classifications. These structures will allow for easy production and may not require stimulation. The presence of stylolites and fractures will have a major impact on the permeability.

The burrows and boring structures shown in the above classification are a result of living creatures that derived their sustenance or lived in the sediment when it was being laid down. These formations are referred to as Bioturbidites and can display varying amounts of burrowing, boring and mixing of the formation. A common environment for the development of this type of rock (but not limited to it) is in shallow coral reefs where numerous animals live in the sediments at the bottom.

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Impurities Limestone is usually white in colour. However, the presence of impurities may give it a different colour. Iron Oxide may give it a brown/red/yellow colour while carbon can result in a black/grey colour.

Shale, which was discussed at length in Sandstone formations, is typically not present in Carbonates due to the totally different depositional environments. Evaporates such as Anhydrite can be present in the rock matrix.

5.2.2 Limestone Depositional Environment

Carbonates have a vastly different depositional environment to silicates. They are formed in deep marine environments, evaporative lakes and also deserts, although the predominant environment is in deep water.

The initial material deposited consists of a granular structure. However, this is changed completely by means of diagenesis, cementation, leaching and dissolution, leaving a complex pore system.

The formation of stylolites in a reservoir can act as impermeable barriers. However, fracturing can greatly improve the permeability of a reservoir.

5.2.3 Limestone Log Interpretation Topics

Archies Equation, which was discussed in the Resistivity Section, works very well in water wet sandstone formations. However, it does not have as favourable results in carbonates, due mainly to the complex pore structure. Certain clients will however still use a modified version of Archies equation to calculate water saturation.

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Figure5.8: Dolomitization in a Carbonate Reservoir. (Sibbit, A.) Particles of dolomite are denser than limestone, which results in increased formation porosity in the form of vugs and cavities (man sized caverns) as the Dolomitization process progresses. Figure 5.8 shows how the process of Dolomitization is not always a reservoir-wide phenomenon, and how logs attained from one well will not necessarily be representative of the entire reservoir. Fractures seen in one well will not always be present in a well drilled a few feet away, which could have a major impact on the well‟s ability to flow. This poses a major problem to geologists when trying to determine the reservoir structure between wells. In addition to this, the formation of the vugs and cavities (during Dolomitization) may present major drilling hazards resulting in lost circulation whilst drilling and possibly even stuck pipe in highly fractured formations.

Limestone that has been dolomitized in certain sections is know as dolomitic limestone‟s. The type of formation that is being logged may be identified from both the GR and PEF logs. GR in Limestone reads, usually around 5 GAPI units higher than dolomite and the pef reading in Limestone reads around 5 whilst in dolomite it reads around 3. A sequence of Dolomitic Limestone is shown in figure 5.9.

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Figure 5.9: Sequence of Dolomitic Limestone

Figure 5.10: Limestone Reservoir

Limestone

Dolomite

Limestone

Dolomite

Limestone

A limestone reservoir is shown in figure 5.10. The PEF measurement in a limestone should read around 5, which is apparent throughout the section shown on the log. Resistivity displays a flat response, which is expected in Limestone due to the pore structure. For this reason, Resistivity logs are not always very useful in Carbonates, although certain clients will use it and make adjustments to Archie‟s equation to compensate for it.

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3. Review Questions

1. Refer to the log shown below and determine Shc at the depth marked on the log with an arrow. Ensure that you are clear on which point on the log you are using for your calculation. The neutron-derived porosity is presented in sandstone units. WBM was used with Rmf >Rw at formation temperature. The wet zone is very thin, but it‟s the only one we have shown on the log, so use it. For differentiation, Attenuation and Phase shift resistivity curves are presented on different horizontal scales respectively( 0.02 – 20 ohm.m and 0.2 – 0.200 ohm.m).

Courtosey-R.Talamantez

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Wet Pay Shale

R

N

D

GR

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6. Crossplots

A crossplot is a two-dimensional plot with one variable scaled in the vertical (Y) direction and the other in the horizontal (X) axis. The scales are usually linear but other functions, such as logarithmic scales, may also be used. Additional dimensions may be represented by using color or symbols on the data points. These plots are common tools in the interpretation of petrophysical and engineering data. (Oilfield Glossary, www.glossary.oilfield.slb.com)

There are a number of applications of crossplots that can assist in reservoir interpretation. These include;

Effective Porosity

Graphical Shale Volume Calculation

Lithology Identification.

Porosity and Lithology Identification

Apparent Matrix Parameter Determination

Apparent Matrix Volumetric

Photoelectric Factor Determination

Lithology Identification Permeability These crossplots can be made for any well that is running nuclear tools. It can be done either by means of specially written software, or simply by selecting a relevant reservoir zone and importing the data (in LAS format) into Excel where the required plots can be generated. Crossplots shown can all be found in the Schlumberger Log Interpretation Chart book. Templates of the required crossplots are available for downloading.

The Porosity and Lithology crossplot will be discussed in detail. The same principles apply when working with the majority of the crossplots that can be found in the Log Interpretation Chart book.

6.1. Effective Porosity Determination I

Many drilling environments encountered will contain a combination of rock matrices, which makes log responses rather difficult to interpret. The density/neutron porosity crossplot is useful for identifying the type of lithology present as well as the presence of shale and gas effects, and, once the relevant corrections have been applied, an effective porosity reading.

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B

Increasing

Gas

D

A

Increasing

Shaliness

C

Figure 6.1: Density/Neutron Porosity Crossplot for ADN6. The crossplot shown in figure 6.1 is Crossplot 24 and is taken from the log interpretation chart book. This type of chart is available for each of the nuclear tools and will provide an effective porosity reading, even in complex (mixed) lithology.

Density readings are plotted against the apparent neutron porosity for the zone of interest. For training purposes, this can be done by creating a simple excel spreadsheet.

Data that was recorded in clean (shale free) water filled sandstone will plot along the Sandstone line shown on the crossplot, the same will happen for limestone and dolomite formations. The presence of

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gas and shale will however cause a deviation from the data points plotting on the respective formation lines. These effects will need to be removed prior to making these crossplots.

Gas Effect Gas in a formation will cause a tool to read low neutron porosity as well as a low density reading which results in points plotting towards the top left corner of the crossplot, indicating the presence of gas effect.

Shale Effect The presence of shale will cause a tool to read very high neutron porosity due to the presence of bound water. Shale also has a high bulk density, which results in points plotting towards the bottom right of the crossplot, indicating the presence of shale effect.

It is very rare to find sandstone and shale in the same formation as limestone and dolomite due to the vastly different depositional environments in which they are formed. For this reason, there should be little or no shale effect when dealing with carbonates.

Intermediate Points Points that plot between the two lithology lines will be affected by more than one influence.

Sandstone, just like shale, will not be commonly found in the same formation as carbonates. For this reason, a point plotting between the limestone and dolomite lines will mean that the formation is made up of a combination of both limestone and dolomite and the relative proportions of the two lithologies can be found from the spacing of the point between the two lithology lines. This can be confirmed from cutting samples over the same interval.

The points plotted on figure 6.1 will now be discussed in more detail.

A - Should drilling be conducted in a silicate environment, this can be interpreted as a clean sand as it plots on the sandstone line, with a porosity of 6 PU. However, if drilling in a carbonate environment, it could be a mixture of limestone and dolomite but with gas effect playing a role. Before further analysis can be done, the gas effect needs to be removed and the points re- plotted.

B - This point displays a large Gas effect. The gas correction will need to be run before any interpretation can be done.

C - This point displays a large Shale effect. The shale correction will need to be applied before further interpretation is possible.

D - This point plots in between the Limestone/Dolomite Lines and can be interpreted in two ways: Should drilling be conducted in a silicate environment, the deviation from the sandstone line indicates the presence of shale which would need to be removed before an interpretation can be made. However, if drilling in a carbonate environment, it would indicate a lithology made up of both limestone and dolomite. The line joining the Limestone/Dolomite lines and also running through point D indicates a porosity of 28PU and the presence of the point 3/5 of the

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way towards the Limestone line means that the lithology is made of 60% Limestone and 40% Dolomite.

Upper Reservoir

Shale Zone

Lower Reservoir

Figure 6.2: Effective Porosity Crossplot An example of a cross plot is shown in figure 6.2. Three different zones are plotted on this crossplot. An upper sand zone is plotted in pink, it is plotting along the sandstone line, showing porosity values of 20- 22PU, the lower sand also plots in the same region, although both zones plot, on average, a little higher than the water filled sandstone line, which may indicate the presence of oil.

The two reservoir zones are divided by a shale zone, which has been plotted here to demonstrate the position that shale would plot, below the dolomite line and to the right.

6.2 Effective Porosity Determination II

The Density/PEF crossplot can be used to provide porosity readings as well as identify the lithology in the zone in question. The plot shown has been constructed using formations filled with water, presence of hydrocarbons would cause points to plot slightly differently.

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Rh

ob

( g

/cc

)

1.9

2

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3

Pe, Photoelectric Factor

0 1 2 3 4 5 6 Figure 6.3: Density/PEF Crossplot

Whenever interpretation is being done using a Pef reading, it should always be kept in mind that PEF is very sensitive to high barite content that was used whilst logging through the section. The amount of barite in the mud is related to the mud weight. Pef limitations are as follows:

Mud Weight > 9.5ppg Pef data should be dealt with cautiously. Mud Weight > 10.5ppg Pef data is invalid and must not be used in interpretation.

This crossplot can be used in much the same way as the porosity crossplot although in this case there is no dependence on neutron porosity, which removes the effect of the fluid in the formation.

6.3 Permeability Estimation

Permeability is a measurement that is crucial to the production of any well. The crossplot of Porosity and Water Saturation could be used for sandstone lithology to give an estimated permeability value.

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Figure 6.4: Permeability Estimate using a Porosity/Water Saturation Crossplot.

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7. Recoverable Hydrocarbon Estimation

Hydrocarbon reserves are the main assets of Oil and Gas Companies. Like all other companies, they have to report all assets on a balance sheet that has a major impact on the listing price for shares traded on the stock market.

A stringent set of rules governs the reporting of this type of asset as it is very difficult to quantify the hydrocarbons that can be produced from a reservoir. For this reason hydrocarbon reserves are categorized into three groups;

▪ Possible reserves - Those hydrocarbons that have a 10% chance of being produced.

Production from these reserves will only be possible under favourable conditions and may require excessive stimulation. These reserves include depleted zones that may be revitalized by means of advanced stimulation methods which may not yet have been proven in the field in question.

▪ Probable reserves - Hydrocarbons that have a 50% chance of being produced. Production from

these reserves with current technology is likely to be successful and also economically viable. This includes reservoirs that appear to contain hydrocarbons and the ability to produce but are lacking in regards to critical data like oil water contact points or core analysis.

▪ Proven reserves - Reserves that are well supported by Geological and Engineering data and

have a 90% chance of being produced. All the required technology and lease agreements are available for the exploitation of these reserves. Further support can be provided from producing wells that behave as predicted.

Only proven reserves are permitted to be presented as assents on the company‟s balance sheet, which means that official reserves reported underestimate the actual reserves.

A number of factors will have a major impact on the hydrocarbons in place calculations. All Estimates are only as good as the information that they are calculated with, which is why every little detail is important when processing logs.

7.1 Reservoir Thickness Calculations

Estimates of the reservoir thickness are obtained from logs produced in the wellbore. It is important that the following definitions are understood:

▪ Measured Depth (MD) - Distance from surface origin of wellbore, as measured along the well

trajectory. ▪ True Vertical Depth (TVD) - Vertical Displacement below surface origin. ▪ True Vertical Thickness (TVT)- The distance between the bottom TVD of the formation in

question and the bottm TVD.

TVT=TVDBottom- TVDTop

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A quick analysis of the reservoir should make use of the TVT thickness. Clients will use more complex well models to give a more accurate estimate of the oil in place.

7.2 Reservoir Area

The reservoir area can be estimated from seismic plots, as shown in Figure 7.1, A quick reference of the approximate size would be to use a plan view (view from above) that would give an indication of the horizontal extent of the reservoir.

Reservoir modeling techniques and data drawn from wells drilled in the reservoir will be used by Oil Companies to measure the extent of the reservoir. These models are continuously updated as fields develop, reducing the uncertainty of the actual reservoir extents.

A 2D (smooth section) and 3D (detailed section in middle) seismic plot is shown in Figure 7.1.

Figure 7.1: 2D and 3D Seismic data for Reservoir Modeling. (Managing Uncertainty in the Oilfields)

7.3 Recoverable Oil Estimation

The volume of recoverable oil on surface can be calculated from the equation;

7758 1

S N W

h A RF

R B

Where

N R

= Volume of Recoverable Oil.

7758 = Barrels per acre-ft

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= Effective Porosity expressed as a fraction.

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SW = Water saturation expressed as a fraction.

h = Vertical thickness of reservoir (ft) A = Horizontal extent of reservoir (acres) RF = Recovery Factor (0.2-0.4 for Oil) B = Volume Factor for oil (1-1.3). This value accounts for the expansion as pressure is

released when the oil comes on surface. The calculation shown for the Recoverable Gas Estimate is assuming a simple cubic reservoir shape. In

practice, the values for h and A are replaced by a term VO (Volume of Reservoir containing oil), which

can be calculated by means of integration techniques from geologic models.

Reservoir zones can be classified according to their SW , a typical cutoff used for defining a reservoir is

where SW >0.5. This means that any zone that has water saturation below this value is not counted

logged as a pay zone. Not all oil that is in a reservoir can be produced, a lot of oil is unable to flow out of the reservoir due to capillary forces. For this reason, the term RF was introduced. The value for RF will be chosen by the Oil Company, although it will be related to the production system, and matrix, amongst other.

As oil is produced and it rises to surface, the pressure will decrease, which results in an increase in volume. The decreased pressure also leads to volatile components coming out of solution and escaping, which contributes to a volume decrease. Temperature also decreases as the oil comes to surface, this contributes to a volume increase. The overall effect is that the volume of oil on surface is either the same, or less than that flowed out of the reservoir.

7.4 Recoverable Gas Estimation

The volume of Gas in a reservoir can be calculated from the equation:

GR 43560 1

SW

h A Pr

14.7

520

460 Tr

1 RF

Z

Where GR = Recoverable Gas in place

43560 = cubic ft per acre foot conversion

SW = Water saturation expressed as a fraction.

h = Vertical thickness of reservoir (ft) A = Horizontal extent of reservoir (acres)

Pr = Reservoir Pressure (psi)

Tr = Reservoir Temperature (oF)

Z = Compressibility Factor RF = Recovery Factor

The Recoverable gas in place is measured in cubic ft at Standard Temperature and Pressure (STP).

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Answers

1. The Gamma Ray Log

1. GAPI 2. Th, U,K 3. Bit size, tool size, mud weight and potassium content in the mud. 4. Plateau Gamma Ray Sensor 5. Correlation between wells, Depositional Environment Interpretation, Shaliness Determination,

Shale zone identification. 6. Refer to Figure 1.1 7. Correct for shale effects on other measurements.

8. V

GRLog GRClean

Shale GRShale GRClean

2. Resistivity

1. Vertical Resolution is the thickness that a formation bed would need to be before the desired

tool response can be attained. Two terms that are referred to in terms of Vertical Response are Qualitative and Quantitative resolution.

2. Attenuation has a larger volume of investigation, and as a result, will not be able to see thin beds as well as Phase Shift Resistivities.

3.

Attenuation Resistivity has a deeper depth of investigation, simply because it is a

slightly more focused measurement that Phase Shift attenuation and as a result is able

to travel deeper into the formation, as shown in figure 2.5. 2MHz (High Frequency) readings have Shallower Depth of Investigation than 400kHz

Shorter spaced transmitters have Shallower Depth of Investigation. 4.

Depth of Investigation increases with an increase in RT.

Attenuation Resistivity has a poorer Vertical Resolution than Phase Shift Resistivity.

400kHz (Low Frequency) has a poorer Vertical Resolution than 2MHz (High Frequency).

Vertical Resolution becomes poorer with increased transmitter spacing. Vertical Resolution becomes poorer with an increase in RT

5. Formation Resistivity, Transmitter Spacing, Type of Resistivity measurement,

Frequency of resistivity measurement

6. Correlation, Quantitative Analysis (how much oil), Qualitative Analysis (where the oil

is), Pore Pressure estimation, Invasion Identification, Geosteering.

7. 1- 0.35 ohmm

2- 2.5 ohmm

3. 10 ohmm

8. In the wet zone, shown on the log at the low Resistivity at 10890ft

Sandstone is being drilled so a =0.81

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S

m 2

RO 0.3 Ohmm

30PU = 0.30

In Wet Zone- R RO

W a

0.3 0.3

0.81

0.033 Ohmm

In Pay Zone- n

aRW W R

m

0.81 0.033

0.046 13 0.21

2

T

RT 13 Ohmm

21PU = 0.21

SW 0.046 = 0.22

A water saturation of 22% means that this would be a zone of much interest for production.

3. Density and Porosity

1. Crossover can be identified as Hydrocarbons, overlaying density and porosity can be

interpreted as water. 2. The corresponding matrix calculation must be used for the type of formation drilled. Compatible

scale must be used. 3. Increased Mud Temperature, decreased Mud HI, Decrease in Borehole and Mud Salinity. 4. RPM, DRHO, Caliper (Verd, Hord). 5. RPM-Sliding Indicator, DRHO-Measurement Reliability Indicator, Caliper-QC measurement and

also support DRHO response. 6. 1-Yes

2- Yes it can be read off the TNPH scale, if the Matrix used to calculate the TNPH was processed for Limestone Matrix. DPOR (Off TNPH scale)=36PU 3- Permeable Zone, suggests WBM invasion profile.

4- Density Porosity =

DPOR = 35 PU TNPH = 15 PU

ma b

ma f =

2.71 2.1 =0.356

2.71 1

5- Gas effect, refer to Sandstone Reservoir Section for correct interpretation of this section.

7. 2-3 g/cm3

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5. Reservoir Analysis

Wet Pay Shale

R 0.3 50 0.9 not required

N 0.23 0.15 .39

D 0.23 0.36 0.09

GR Clean 30 Zone 37 Shale 105

Rw = 0.02 ohm.m Vsh = 0.09 NCORR = 0.15-0.09(0.39) = 0.115

DCORR = 0.36-0.09(0.09) =0.35 DCORR >NCORR; therefore require gas correction

e = 3/8(0.115) + 5/8(0.35) = 0.26 Sw = (0.81/0.26^2) (0.02/50)= 0.069

quicklook Ro/Rt = 0.3/50 = 0.077 Shc=1-Sw=1-0.069=93.1%

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Acknowledgements

Much appreciation to those that have reviewed this project. Asif Khalil and Julian Fletcher, Thank you for the hours of advice and reviews that you have put in.

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References

1. Berg, R., 1986, Reservoir Sandstones, Texas A&M University, Prentice Hall.4

2. Carbonate_WhitePaper2001.pdf 10

3. CDN Training Manual, 1996 9

4. Forest, A. Oil and Gas Reserves Classification, Estimation and Evaluation. Society of

Petroleum Engineers, 1985. (SPE 13946)8

5. Hansen, S., Houston Solutions Interpretation Development. 5http://www.dallas.geoquest.slb.com/houston-id/shansen/shansen.html. Oct 2006.

6. Managing Uncertainty in the Oilfields, Middle East Evaluation Review, 1992.

7http://www.slb.com/media/services/resources/mewr/wer12/rel_pub_mewer12_3.pdf, Oct 2006.

7. Montaron B., Fractals, Percolation Theory and Stability of Archie‟s m Exponent Low Resistivity Pay in Carbonates. 1www.eureka.slb.com/Files/NewsEvents/m_exponent.pdf Sep 2006.

8. Parasher A., Dolomitization- An Enhanced Oil Recovery Technique SPE International Student

Paper Contest.2

9. Shaly Sand Interpretation, Sugar Land Learning Centre, 1999.6

10. Sibbit A., Formation Evaluation in Complex Reservoirs A well-log interpretation course focused

on Russian oil and gas fields. Schlumberger Russia Technology Hub. Sep 2006.3