BASIC LOG INTERPRETATION_HLS

BASIC LOG

INTERPRETATION

Log Interpretation Seminar/ Workshop

(14

_{– 16}

_{May 2007, New Delhi)}

Name: _____________________________________

INDEX

Section – 1

BASIC ANALYSIS CONCEPTS

Section – 2

POROSITY AND MINERALOGY

Section – 3

ENVIRONMENTAL CORRECTIONS

Section – 4

CLEAN FORMATION EVALUATION

Section – 5

ADDITIONAL LOG

INTERPRETATION TECHNIQUES

Section – 6

SHALY SAND THEORY

Section 1

Basic Analysis Concepts

Table of Contents

Introduction………. 3

Objectives……….…….. 3

Formation Evaluation and Log analysis………. ₄

The Basis for Log analysis………... 5

Water Saturation of Clean formations……… 6

Archie's Equation dissected………. 10

Essential Calculations……….. 10

Determining Geothermal Gradient……….. ₁₁

Determining Formation Temperature (Tf)……….. 11

Determining Rm f from Rm……….. 12

Correcting Resistivity for Temperature……….. 12

Determining Formation Water Resistivity (Rw) by the Inverse Archie Method……… 13

Example Application of Archie's Equation………. ₁₃

Rw Calculation by Inverse-Archie Method……….. 15

Sw Calculations……….. 16

Permeability Indicators………. 17

Determining Formation Water Resistivity (Rw) by the SP Method………. 19

Detailed Procedure of SP Method……….. ₂₀

Additional Notes about Formation Water Resistivity……… 21

Additional Rw Calculation Example………. 21

"Quick-Look" Methods in Log Analysis……….. 25

Introduction

This section presents an overview of the basic concepts of open hole log analysis and provides practical examples of the techniques and methods. A working knowledge of each of these concepts is fundamental for performing a basic well-site analysis.

Objectives

After completing this section, the participant should be able to

§ clearly identify and mark on a log the potential water-bearing zones

§ clearly identify and mark on a log the potential hydrocarbon-bearing zones.

§ recognize potential water-bearing zones that are amenable to formation water resistivity (Rw) derivation by judging their cleanliness, porosity, and qualitative

permeability.

§ estimate lithology of potential water-bearing and hydrocarbon-bearing zones. § calculate the cross-plot porosity of a zone of interest.

§ select appropriate values for tortuosity factor (a) and cementation exponent (m) values required for calculating formation water resistivity (Rw) and water saturation

(Sw) in zones of different lithology and/or porosity.

§ calculate geothermal gradient (gG) for a particular well location by equation and by

chart.

§ calculate formation temperature (Tf) for any depth of interest by equation and by

chart.

§ determine values for mud filtrate resistivity (Rmf) and mudcake resistivity (Rmc) from

mud resistivity (Rm) by chart and by equation.

§ convert measured and/or derived resistivity values (Rm, Rmf, Rmc) to formation

temperature (Tf) for any depth of interest by equation and by chart.

§ calculate value for formation water resistivity (Rw) in a selected clean waterbearing

zone by inverse-Archie method.

§ determine value for formation water resistivity (Rw) in a selected clean waterbearing

zone by SP method.

§ determine a reasonable and optimistic value for formation water resistivity (Rw) by

comparing values derived from inverse-Archie and SP methods.

§ convert derived values of formation water resistivity (Rw) to formation temperature

§ calculate water saturation (Sw) for a clean hydrocarbon-bearing zone by Archie

equation.

§ calculate hydrocarbon saturation (Shc) for a clean hydrocarbon-bearing zone by

equation.

§ clearly identify and mark on a log potential perforated intervals based on water saturation (Sw) calculations.

Formation Evaluation and Log Analysis

Formation evaluation can be generally defined as the practice of determining both the physical and chemical properties of rocks and the fluids they contain. The objective of formation evaluation is to locate, define, and produce from a given reservoir by drilling as few wells as possible. To this end, oil companies utilize a variety of formation evaluation methods, some of which are outlined in Figure 1.1.

Figure 1.1. Formation Evaluation methods

Exploration Define Structure Seismic, gravity mapping, magnetic

mapping

Drilling Drill well Mud logging, whole coring, MWD

Logging Log well Open hole logs

Primary Evaluation Log analysis and testing Sidewall cores, vertical seismic profile (VSP), Wireline formation testing, drillstem testing

Analysis Core analysis Laboratory studies

Feedback Refinement of seismic model

and log analysis

Log calibration via core analysis results, seismic calibration from log analysis results

Exploration Producing hydrocarbons Material balance analysis Secondary

recovery

Water or gas injection and production logging

Production log analysis, flood efficiency analysis, micro-rock property analysis

Abandonment Economic decisions

Wireline logs are one of the many different sources of data used in formation evaluation. However, due to accurate depth determination and near proximity of receiver to formation, wireline logs occupy an important position in formation evaluation. Logging is a very small, but very important, piece of the larger puzzle. The decision to

plug or complete a well is often based upon the logs response and hence a proper and accurate acquisition and analysis of these data is a must.

The Basis for Log Analysis

Resistivity is, perhaps, the most fundamental of all measurements in logging. All geological materials possess some amount of resistance which is inherent to the flow of an electrical current. Resistivity (R) is the physical measurement of resistance and is defined as the reciprocal of material's electrical conductivity (C).

Rock matrix, oil, and gas are electrical insulators. They will not conduct the flow of an electrical current and therefore their resistivities are said to be infinite.Water, however, will conduct electricity depending upon its salinity. This implies that any current flow through a formation is taking place in the formation water,and not hydrocarbons or the rock matrix. Salt water, with high concentrations of dissolved solids (e.g., NaCl, etc.), will conduct electricity much more readily than will fresh water. Therefore, salt water has a much lower resistivity than fresh water. In most instances, the water present in a formation at depth will be moderately saline. Water-bearing zones, therefore, have

higher conductivity--or lower resistivity--than hydrocarbon-bearing zones.

Because oil and gas will not conduct electrical current, it is impossible to distinguish them from rock matrix on the basis of resistivity. These fluids do, however, fill the pore space of a formation, leaving less room for conductive formation water. The electrical current that does flow through a hydrocarbon bearing formation is forced to take a more tortuous path, weaving around the hydrocarbon that occupies part of the pore space.

The overall effect of the presence of hydrocarbons is an increase in resistivity.

The basis for log analysis is to compare the measured resistivity of a formation with the calculated resistivity of that formation assuming its porosity is 100% water-filled. The resistivity of a rock at 100% water saturation is referred to as wet resistivity (Ro). If, for a

given porosity, the measured resistivity is significantly higher than the wet resistivity, then the presence of hydrocarbons is indicated. This relationship is the basis for determining the percentage of porosity that is filled with formation water (water

saturation) and therefore the percentage of porosity that is filled with hydrocarbon

(hydrocarbon saturation). Water saturation (Sw) for a clean formation may be calculated

using the Archie equation.

Archie Water Saturation

Water Saturation of Clean Formations

Consider a formation with a given amount of porosity and assume that porosity is completely filled with saline formation water of a given resistivity (Figure 1.2). The

formation water resistivity (Rw), because the saline water is capable of conducting

electrical current, is quite low. The resistivity of the formation itself (Ro, or wet resistivity,

where porosity is 100% filled with water) will depend upon the formation water resistivity and some other factor referred to as the formation resistivity factor (Fr).

Figure 1.2. Model formation: 100% water saturated.

By rearranging this equation, formation resistivity factor (Fr) can be quantified as the

ratio of the formation's wet resistivity to the resistivity of the water (Rw) present in that

formation.

In this example, formation water resistivity (Rw) is defined as constant and therefore,

changes in formation resistivity factor (Fr) will occur only with changes in the overall

formation resistivity (Ro). The one way in which Ro can change in a formation of

constant Rw is by changing the amount of fluid available to conduct an electrical current.

This is accomplished through changes in porosity. As porosity decreases, the amount of water available to conduct electrical current is decreased, resulting in an increase in formation resistivity (Ro). Therefore, formation resistivity factor (Fr) is inversely

proportional to porosity (Φ).

This relationship between formation resistivity and porosity was researched by G.E. Archie of Shell Oil while working on limestones in France. Archie had electric (resistivity) logs from several wells, and core porosity from productive zones within these wells. He noticed that there was some relation between resistivity and porosity, and thus was able to identify zones of interest through the use of electric logs alone. What he wanted to know was the existence of some relationship that makes it possible to determine whether a zone would be productive on the basis of measured resistivity and core porosity.

Changes in the porosity of a formation may have effects other than simply increasing or decreasing the amount of fluid available to conduct electrical current. With a change in porosity, there may be concomitant changes in the complexity of the pore network that affect the conductive nature of the fluids present, and formation resistivity factor (Fr) can

therefore vary with the type of reservoir. These changes are expressed by the tortuosity

factor (a) and cementation exponent (m).

For the limestones of Archie's experiments, the tortuosity factors and cementation exponents were always constant (a = 1.0, m = 2.0). However, this may not be the case for all reservoirs. Although both parameters can be determined experimentally for a specific reservoir, log analysts commonly use set values for tortuosity factor (a) and cementation exponent (m) depending upon lithology and porosity. These standard values are presented in Figure 1.3.

Figure 1.3. Standard values for tortuosity factor and cementation exponent.

Consider now that the porous formation discussed previously is filled with some combination of conductive formation water of constant resistivity (Rw) and oil (Figure

1.4). Oil is an insulator and will not conduct electrical current. Furthermore, because the formation is filled with both water and oil, the resistivity of the formation can no longer be referred to as wet resistivity (Ro).

The measure of formation resistivity in this instance--taking into account the resistivity of the rock matrix and the fluids contained--is called true resistivity (Rt).

True resistivity of a formation will only be equal to wet resistivity (Rt = Ro) when the

porosity of that formation is completely filled with conductive water. However, because some of the available porosity may be filled with nonconductive oil or gas, the wet resistivity (Ro) of that formation can now be related to the measured true resistivity (Rt)

by some additional factor, referred to as F'.

The factor F' can therefore be expressed as a ratio of the theoretical wet resistivity of that formation (Ro) to the actual omeasured resistivity of the formation (Rt)

In this example, because both porosity and formation water resistivity (Rw) are

considered to be constant, the resulting wet resistivity (Ro) will be constant. Therefore,

changes in the factor F' will occur with changes in measured true resistivity (Rt). Under

the given conditions, the only way in which measured true resistivity (Rt) of the

formation can change is through the addition or subtraction of conductive fluid. For example, the addition of oil to the reservoir would result in the increase of that formation's measured resistivity (Rt) because some amount of conductive formation

water would be displaced by the oil. Therefore, the factor F' is dependent upon the relative proportion of conductive fluids (water) and non-conductive fluids (hydrocarbons) in the formation.

The factor F' in the above equation represents water saturation (usually expressed as

Sw) which is the percentage of pore space within a formation that is occupied by

conductive formation water. By substitution of equations, water saturation can be

related to the physical properties of the formation and the conductive properties of the fluids it contains.

Water saturation is related to these properties by the exponent n (saturation exponent). Saturation exponent may have a range of values dependent upon specific reservoir conditions, but generally is assumed to be equal to 2.0. With knowledge of the production characteristics of the formation in question, it is possible to determine more accurate values for saturation exponent.

The equation for water saturation (Sw), an expanded version of that presented as a

footnote in Archie's 1942 publication and commonly referred to as "Archie's equation," has become the foundation of the entire industry of well logging. In its simplest form, Archie's equation is often expressed as:

where:

n = saturation exponent a = tortuosity factor Φ = porosity

m = cementation exponent Rw = formation water resistivity

Rt = true formation resistivity

It is important to realize that while water saturation represents the percentage of water

present in the pores of a formation, it does not represent the ratio of water to

hydrocarbons that will be produced from a reservoir. Shaly sandstone reservoirs with clay minerals that trap a large amount of formation water may have high water saturations, yet produce only hydrocarbons. Water saturation simply reflects the relative proportions of these fluids contained in the reservoir. Nonetheless, obtaining accurate values for water saturation is the primary goal of open hole log analysis. With knowledge of water saturation, it is possible to determine what percentage of porosity is filled with a fluid other than water (i.e., hydrocarbons) and therefore, hydrocarbon reserves.

Archie's Equation Dissected

Essential Calculations

Log analysis calculations require values of resistivity, in particular mud filtrate resistivity (Rmf) and formation water resistivity (Rw). A single measured or calculated value of Rmf

and/or Rw may need to be applied over a wide range of depths. Because resistivity

appropriate temperatures at depth. Bear in mind that Rmf and/or Rw must be corrected to

the temperature at a certain depth if those values are to be used in calculations.

Determining Geothermal Gradient

The first step involved in determining temperature at a particular depth is to determine the geothermal gradient (gG) of the region. Temperature increases with depth, and the

temperature gradient of a particular region depends upon the geologic, or tectonic, activity within that region. The more activity, the higher the geothermal gradient. Geothermal gradients are commonly expressed in degrees Fahrenheit per 100 feet (?F/100'). If the geothermal gradient of an area is not known, then it can be determined by chart or by formula. If using a chart, it is important to use the correct chart, depending upon your location. Instructions and an example for using these charts accompany charts GEN-2a (international locations) and GEN-2b (North America locations).

Geothermal gradient may also be determined by taking pertinent information from the header and using the following equation:

Note that both the chart method and the formula method require a value for mean

surface temperature (Tms). This refers to the average annual temperature of a region,

and not the temperature at which resistivity measurements were made during the logging job (e.g., mud press resistivities). Mean surface temperatures for international and North America locations are presented on charts GEN-2a and GEN-2b, respectively. If the mean surface temperature for a region is not known, then it is standard practice to assume 75?F as a value for Tms, and realize the potential

calculation errors that may result from this assumption.

Determining Formation Temperature (T

)

Once the geothermal gradient (gG) has been established, it is possible to determine the

temperature for a particular depth. This is often referred to as formation temperature (Tf). As with geothermal gradient, Tf may be determined through the use of charts

Determining R

from R

In some cases, a value of mud filtrate resistivity (Rmf) may not be available from the

header, or there may be a question about the validity or accuracy of the measurement. A value of Rmf may be obtained from the mud resistivity (Rm) through the use of chart

GEN-3. This chart requires only mud density (or mud weight) as input, and allows the determination of both Rmf and mudcake resistivity (Rmc) from Rm. It should be

remembered that values of Rmf obtained from this chart also require correction to

formation temperature before their use.

Correcting Resistivity for Temperature

Resistivity decreases with increasing temperature, and therefore any value of Rmf

and/or Rw determined at one depth must be corrected for the appropriate formation

temperature (Tf) where those values will be used to calculate water saturation (Sw). It is

vital that formation water resistivity (Rw) be corrected for temperature. Failing to correct

Rw to a higher temperature will result in erroneously high values of water saturation

(Sw). Therefore, it is possible to calculate a hydrocarbon-bearing zone as a wet zone if

the temperature correction is not applied.

Correction may be applied through the use of a chart (GEN-5) or an equation (Arp's equation). Chart GEN-5 may be used to determine the resistivity of a solution (such as Rm, Rmf, Rw, etc.) at a given temperature when the NaCl concentration of that solution is

known, and vice versa. It may also be used to determine the resistivity of a solution at a given temperature when the resistivity of this same solution at another temperature is known. Instructions and examples for these particular uses accompany chart GEN-5. A more straightforward method of correcting resistivity for temperature is through the use of Arp's equation:

Determining Formation Water Resistivity (R

) by the

Inverse Archie Method

Determining a value for formation water resistivity (Rw) from logs may not always

provide reliable results; however, in many cases logs provide the only means of determining Rw. Two of the most common methods of determining Rw from logs are the

inverse-Archie method and the SP method.

The inverse-Archie method of determining Rw works under the assumption that water

saturation (Sw) is 100%. It is necessary, therefore, that the inverse-Archie method be

employed in a zone that is obviously wet. Furthermore, it is desirable to calculate Rw

from the inverse-Archie method in a clean formation with relatively high porosity.

Once a clean and porous wet zone is located, lithological assumptions must be made about that formation in order to select the appropriate values of cementation exponent (m) and tortuosity factor (a) to use in the equation. This estimate should be accomplished by quick-look means using a combination of the gamma ray, porosity, and Pe curves. Formation water resistivity calculated by the inverse- Archie method

(Rw a) depends upon lithology; however, Rwa calculated in one lithology can be used for

water saturation (Sw) calculations in a zone of different lithology. For example, Rwa may

be determined in a sandstone, and this value may then be used in the Archie equation to calculate water saturation (Sw) in a limestone, provided that the necessary

temperature corrections have been made. This is one of the many assumptions that must be made in log analysis applications.

Example Application of Archie's Equation

The following examples are worked with respect to the log presented in Figure 1.5. It is assumed that any zones of interest are limestone.

By first observing the resistivity log, one can infer that the areas of high resistivity (8515 and 8610) indicate zones containing hydrocarbons. Areas with low resistivity (8535 and 8710) are more likely to contain conductive formation water. These axioms are not always correct because high resistivity in a formation may also be caused by a lack of porosity. Therefore, sections of higher porosity (8515 and 8710) should be of more interest than those with lower porosity (8610). The flat-line areas, falling between the zones of interest, are assumed to be nonproductive shale zones.

For optimistic values of Rw to be obtained, a zone most likely to produce 100% water

should be chosen for calculations. This zone should have low resistivity and relatively high porosity. There are two obvious zones fitting these criteria (8535 and 8710). The zone at 8710 has higher porosity; however, the zone at 8535 is in close proximity to the hydrocarbon zone just above it at 8515. The Rw value of this wet zone probably closely

matches the Rw value of the hydrocarbon zone because they occur at virtually the same

depth. On a more pessimistic note, however, this upper wet zone (8535) may contain some hydrocarbons because both the wet zone and hydrocarbon zone occur in the same porous lithologic unit. Because two wet zones are present, values of Rwa should

be calculated for both, and the lesser of these two values should be used in order to obtain more optimistic water saturation (Sw) results.

Lithology of the zones of interest has been given as limestone. Therefore, for all calculations, the appropriate values of cementation exponent (m) and tortuosity factor (a) must be assumed. In this case, for limestone, a = 1.0 and m = 2.0.

In any case where Rw may be calculated in different zones or by different methods, the lowest calculated value of Rw (within reason) should be used in

order to obtain more optimistic (lower) calculated values of water saturation. This is a critical assumption!

R

Calculation by Inverse-Archie Method

There are several possible explanations for the variance in calculated values for Rw a.

The lesser of the two values (at 8710) may possibly be the result of a cleaner wet zone. It could also be the result of the water at 8710 having a completely different salinity than the water at 8535. More than likely, the higher value (at 8535) results from the fact that the wet zone probably contains residual hydrocarbons from the overlying zone.

The decision of which value of Rwa to use in water saturation calculations should be

based on experience, common sense, and logical deductions. All of the conditions discussed above should be considered.

For the purposes of this example, the lowest value of formation water resistivity from 8710 (Rw = 0.038 ? -m) will be used. This value, because it is the lesser of the two, will

produce more optimistic values of water saturation.

Once a reasonable value for Rw is established for a zone or groups of zones, it should

be temperature corrected for depth, depending upon the differences in depth between its origin and its implementation. This is accomplished by using either GEN-5 or Arp's equation. In this particular example, the temperature variation between the top and bottom of the log is only 2?F, therefore no temperature correction is necessary.

S

Calculations

Potential hydrocarbon-bearing zones may now be evaluated using the value for Rw that

was previously established. High resistivity and high porosity typically characterize hydrocarbon-bearing formations, again because of the nonconductive behavior of oil and gas. There are two zones illustrated in Figure 1.5 that fit these criteria--8515 and 8610. The zone at 8610 has very low porosity; its high resistivity results from the fact that there is little pore water available to conduct current. The zone at 8515 has good porosity (~28%), and warrants further investigation.

When taking measurement values from a log for use in the Archie equation, it is desirable to select a single depth rather than averaging values across a zone. Through the course of actual interpretation there may be many appealing formations. In any single formation, an analyst may choose several depths at which to calculate water saturation (Sw). Because the zones in the example log are so well defined, only two

Permeability Indicators

Scanning a log in search of zones with high porosity and high resistivity may yield a number of appealing formations. However, the presence of high porosity and high resistivity does not necessarily mean that a formation that contains hydrocarbons will actually produce those hydrocarbons (especially without stimulation or hydraulic fracturing). Without data from a Formation Tester or Magnetic Resonance Imaging log, quantitative estimates of permeability are lacking. Permeability refers to the ability of a

formation to transmit the fluids it contains through the existing pore network, and is a fundamental requirement of a productive reservoir.

Some standard open hole logging services provide several means of getting a

qualitative estimate of a formation's permeability. The most commonly used

permeability indicators are the Micro Electric (or Microlog) and the Spontaneous Potential (SP) tools. The Microlog indicates permeability when there is separation between the Micronormal (or Normal) and Microinverse (or Lateral) curves. The Micronormal curve will read a higher resistivity than the Microinverse curve because of the effects of mudcake (Rmc) on the resistivity measurements. Mudcake can only be

present opposite a permeable formation, therefore the presence of this separation is used as a qualitative indicator of permeability. The Spontaneous Potential, apart from providing a qualitative estimate of permeability, may also be used to determine a value of formation water resistivity (Rw).

A permeability indicator (in this case the SP response) for the log presented in Figure 1.5 might appear as the curve presented in Track 1 of Figure 1.6. The SP will often respond in such a way that it reflects the same trend as the porosity device; however, this is not always the case. Negative deflections of the SP curve are used as qualitative indicators of permeability. Permeable zones in this example log (Figure 1.6) are indicated at 8500 to 8535, 8595 to 8610, and 8680 to 8720. The zone responsible for the most SP deflection (8700) is not necessarily the zone with the most permeability. Likewise, because the zone at 8500 exhibits less SP deflection than the zone at 8700, this does not mean that it has less permeability than the deeper of the two formations. Whereas the presence of negative SP deflection may be an indicator of permeability in a particular zone, the absence of any deflection does not indicate an absence of permeability.

If permeability is not evident on a log, evaluation of the porosity and resistivity curves can still result in low water saturation calculations. Depending upon the geology and the type of tool used to indicate permeability, hydraulic fracturing or other formation treatment methods may be necessary to produce hydrocarbons.

Locating permeable zones using SP response is an important first step in any "quick-look" analysis program.

Figure 1.6. Example log illustrating permeability indicator (SP curve) in Track 1.

Determining Formation Water Resistivity (R

) by the

SP Method

Once zones of interest are located by observing trends in their resistivity, porosity, and permeability indicator responses, determination of formation water resistivity (Rw) is in

order. As discussed previously, Rw can be calculated by rearranging the Archie

equation and assuming a water saturation (Sw) of 100%. An additional method of

assessing Rw is through the use of an SP versus Rmf chart (SP-4), and is referred to as

the SP method. As with the inverse-Archie method, the SP method gives best results in clean and relative porous formations. However, because virtually anything and everything affects the SP measurement it sometimes does not yield reliable results. The SP method may be advantageous in certain circumstances where porosity data are not available.

Several steps are involved in determining Rw from the SP response. These procedures

are outlined in Figure 1.7.

Detailed Procedure of SP Method

Determine Formation Temperature (Tf)

From chart GEN-2b, locate the mean surface temperature (Tms = 60oF) for the Mid-

ontinent. Using this value, determine the geothermal gradient (gG = 1.14oF/100') and

formation temperature (Tf = 159oF) from the chart or by the appropriate equation.

Determine Rm f

Plot Rm = 0.88 Ω-m versus Rm reference temperature (70oF) on GEN-5. This results in a

salinity value of 7,000ppm NaCl. Following this salinity curve to the formation temperature of the zone of interest (Tf = 159oF) results in a mud resistivity (Rm) value of

0.40 Ω-m at 159oF.

With the value of the mud resistivity (Rm = 0.40 Ω-m) at the proper formation

temperature (Tf = 159oF), use GEN-3 to determine Rmf = 0.22 Ω-m and Rmc = 0.75 Ω-m

at 8710.

Plot Rmf and Determine SSP

Plot Rmf = 0.22 Ω-m on the X-axis of SP-4. Project a vertical line upward to an

interpolated imaginary line representing Tf = 159oF (slightly less than half-way between

150oF and 175oF). From this point, extend a horizontal line to the Yaxis to find SSP = -132mV.

Determine SP Deflection

Assuming the SP base line to be the second division from the right of Track 1, the deflection at 8710 is -70mV.

Differentiate Between SSP and SP

Re-enter SP-4 on the Y-axis at 62mV. Project a horizontal line to intersect the interpolated imaginary line representing Tf = 159oF.

Determine Rw

From the intersection determined in the previous step, project a vertical line downward to the X-axis. This plot should fall on a value of Rw = 0.037 Ω-m. There is a 0.001 Ω-m

difference between the Rw values determined by the inverse-Archie method and the SP

method at 8710 (Rwa = 0.038 Ω-m and RwSP = 0.037 Ω-m). This minor difference is in

support of the fact that both measurements likely represent accurate values of formation water resistivity (Rw). Water saturation (Sw) calculations using these two

Additional Notes on Formation Water Resistivity

Determining an accurate value of formation water resistivity (Rw) from logs is often quite

difficult, and usually not as straightforward as presented in these examples. A zone that is assumed to be 100% water saturated may, in actuality, not be. The presence of hydrocarbons may suppress any SP deflections, resulting in erroneous calculations. Furthermore, in a slightly shaly formation, clay minerals may result in abnormally low resistivities. Perhaps the most dangerous situation is assuming that a particular zone is wet when it actually contains hydrocarbons. This misinterpretation will result in compounded errors in the process of log analysis.

When possible, it is best to calculate formation water resistivity (Rw) using a variety of

methods at several different depths. The results can then be ranked and compared to reveal a "best pick" for the reservoir. In an effort to be optimistic in water saturation (Sw)

calculations, it is usually beneficial to pick the lowest value (within reason) of formation water resistivity (Rw). The worldwide average for formation water resistivity without

correcting for temperature is 0.05 Ω-m. Additional methods of evaluating formation water resistivity will be discussed in later sections of this text.

Additional R

Calculation Example

The log for this example calculation is illustrated in Figure 1.8. The objective is to determine an appropriate value for Rw from the log. It may be assumed that any zones

of interest are sandstone.

Given

Location: Santa Cruz, Bolivia T.D.: 3,600 meters B.H.T.: 60 deg. C Mud weight: 13 lbs/gal Drilling Fluid Constituents:

Sodium 3,000 ppm Chloride 4,000 ppm Magnesium 2,900 ppm Calcium 2,500 ppm

Define Zones of Interest

The only worthwhile SP deflection occurs from 2775m to 2830m. Within these limits there are two definite zones of interest. The upper zone (2790m) has low resistivity and high porosity, and is an ideal choice for Rw calculations assuming 100% water

saturation. The lower zone (2815m) has high resistivity and high porosity, making it a likely candidate for a hydrocarbon-bearing zone. The zone at 2900m exhibits no indication of permeability, and has both lower resistivity and lower porosity than the zone at 2815m. Because the SP response may be suppressed by the ratio Rmf/Rw, a

Determine Formation Temperature (Tf)

From chart GEN-2a, determine the mean surface temperature (Tms = 15oC) of Santa

Cruz. After establishing a base line, project a vertical line upward from BHT = 60oC on the X-axis, and project a horizontal line from the right of the TD (3600m) on the Y-axis. The intersection of these two lines should fall on a line representing the geothermal gradient (gG = .25oC/100m). Following the geothermal gradient line upward to the depth

of the zone of interest and descending from that intersection to the X-axis yields a formation temperature (Tf) of 50oC at 2790m (wet zone).

Determine Equivalent NaCl Concentration

The equivalent NaCl concentration can lead to an estimated value of mud resistivity (Rm) at the zone of interest. To determine this concentration, chart GEN-4 must be

used.

Add the concentrations of the four ionic constituents to obtain a total ion concentration. Enter GEN-4 on the X-axis at a value equal to this total concentration. Project a vertical line upward to intersect with the lines corresponding to each of the particular constituents (Ca, Cl, Mg, Na). From the projected intersections, extend horizontal lines to intersect the Y-axis. The Y-axis values represent corrective multipliers for each constituent.

Determine Rm at Zone of Interest

With the estimated total solution of NaCl = 12,596ppm, use chart GEN-5 to obtain a mud resistivity (Rm = 0.29 Ω-m) at 2790m.

Determine Rm f

Using GEN-3, determine Rmf = 0.13 Ω-m at 2790m.

Plot Rmf and Determine SSP

Using SP-4, plot Rmf = 0.13 Ω-m on the X-axis and extend a vertical line upward to the

proper formation temperature line (Tf = 122oF). To convert between oF and oC, use the

top and bottom scales of GEN-5.

Project a horizontal line from this intersection to the Yaxis and obtain an SSP value of -98mV.

Determine SP Deflection

From the log, the SP deflection at 2790m is roughly -62mV from the baseline.

Plot ∆SP

Re-enter chart SP-4 on the Y-axis with a value of 36mV. Project a horizontal line to the interpolated 122oF line representing formation temperature (Tf).

Determine Rw

From the intersection established in the previous step, extend a vertical line downward to the X-axis. This plot should fall on a value of Rw = 0.035 Ω-m.

Determine Rw from the Inverse-Archie Method

Because the lithology of formations of interest is given to be sandstone and the porosity of the zone at 2790m is greater than 16%, the Humble values of tortuosity factor (a) and cementation exponent (m) may be assumed.

Comparison of Rw Results

The values of Rw calculated by different methods for the zone at 2790m differ by 0.091

Ω-m. This is a major difference, and will have detrimental effects on calculated values of water saturation (Sw). The decision as to which value to use should be based on

experience as well as information taken from the log. The SP method has yielded a more reasonable and optimistic value of formation water resistivity (Rw = 0.034 Ω-m),

and should be used in future calculations to obtain more optimistic values of water saturation (Sw).

"Quick-Look" Methods in Log Analysis

Before water saturation is calculated for any zone, it is necessary to scan a log and locate favorable zones that warrant further investigation. This is true not only for potential hydrocarbon-bearing zones, but water-bearing zones as well. This is often referred to as ”scanilizing" a log. There are certain responses that should be looked for, and these responses may indicate whether a zone is water-bearing or hydrocarbon-bearing.

"Quick-look" log analysis employs scanilizing to locate potential zones of interest, and also employs the basic concepts and procedures thus far considered in this text. The objective in performing a "quick-look" analysis is to quickly produce values of water saturation for zones that appear interesting on a log. It is important to remember that in "quick-look" analysis environmental corrections are not applied. Therefore, the water saturation values obtained during "quicklook" analysis may not be as accurate as those determined through in-depth and

detailed log analysis and interpretation.

When performing a "quick-look" analysis--which should be the first step of any detailed investigation--six questions must be asked when considering whether a zone is potentially productive.

What value will be used for Rw?

What are the lithologies of the zones of interest? Are the hydrocarbon-bearing zones "clean" (shale-free)?

Is there sufficient porosity in the zones? Is there satisfactory resistivity in the zones?

Are the zones permeable?

The particular methodology by which an individual approaches the "quick-look" analysis may vary, yet should address all of the questions posed above. There should be some order and consistency to the method. A suggested "quick-look" approach is outlined in the following paragraphs.

Identify Permeability Indicators

Scan the appropriate permeability indicators presented with the log. These may include the SP, Microlog, Caliper, and even resistivity invasion profiles. Mark on the log all zones that exhibit potential permeability, regardless of whether they appear water-bearing or hydrocarbon-water-bearing. This should always be the first step of a "quick-look" analysis, particularly with High Resolution Induction (HRI) logging suites.

Determine Formation Water Resistivity (R

)

If the customer provides this data, then the source is defined. If not, then it may be necessary to calculate Rw from the logs. Locate a relatively clean waterbearing zone of

more than one water-bearing zone is located, then Rw should be calculated for all

zones. Tabulate the results and select the lowest value of Rw for future calculations,

remembering that lower values of Rw (within reason) produce more optimistic values of

water saturation (Sw).

Determine Porosity and Resistivity of Zones

Once a permeable zone is located, porosity and resistivity curves should be checked to see if the relationship between them indicates the possible presence of hydrocarbons. These curves should be considered together, and not without respect to one another. Recall that it is entirely possible for a zone to exhibit an increase in resistivity because of a decrease in porosity. Therefore, without considering all the data, it is possible to misidentify a tight zone as being potentially productive.

Most porosity logs will present two porosity curves--density porosity (ΦD) and neutron

porosity (ΦN). Both of these curves reflect formation porosity, but the differences in their

values depend upon the different ways in which the respective measurements are made.

The Archie equation provides for only one value of porosity, therefore it is necessary to calculate cross-plot porosity before calculating water saturation. Cross-plot porosity is a weighted average of the two values, and is calculated by the equation below. Additional discussion of cross-plot porosity is included in later sections of this text.

A quick determination of cross-plot porosity may be made by estimating "two thirds" porosity. This is done by visually estimating two-thirds the distance between the minimum-porosity curve and the maximum-porosity curve. For "quick-look" purposes, the use of visually estimated "two-thirds" porosity is sufficient for making water saturation calculations.

Determine Formation Lithology

Lithology identification can be accomplished in several different ways, the most basic of which is to examine the responses of various curves. For "quick-look purposes, the curves most useful for lithology determination are gamma ray, Pe, resistivity, and a

combination of neutron porosity and density porosity. Once lithology of the zone is determined, the necessary parameters (a & m) may be selected for water saturation calculations.

Determine Formation "Cleanliness"

An additional concern is the "cleanliness" of the formation which refers to the amount of shale present. All types of formations--sandstone, limestone, and dolomite--may contain clay minerals ("shale"). The presence of these clay minerals effects the responses of certain tools--namely, resistivity and porosity tools--and may result in a productive formation being overlooked as waterbearing The degree of shaliness of a formation can be judged from the gamma ray response. In general, the lower the

gamma ray response of a porous zone, the lesser the amount of shale ("clean formation"). This judgement requires some amount of experience and knowledge in the area, and a later section of this text addresses more detailed methods of shaly sand analysis.

Calculate Water Saturation

Water saturation may now be calculated for those zones that appear to be hydrocarbon-bearing. Remember that this value is not a reflection of the ratio of water to hydrocarbons that will be produced from the reservoir. It is simply the relative proportion of water to hydrocarbons in the porosity of that formation. There are no safe guidelines for determining what constitutes "good" and "bad" values for water saturation. This judgement calls upon experience and local knowledge.

References

Archie, G. E., 1942, The electrical resistivity log as an aid in determining some reservoir characteristics: SPE-AIME Transactions, v. 146, p. 64-62.

Asquith, G. B., 1982, Basic well log analysis for geologists: American Association of Petroleum Geologists, Tulsa, OK, 216 p.

Bateman, R. M., 1985, Open-hole log analysis and formation evaluation: IHRDC Publishers, Boston MA, 647 p.

Dewan, J. T., 1983, Essentials of modern open-hole log interpretation: PennWell Publishing, Tulsa, OK, 361 p.

Section 2

Porosity and Mineralogy

Table of Contents

Introduction………. ₂₉

Objectives………... 29

Cross-Plot Porosity and Lithology (CP Plots)………... 30

Two-Thirds Porosity……….. ₃₀

Cross-Plot Porosity……… 30

Cross-Plot Porosity and Lithology from Chart……….. ₃₁

Limitations of Cross-Plot Porosity (CP) Charts………. 33

Cross-Plot Gas Effect………... 33

Cross-Plot Shale Effect……… ₃₃

Sonic Tool Cross-Plot Charts……….. 34

Complex Reservoir Mineralogy………... ₃₅

Clastic Sedimentary Rocks……….. 35

Carbonate Sedimentary Rocks………... ₃₆

Complex Lithologies……….. 36

Mineral Identification Plots (MIP Plots)……….. 36

Introduction

Determining accurate values of porosity (Φ) and describe lithology of a formation based on log responses is one of the vital step in any log analysis. Assumed values of tortuosity factor (a) and cementation exponent (m) necessary to calculate water saturation (Sw) are dependant on these determinations. This section presents an

overview of the different methods available for determining porosity and lithology as well as methods for determining complex lithology composition.

To effectively use this section, the participant should have a copy of the Halliburton Log Interpretation Charts manual. Examples illustrated in this section will make frequent references to this Log Interpretation Charts manual.

Objectives

After completing this section, the participant should be able to § visually estimate "two-thirds" porosity from neutron-density data. § calculate cross-plot porosity of a formation by equation.

§ determine cross-plot porosity of a formation by Cross-Plot (CP) chart using a combination of neutron, density, and/or sonic data.

§ determine two end-member lithology of a formation by Cross-Plot (CP) chart using a combination of neutron, density, and/or sonic data.

§ recognize the effects of gas and shale on Cross-Plot (CP) data plots.

§ apply the appropriate correction on a Cross-Plot (CP) chart to compensate for the effects of the presence of gas.

§ determine three end-member lithology of a formation by Mineral Identification Plot (MIP) using a combination of neutron, density, and/or sonic data.

Cross-Plot Porosity and Lithology (CP Plots)

Two of the most important uses of log data are to provide porosity and lithology Information to the geo-scientific community and use it for calculating water saturation (Sw). Porosity is a vital input to Archie equation. A knowledge of lithology is also helpful

because it empowers the analyst make a reasonable determination to choose appropriate value of tortuosity factor (a) and cementation exponent (m).

Porosity measurements taken from an individual logs are rarely adequate for use in calculating water saturation. This is because of Natures heterogeneity. Once density and neutron porosity values are corrected for environmental effects, the analyst has two values of porosity--neutron porosity and density porosity. Archie water saturation calculations require only one input value for porosity. Which one to be considered for rational saturation evaluation? This is a big dilemma and requires a step to move forward.

Two-Thirds Porosity

One method of visually estimating a value of porosity for use in the Archie equation is referred to as "two-thirds" porosity. This method simply involves estimating two-thirds the distance between the lowest porosity reading and the highest porosity reading, and taking that value as input into the Archie equation. This method may be used regardless of which matrix (e.g., limestone, sandstone, dolomite) was used to calculate porosity.

Regardless of matrix choice, two -thirds porosity may be assumed to reflect the approximate porosity of a formation of any lithology. The reason for taking twothirds the

distance between porosity readings rather than a simple average is to more closely approximate the value that would be calculated by the cross-plot porosity equation (discussed below). Some analysts prefer to take a simple average of the two measurements.

An important limitation in the estimation of two-thirds porosity is the presence of gas. Because gas affects neutron porosity more than it does density porosity, any averaging routine may contain error. Fortunately, in the presence of gas, density and neutron porosity partially compensate one another. This limitation should be kept in mind when applying the method. Furthermore, this approximation should be made with caution where anhydrite is present. Because of the high bulk density of anhydrite (ρb =

2.98g/cc), density porosity will often read too low (in some cases, negative). Averaging methods, therefore, will result in a value of formation porosity that is too low.

Cross-Plot Porosity

Another method of obtaining a single value for porosity from density porosity and neutron porosity data is through the use of the cross-plot porosity equation.

The value obtained from this equation likewise may be assumed to represent the actual formation porosity, regardless of which matrix value was used during logging. This weighted average results in values similar to those obtained by visually estimating the two-thirds porosity of a formation.

Again, an important limitation in the use of this method is the presence of gas and anhydrite. These circumstances will create a situation in which the value of crossplot porosity is not an accurate approximation of formation porosity. In cases where density porosity reads negative values (common in anhydritic dolomite reservoirs), some analysts prefer to use a simple average of density and neutron values as illustrated below.

Cross-Plot Porosity and Lithology from Chart

The cross-plot porosity equation is assumed to be correct for any particular matrix (e.g., limestone, sandstone, dolomite) that may have been used to calculate density and neutron porosity. However, this assumption is in error because the porosity values do, in fact, depend upon what matrix was used in calculating porosity. For instance, a formation consisting of 70% limestone and 30% dolomite might have two possible porosities; one if run on a limestone matrix, and another if run on a dolomite matrix. This condition may necessitate that crossplot porosity be determined from chart. An added benefit of this method is that a basic lithology of the formation in question is also obtained.

The proper Cross-Plot Porosity (CP) chart is determined first by tool type, and second by the density of the drilling fluid. The chartbook differentiates between five types of neutron tools: Dual Spaced Neutron (DSN); Compensated Neutron (CNT-K); Hostile Dual Spaced Neutron (HDSN); Dual Spaced Epithermal Neutron (DSEN); and, Sidewall Neutron (SNL).

Each of these chart sections contains Cross-Plot Porosity charts for oil-based muds (ρfl

= 0.85g/cc), freshwater-based muds (ρfl = 1.0g/cc), and saltwater-based muds (ρfl =

1.15g/cc). On these charts, neutron porosity is cross-plotted with bulk density (ρb).

Neutron porosity may also be cross-plotted with interval transit time (∆t), or bulk density and sonic measurements may be cross-plotted together without implementing a neutron measurement at all.

To illustrate the use of the neutron-density Cross-Plot Porosity (CP) chart, refer to the example worked in blue on the CPDSN-II-1a chart. This chart fits the conditions where a

Dual Spaced Neutron (DSN) tool was logged in an oil-based mud (ρfl = 0.85g/cc).

Example Data for Chart CPDSN-II-1a

ΦN = 17% on limestone matrix (environmentally corrected)

To correctly use this chart, it is important to ensure that environmental corrections have already been applied to the recorded porosity measurements. Furthermore, notice that

both density and neutron porosity values are in units of limestone porosity. If these

conditions are not met, then the use of the chart will not yield accurate results. Neutron porosity may be converted from one lithology to another through the use of chart POR-12.

Using the example data above, enter the chart with the environmentally corrected value of neutron limestone porosity (17%) on the X-axis. Extend a vertical line upward to intersect a horizontal line that represents either the bulk density (?b = 2.34g/cc) or

density limestone porosity (?D = 20%). The resulting plot falls between the sandstone

and limestone matrix division lines.

Assuming that the formation consists of a mixture of sandstone and limestone, to interpolate cross-plot porosity extend a straight line (solid blue line) between equal values of porosity on both the quartz and calcite matrix division lines (the black lines at the top of the red shaded regions). In this example, the point plots along a line representing a cross-plot porosity of 19% if that formation is, indeed, a mixture of sandstone and limestone.

Relative proportions of the two end-member lithologies (sandstone and limestone) may be estimated by normalizing a scale along the solid blue line between the two matrix division line with each division line representing 100% of that particular lithology. The point in question plots at approximately 65% calcite and 35% quartz (sandy limestone). However, this is not the only possible solution for the plotted data.

Notice that the plotted point also falls between the matrix division lines of sandstone and dolomite. Without previous knowledge of the reservoir, it is impossible to determine from the log which lithology mixture is correct. It is therefore necessary to obtain a second value for cross-plot porosity assuming that the formation consists of a mixture of sandstone and dolomite. This is accomplished in the same manner as above by extending a straight line (dashed blue line) between equal values of porosity on both the quartz and dolomite

matrix division lines. For the assumed sandstone-dolomite mixture, cross-plot porosity is 20%.

Again, relative proportions of the two end-members (sandstone and dolomite) may be estimated by normalizing a scale along the dashed blue line between the two matrix division lines. The plotted point represents a mixture of approximately 70% quartz and 30% dolomite (dolomitic sandstone).

In this particular example, cross-plot porosity differed only slightly between the two possible lithology combinations. In other instances, the difference may be more significant. Cross-plot porosity is relatively insensitive to the mineralogy mixture provided that the lithology is composed of two of the three common minerals: quartz, calcite, and dolomite. The presence of other minerals, however, will require a different approach.

When different porosity values and different lithologies are obtained from Cross-Plot charts, it is advisable to calculate formation water resistivity (Rw) and water saturation (Sw) for both situations, and present the results of each.

Limitations of Cross-Plot Porosity (CP) Charts

The choice of basic lithology is obviously quite important. Apart from the difference in resulting cross-plot porosities, the values for tortuosity factor (a), cementation exponent (m) and even saturation exponent (n) may need to be altered. In the previous example, the cross-plot lithology determination was based upon only two measurements (neutron porosity and bulk density). At best, the Cross-Plot method can differentiate between

only two minerals. The previous example data presented two possible solutions: sandy

limestone or dolomitic sandstone. There are, however, certain effects that tend to mask the apparent lithology of a formation, thereby making their evaluation more difficult.

Cross-Plot Gas Effect

The presence of gas in a formation has a profound effect on the neutron porosity measurement. Because the tool measures hydrogen index, the low hydrogen density of gas (compared to hydrogen density of liquids) causes the neutron tool to underestimate porosity. Gas also affects the density measurement, causing density porosity to be overestimated.

If gas is present, then the base lithology of the formation of interest must fall somewhere to the lower right of its plotted point. Although not a precise method by any means, the presence of gas may be corrected for by drafting a line parallel to and in the same direction as the "Approximate Gas Correct" arrow. This line should extend from the plotted point of interest to the nearest lower-right matrix division line. The base lithology, of course, should be logically determined from cuttings, core samples, tool response in non-gassy zones, etc..

The presence of gas may cause tremendous problems in resolving lithology from a Cross-Plot chart. Because gas tends to pull points up and to the left, it is entirely possible for a 100% dolomite gassy formation to plot along the matrix division line representing 100% sandstone. For that matter, the point may also fall somewhere between the quartz and calcite matrix division lines, giving the impression that dolomite is not present at all.

Cross-Plot Shale Effect

The presence of shale will also adversely influence the interpretation of the plotted point. In reality, the properties of shale (to be discussed in more detail later) affect all logging responses to some degree. The primary concern on a neutron-density Cross-Plot chart is the characteristic high porosity reading of the neutron tool.

The high porosity response of the neutron tool together with the relatively high bulk densities typical of shales will push the plotted point of a shaly formation to the bottom right of where it would fall if it were clean. For example, a shaly sandstone could

Do not base an interpretation on a single chart or a single method. An error-free evaluation can seldom be made from one curve, or from a single chart or

feasibly have a point which plots along the matrix division line representing 100% dolomite.

A 100% pure shale will typically plot within an area defined by the following limits: 30% < ΦN < 40%

2.35g/cc < ρb < 2.50g/cc

Because the presence of shale tends to pull plotted points down and to the right, correction for shale would therefore be up and to the left. How far to the left and at what angle the correction is to be taken would be determined by the characteristics of that particular shale. For now, it is sufficient to realize that the presence of shale can cause dramatic misinterpretations about the lithology of a formation when using Cross-Plot porosity charts.

Sonic Tool Cross-Plot Charts

The "Sonic versus Bulk Density" and "Sonic versus Neutron Porosity" charts may be interpolated or extrapolated in the same manner as the "Bulk Density versus Neutron Porosity" charts previously discussed. These charts may be used as an alternative to the neutron-density cross-plots, or as an additional method for providing solutions to the constraints that exist on lithology front. The use of "Sonic versus Neutron Porosity" Cross-Plot charts can help refine the estimate of lithology obtained from the neutron-density Cross-Plot charts. When two different methods converge to a particular solution it gives adequate weight to derived conclusions.

The "Time Average" lines represent the response of the Wyllie-Time Average sonic porosity equation. This response is based on the premise that the travel time through a porous formation will remain unchanged irrespective of pressure variations, this happens when the formations have reached the terminal velocity. Porosity is commonly calculated with the Wyllie-Time Average equation illustrated below.

The "empirical," or curved, lines represent the response from a combination of data gathered by Raymer-Hunt and Halliburton. This is a purely emperical calculation based upon comparisons of transit times with core porosities and porosity as derived from other types of logs. The Raymer-Hunt equation for sonic porosity is illustrated below.

The choice of equation for computing sonic porosity should be left to the customer. Because the customer is aware of other wells in the same region and reservoir, and how sonic porosities were calculated from those logs.

Complex Reservoir Mineralogy

Most oil- and gas-bearing formations are composed of sedimentary rock, as opposed to igneous and metamorphic rock. Sedimentary rock, as its name implies, is composed of different types of sediments that have been deposited at some type of accumulation point, possibly an ancient ocean basin or river channel. After some period of geologic time, many such layers of sediment may accumulate. The tectonic forces imposed upon these layers results in compaction and cementation of the loosely consolidated sediments into a sedimentary rock.

By volume, sedimentary rocks are estimated to constitute only 5% of the known lithosphere (the 10 mile-thick outer shell of the earth), whereas igneous and metamorphic rocks account for 95%. However, sedimentary rocks cover 75% of the total land area on continents, with igneous and metamorphic rocks covering the remainder. It is evident, therefore, that sedimentary rocks must form only a thin, superficial veneer on the surface of the earth.

For the purposes of this discussion, sedimentary rocks can be subdivided into two primary categories: clastic and carbonate. These categories comprise the three most common producing reservoir rock types: sandstones, limestones, and dolomites. The composition, place of origin, and granular size of the individual sediments of a rock are among the factors that determine the rock's identity.

Clastic Sedimentary Rocks

Clastic sediments are those produced by the weathering and breakdown of preexisting rocks. These particles, having been derived somewhere other than the accumulation point, are transported, sorted, and modified by moving fluid such as water or air. Their deposition is normally in successive horizontal layers. Clastic sedimentary formations are typically sandstones and shales. Apart from differing in composition, these two rock types also differ dramatically in constituent grain size. This combination of similarities (origin) and differences (grain size) produces formations containing combinations of both sandstone and shale. Because shaliness affects both formation characteristics and log responses, it will be discussed in detail later in the text.

Sandstone is composed primarily of quartz, feldspar, and mica. In many forms of sandstone, quartz constitutes over 90% of the detrital fraction of the rock. For this reason, many charts refer to sandstone formations simply as "quartz."

Carbonate Sedimentary Rocks

Carbonate formations are usually marine in origin and composed primarily of skeletal grains and/or seawater precipitates. These constituents are produced within the region of accumulation, and are not derived form weathering or breakdown of pre-existing rocks. Productive carbonate formations typically include limestones and dolomites. The primary difference between these two types of rocks is the chemical composition. The term "limestone" is used for rocks containing predominantly calcite: CaCO3. The term

"dolomite" implies substitution of Ca with Mg. Dolomite composition is:(CaMg(CO3)2).

Complex Lithologies

Subsurface formations may be heterogeneous e.g. a clastic may have lime marter making it calcarious sandstone and similarly carbonate rocks.may contain high percentage of marl commonly termed as shaly limestone. In addition, the presence of accessory minerals may cause further confusion when determining lithology from a Cross-Plot chart. At best, the Cross-Plot methods discussed previously can identify only

two end minerals. The methods are fairly accurate provided that the rock matrix is

composed of two of the three common minerals: quartz, calcite, and dolomite. To address the problem of the possible presence of other minerals (e.g., clays, coals, anhydrite, halite etc) a more rigorous method of mineralogy identification (Mineral Identification Plots) may be used.

Mineral Identification Plots (MIP Plots)

When complex lithologies are suspected and accuracy is of the utmost importance inverse technique (ULTRA) is the only solution. However, there are techniques through which mineral identification can be tried. In the previous examples of Cross-Plot chart data from two logging measurements (e.g., ρb and ΦN, ρb and ∆t, or ΦN and ∆t) may be

used to identify lithologies limited to only two end-members. By using a chart that handles a third measurement (e.g., Pe), a more accurate evaluation can be ascertained.

In this discussion, two techniques of "trimineral plots will be considered: Umaa versus

ρmaa, and ρmaa versus ∆tmaa.

Accurate lithology determination may be necessary for a variety of reasons:

§ Porosities may be near cut-off values (~5%); therefore, the most accurate values obtainable from logs are desired. Dolomite and shale, for example, cause similar separation between limestone-based neutron and density porosity curves, but effective porosity is computed differently for each case.

§ Tight (low porosity) formations often require acidizing or acid fracturing to stimulate production. Optimization of this operation requires knowledge of the formation lithology.

§ Lithology distribution across a field may reveal preferential directions for the locations of future offset wells. For example, dolomitization is often accompanied by increased permeability, therefore the direction of increasing dolomite content may be a favorable direction for further exploration.

Spectral logging tools (Spectral Density and Spectral Gamma Ray) can be used individually to determine simple lithologies in "pure" formations. Combinations of two more basic tools (e.g., DSN versus CDL, CDL versus BCS) can also be utilized for determining simple lithologies. However, when used in complex lithology situations, such "two tool cross-plots" can be very misleading. For example, a point plotting directly on the limestone matrix division line of a neutron-density Cross-Plot chart could possibly be the response of a dolomitic sandstone.

The use of three different types of log responses is the next logical step in the goal of increasing accuracy and reliability of lithology identification. Because the manipulation of a three-dimensional chart (X-axis, Y-axis, and Z-axis) would be rather cumbersome within the confines of a two-dimensional chartbook, the three tool responses must first be incorporated into simple X-Y coordinates. These calculated X and Y coordinates then are introduced into the respective Mineral Identification Plot (MIP), and the complex mineralogy resolved.

Umaa Versus

ρmaa MIP Method

The Umaa versus ρmaa MIP method of lithology determination requires a Spectral Density

(SDL, with Pe curve) and neutron for implementation. The Mineral Identification Plot

charts are labeled MIPXXX-8, according to the particular type of neutron tool being used.

Notice that the X-axis and Y-axis coordinates of these charts are not values that can be taken directly from logs. The "Apparent Matrix Density (ρmaa)" and "Apparent Volumetric

Photoelectric Factor (Umaa)" must first be determined using separate charts (MIPXXX-4

and MIPXXX-6, respectively).

Utilization of this method requires three steps: 1. ρmaa determination (chart MIPXXX-4)

2. Umaa determination (chart MIPXXX-6)

3. ρmaa versus Umaa MIP plot (chart MIPXXX-8)

?maa Determination

Without having actual core samples of the formation of interest, it is impossible to know an exact value of matrix density (ρma). However, by being able to determine Cross-Plot

lithology of a formation from charts using neutron and density data, it possible to estimate the apparent matrix density (ρmaa) from these data (Step 1).

For the purposes of illustration, the chart MIPDSN-II-4 will be referenced here. Notice that

this chart is developed for a fluid density (ρfl) of 1.0g/cc (freshwaterbased drilling fluid).

There are no charts available for use in those conditions where ρfl _ 1.0g/cc, therefore

this same chart will also apply for oil-based mud and saltwater-based mud conditions.

Furthermore, notice that neutron porosity must be in limestone porosity units. Again, the conversion of another neutron lithology to limestone, if necessary, may be made using chart POR-12.

Mineral Identification Plots (MIPs) have an advantage over Cross-Plot (CP) charts in that they resolve three end-member lithologies.