Petrophysical Reference 

Manual 

(Last Updated 16 December 2015)

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1. Introduction & Mudlogging

Summary

In part A of this chapter the objectives of the course and the course schedule are outlined. Also a description is given of the tasks of a petrophysicist. In part B of this chapter a review of mudlogging is given.

References

General petrophysics text books: - Schlumberger, Log Interpretation Principles/Applications, 1989 (see also:

Schlumberger, Log Interpretation Charts, 1991, and Schlumberger, Wireline Services Catalog, 1991)

- Western Atlas, Introduction to Wireline Log Analysis, 1995 (see also: Western Atlas, Log Interpretation Charts, 1995, and Western Atlas Services Catalog, 1994)

- Richard M. Bateman, Open-hole log analysis and formation evaluation, D. Reidel, 1985 (this book by Bateman has the most complete coverage of all text books currently available)

- John T. Dewan, Essentials of modern open-hole log interpretation, PennWell Books, 1983 (a bit less coverage than Bateman and Desbrandes, but very clear and excellent lay-out)

- R. Desbrandes, Encyclopedia of well logging, Editions Technip, 1985 (excellent coverage, but the lay-out is a bit confusing)

- Darwin V. Ellis, Well logging for earth scientists, Elsevier, 1987 (especially good on the physics behind the tools) - M. Rider, The geological interpretation of well logs, Whittles Publishing, 1996

(2nd ed.) (aimed at geologists, nevertheless very useful to petrophysicists as well; very good lay-out)

- Zaki Bassiouni, Theory, measurement and interpretation of well logs, SPE, 1994 (good on logging and interpretation, but relatively limited overall coverage)

- Donald P. Helander, Fundamentals of formation evaluation, OGCI publications, 1983 (a bit weak on interpretation)

- O. Serra, Fundamentals of well-log interpretation: 1. the acquisition of logging data, Elsevier, 1984 (good coverage of (older) tools, a bit limited on interpretation)

- R.C. Ransom, Practical formation evaluation, John Wiley, 1995 (OK with respect to interpretation; coverage of some new tools; a bit ideosyncratic)

- Y.I. Gorbachev, Well logging - Fundamentals of methods, John Wiley, 1995 (very theoretical coverage of tool physics; virtually nothing on interpretation / application)

Mudlogging

- J.G. Bond, Mud logging, Manual GL304 of the IHRDC video library for E & P specialists, 1986

A) Introduction

Course objectives

The objectives of the course “ Petrophysics for other disciplines” or “Foundations of Petrophysics”, are to enable the course participants to:

• use petrophysical tools and techniques for the characterisation of hydrocarbon bearing reservoirs

• confidently make a quicklook evaluation of openhole logs to assess porosity, lithology, fluid type and fluid saturation (input to STOIIP equation)

• learn how/why other data sources (mudlogs, core analysis, capillary pressure curves, borehole seismic, wireline formation tests) are used

• be aware of the use of cased hole logs for cement evaluation, reservoir monitoring and production logging

• obtain a feel for the uncertainties related to petrophysical interpretations

• learn how more advanced petrophysical techniques can be applied, e.g. for laminated shaly sand reservoirs

Course sessions and contents Most of the headings given below refer to the half-day sessions in the phase 2 petrophysics courses. The indicated sequence for the openhole sessions reflects more or less the sequence of the acquisition/evaluation stages. The sequence of these sessions may be different for different courses though and is therefore also a bit different from the sequence in the current manual.

OPEN HOLE

Petrophysical objective�

Course session� Key learning points�

Introduction Familiarisation; tasks of PE disciplines

What is petrophysics?

STOIIP equation; tasks of petrophysicist

First indications from mudlog

Mudlogging / Cuttings

Lithology & HC indications from mudlog

Acquire wireline log data�

Data acquisition� Information on Log header; calibration; depth of investigation vs. resolution

Acquire data while drilling�

MWD / FEWD� Formation Evaluation While Drilling: - data acquisition & quality - uses: horizontal holes, data protection, less invasion effect, geosteering

Quality control Calibration / QC Logging tool calibration & quality control

Input parameters for log evaluations�

Coring / Core analysis�

Main coring methods Importance of Core Analysis planningLaboratory Special Core Analysis methods for measuring φ, k, m, n, Qv

Overview of evaluation scheme�

Quicklook� Basic openhole evaluation method: - sand/shale from gamma-ray - porosity/lithology from density/neutron - hydrocarbon saturation from resistivity - gas/oil differentiation from density/neut.

Discriminate reservoir from GR�Assess porosity / lithology

Porosity & Lithology�

- Use of gamma-ray, spontaneous potential, density/neutron and sonic- Main porosity tool: density

Assess reservoir productivity�

NMR� Main uses of NMR logging: Free, Movable and Bound fluid; permeability; pseudo capillary pressure info

"� Full waveform sonic�

Main uses of shear and Stonely wave data: permeability, rock strength

Find hydrocarbons (also in thin beds)�

Resistivity modelling

- Use of Laterolog in saline mud, Induction in non-saline mud / OBM - Modelling & inversion software to be used in thin beds (< 10 - 20 ft)

Find hydrocarbons (also in thin beds)

Wireline Formation Testing

Use of pressure/depth graph for locating fluid contacts

Discriminate gas / oil� Gas/oil differentiation�

- Standard: Use of density/neutron & sonic - Other overlays sometimes help as well

Assess hydrocarbon saturation�

Saturation modelling�

Use of Waxman-Smits model for shaly sands, including how to get the parameters from cores or logs.

"� Capillarity/Wettability�

Saturation/height curves from laboratory measured capillary pressure curves

Assess uncertainties Uncertainty Becoming aware of impact of uncertainties in reservoir area, thickness, net/gross, porosity, saturation

� � �

CASED HOLE� � �

Petrophysical objective�

Course session� Session objectives�

Inspect flow inside tubing / casing

Production logging Familiarisation with main production logging tools; Single vs. multi-phase flow

Assess casing to formation bond�

Cement evaluation� Various tools to inspect zonal isolation: Cement Bond Log, Video Display Log�

Formation evaluation in cased hole

Reservoir monitoring - Pulsed neutron tools

- Absolute, time-lapse and log-inject-log measurements - Inaccuracies due to measurement statistics, tool physics, environment

VOI Operations Costs vs.Value

WELLBORE SEISMIC�

�

Petrophysical objective�

Course session� Session objectives�

Interface petrophysics / seismic�

Wellbore seismic� - Use of checkshots - Making synthetics - Gassmann fluid replacement

Objectives of the petrophysicist The mission of the petrophysicist is to identify and quantify hydrocarbon resources in the subsurface and to provide an evaluation of the nature of formation fluids and rock properties. This is achieved by application and interpretation of downhole "logging" measurements of the physical properties of the subsurface, in most cases in combination with measurements on core samples. The principle deliverable is a static and dynamic reservoir description and subsurface fluid distribution at and away from the wellbore. Through active management of wireline and mudlogging contractors, the Petrophysicist is accountable for the safe, timely and cost-effective acquisition and interpretation of the optimum data set which leads to the quantification of the development potential of petroleum resources. The Petrophysicist continues to update reservoir characteristics and to identify and monitor changing fluid distributions during the development and exploitation of petroleum resources.

The petrophysicist wants to measure physical properties of rocks and fluids downhole. Unfortunately, there are no direct methods with which such quantities can be measured. A direct measurement is a measurement in which a direct comparison is made, like measuring length with a ruler, or weight with weighing scales. Most physical measurements, however, are indirect, i.e. the size of a phenomenon is measured via its impact on something else. For instance, temperature can be measured via the effect of heat on the thermal expansion of mercury. All petrophysical measurements are indirect in that sense. Almost the complete range of physics is used in trying to achieve the goal of quantifying rock and fluid properties downhole. This often makes it difficult for the non-physicist to understand the tools and methods of petrophysics in detail. Fortunately, the actual applications and limitations can also be understood by the non-physicist petroleum engineer. It is the objective of this course to give any petroleum engineer sufficient knowledge of petrophysics in order to do his/her business. More physical/technological detail can be found in the references. The main sources of information for the petrophysicist are (see also Fig. 1): - Mudlog data and cuttings: see section B, below. - Cores and sidewall samples - Logs, acquired via Wireline tools or using tools inserted in the drillstring:

FEWDPressures and fluid gradients, from the Wireline Formation Tester - Borehole seismic measurements From these data the petrophysicist will obtain fluid contacts, fluid saturations, porosity, absolute permeability and lithology information. The petrophysicist has different tasks in the different stages of the reservoir life cycle. In the exploration and appraisal stage the main objective is to quantify the

volume of hydrocarbon in place (HCIP), in conjunction with geophysicists and geologists (see chapter 2). The petrophysicist also works together with geologists and geophysicists to enable extrapolation of the data away from the wellbore, and to help assessing lithology and formation structure (thicknesses, dip). In later stages (development) the petrophysicist works together with reservoir engineers and production engineers to assess/monitor reservoir performance.

Relations between Petrophysics and other Petroleum Engineering disciplines The following specific relations exist between petrophysics and various other disciplines:

• Geology: * 3-D model: deep-reading tools * Microstructure: SEM, FMI, .. * Lithology: Neural networks, source rock

• Reservoir engineering: * Reservoir monitoring: PNC, Production Logging * SCAL: relative permeability (not discussed in this course), cap. curve * Pressure testing: WLFT * Compaction / compressibility

• Well technology: * Production logging: PLT, etc. * Cement evaluation: CBL, etc. * Casing evaluation (not discussed in this course) * Sand failure prediction / rock strength (not discussed in this course)

• Drilling: * Influence hole conditions on response * MWD / FEWD & geosteering * Mudlogging, cutting analysis * Pore pressure prediction (section B, below) * Influence of new mud on tool responses

B) Mudlogging

While drilling a well, the following information about the drilled formations is recorded as a function of depth. This is called a mudlog (Fig. 2).

Information obtained - The drilling rate or rate of penetration (ROP). - All important parameters which influence the drilling speed, e.g. type of bit,

rounds per minute (RPM), weight on bit (WOB), pump speed (SPM), pump pressure (SPP), etc.

- The lithology and texture of the cuttings, which are sampled at regular intervals (+/- 5 meter).

- The total combustible gas content in the air above the returning mud from the well bore. The relatively simple gas detector can be supplemented with a gas chromatograph to analyse the composition of the gas (Fig. 3).

- Hydrocarbon staining on the cuttings.

Applications - Monitoring of the bit performance. - Early indication of the well's position within the predicted stratigraphy. This is of

particular importance as a basis for operational decisions, e.g. at what depth to set casing, or where to core a well.

- Determination of lithology. - Indication of fluid type. - Indication of pressure conditions.

Detection of overpressures, e.g. using the d-exponent Overpressures can often be detected during drilling because drilling parameters change. An important way to do this is to use the so called d-exponent “d”, which can be calculated from the rate of penetration (ROP), the revolutions per minute (RPM), the weight on bit (WOB) and the bit diameter D, using the following equation:

ROP = RPM (WOB/D)d

Herefrom a parameter dc can be derived which is the d-exponent corrected for differential pressure. The d-exponent often shows a certain trend with depth. If suddenly this trend reverses, one may be entering an overpressured zone.

Wellsite hydrocarbon analysis - Staining, bleeding, odour, gas, iridescence (colour) (Pos., Neg., Quest.) - Natural fluorescence (UV): distribution, intensity, colour (5 = strong .....0 = nil) - Solvent cut test (Chlorothene): Minerals will not produce cut fluorescence - Acetone test (light oil): Hydrocarbons cause milky white solution - Acid test: bouncing motion if HC present - Pyrolysis test (“burn it”) - Hot water test: oil film at surface

Accuracy

- The information related to the formation and its fluid content is available on the moment that the mud with the cuttings come to surface. The lag time between the moments of drilling and sampling (varying from 0 - 2 hours), depends on the volume of the annulus and the circulation rate The depth of drilling is for this reason corrected, using a lag-time estimate and an average ROP. As a result, the depth accuracy is only +/- 5 meter.

- Variations in density and shape of the cuttings from various lithologies, causes differences in slippage. As a result a sample taken from the flowline may originate from a range of depths and will consist of a mix of the lithologies present.

- In some cases formations (often shales) higher up in the well bore are not stable. Cavings (flakes) of this particular formation can "contaminate" the cutting samples of lower intervals.

Evaluation Technique - Every formation has a signature on the ROP log. The depth of formations can

be determined, by correlating this log with the mudlog from a nearby well. - The lithology of the cuttings are given as a percentages of the total sample. An

accurate interpretation can be made in combination with the wireline logs, which have a far better vertical resolution

- The oil staining on the cuttings is analysed using several small chemical and fluorescence tests, which can differentiate the light and heavy hydrocarbons

- In water bearing formation no HC staining is expected. - The presence of only light HC's indicates gas. - In the case of an oil bearing formation more heavy HC's will be present. Amongst the staining tests is the solvent -cut (often chlorothene) , which is plotted in the example log (Fig. 2). This test indicates the presence of heavy HC components.

Figure 1 - Petrophysical Data Sources and Its Applications

Figure 2 - Example of a mudlog

Static model Dynamic model

Mudlogdata

Coredata

Open holelogs:- Resistivity- Nuclear- Acoustic- Other

Cased holelogs:- Nuclear- Production logs- Other

Fieldstudies

Interpretation modelsincl. QC & Uncertainty

Corrections:- invasion- layering- deviation

FEWD WL: vert., hor., HPHT, ..

Reservoirmonitoring

Hot wire Analyser

Gas Chromatograph

Figure 3 - Mudlog Equipment

Fixed resistance

Fixed resistance

Recorder

Referencecell

Detectorcell

Sample in

Sample out

C1

(.22) C2

(.39)

C3

(.79)

C4

ISO

(1.5

6)C

4 N

RM

(1.7

9)

C5

NEO

(2.8

9)

C5

ISO

(3.7

1)

C5

NR

M (4

.22)

Star

t

Stop

2

1

3 47

8

6

5

Two-stageregulator

Flowcontrolvalve

Gascylinder

Flowcontrolvalve

Injectionport

Column

Oven

RecorderDetector

Carriergas

2. Data acquisition & Quicklook log evaluation

Summary

Part A of this chapter deals with Data Acquisition methods. Part B of this chapter gives a review of Quicklook log evaluation.

References

Data acquisition - Books by Bateman, Desbrandes and Serra (mentioned in chapter 1)

- Ph. Theys, Log data acquisition and quality control, Editions Technip, 1991

Quicklook evaluation - Books by Bassiouni, Bateman, Desbrandes, Dewan, Ellis and Ransom Serra

(mentioned in chapter 1)

Log data acquisition and quality control

Tools and methods After a section of a well has been drilled, measuring sondes are lowered into the open hole at the end of an electrical cable. Whilst pulling the tools out of the well, various properties of the formations are measured continuously as a function of depth (Fig. 1). The thus recorded curves are called (wireline) logs. The measured physical properties can be interpreted in terms of lithology, porosity, hydrocarbon saturation, etc. This process is called “log evaluation / interpretation”. The downhole measurements mentioned above are performed with logging tools. These are physical measuring devices (sondes), working using various physical principles (nuclear, electrical, acoustical), lowered in the borehole via wireline (wireline logging) or as part of the drill string (measuring while drilling: MWD, logging while drilling: LWD, or formation evaluation while drilling: FEWD, see chapter 6). Hence, wireline logging tools are measuring sondes which record formation rock and fluid properties as a function of depth as the tools are pulled up in the borehole. The records are called wireline logs. In some cases when wireline

logging is difficult, e.g. in strongly deviated holes, the tools can be lowered (after drilling) while connected to drill pipe or coiled tubing. This is sometimes called Tough Logging Conditions (TLC) or Pipe Conveyed Logging (PCL). Logs, which are used to quantify the hydrocarbon in place, can be classified into three families: I Reservoir Thickness (Gamma Ray, Spontaneous Potential ) These logs discriminate reservoir from non-reservoir. II Porosity (Density, Neutron, Sonic.) These logs are used to calculate porosity, identify lithologies, and differentiate oil from gas. III Resistivity (Laterolog, Induction, Microresistivity.) These logs, together with porosity logs, are used to calculate hydrocarbon saturations. Other types of wireline tools are: - Side wall sampler (Takes small rock samples, which are used for lithology and fluid type confirmation.) - Formation tester (Measures formation pressures and can retrieve fluid samples.) - Dipmeter & FMS (Measure dip and azimuth of the layers) - Well shoot & VSP (Used to calibrate seismic.) All logging is carried out by contractors. The main logging contractors are Schlumberger, Bakker Atlas and Halliburton. Important LWD contractors are Anadrill (a Schlumberger company), Sperry Sun (a Halliburton company) and INTEQ (a Baker Atlas company). Many evaluations are carried out in-house, using proprietary software. The actual tool measurement has to be calibrated by the service company, to ensure that the measured quantity is correct, i.e. not disturbed by temperature fluctuations, tool malfunctioning, etc.: see chapter 13. None of the measurements is direct. Hence, the desired results (porosity, hydrocarbon content) have to be evaluated using petrophysical models. In such evaluations account must be taken of the disturbances exerted by the presence of the borehole, mud, mud filtrate invasion, shoulder beds (layers above and below the formation), dip, borehole deviation, pressure, temperature, etc. Therefore, log responses may first have to be environmentally corrected for such effects. Moreover different tools have different vertical resolutions (spatial averaging) and different depths of investigation (into the formation, away from the borehole), depending mainly on the spacings between source (transmitter) and detector (receiver): see section on depth of investigation, further below.

As petrophysical measurements are indirect, interpretation is required. The tool may for instance measure the electrical resistivity of the formation. However, the quantity we want to have is water saturation. Hence, the measured resistivity must somehow be related to the amount of hydrocarbon in the rock. This is achieved by carrying out calibration experiments on core samples in the laboratory

Depth Measurement The depth is measured along hole (AHD) in meters below derrick floor (mbdf). When the bottom of the tool string touches the drill floor the depth measurement is set at zero (Fig. 2). The distance between the various tool detectors and the bottom of the toolstring is automatically compensated by the computer in the surface logging unit. The length of cable in the hole is measured with an accuracy of around 0.1%. In vertical wells the AHD is equal to the true vertical depth (TVD). In deviated wells, a deviation survey is needed to calculate the TVD from the AHD. The TVD is often expressed in meters below a local datum, e.g. meters subsea (mss). The height of the derrick floor above the common sea level dataum is called the Derrick Floor Elevation (DFE). It is important to know accurately at which depth the logging measurements were recorded, hence depth control is essential. For the first logging survey in the well normally a Gamma-Ray / Resistivity combination is used. The depth calibration of this survey is done using magnetic marks (see Fig. 2). Subsequent logging surveys (with other tools) over the same depth intervals have to be depth correlated to the first survey. Errors might be expected if the tool weights are different, or if the travelling block has moved. In subsequent surveys in other (new) intervals, the first log should include a Gamma-Ray. Calibration is again done using magnetic marks. The new run should have an overlap of at least 50 metres with the previous Gamma-ray log (Fig. 3). The logs can be confidently correlated if the depth error is less than 0.5 metre. Stretch corrections are applied automatically by the contractor for depths less than 3000 metres. Only for depths greater than 3000 metres additional stretch corrections have to be applied.

Log Header A log consists of a number of different parts (Fig. 4). Data, crucial for the evaluation, can be found in the log header (Fig. 5): - Well name & -location, date, drill floor elevation (DFE), ground elevation (GE),

bit size, mud -type and –properties, Resistivities of the mud (Rm), mud filtrate (Rmf: Fig. 6 can be used to translate this to NaCl concentration) & mud cake (Rmc)

- Total depth (TD), bottom hole temperature (BHT), Weight-, size-, & depth- of previous casings, Time of last mud circulation

- List of all tools run in this hole section, serial number of tools and logging unit used, name of logging engineer and company representative.

Tool combinations Logging tools can be combined into one string, such that a basic Gamma-Ray, Density / Neutron, Resistivity combination can be logged in one logging run (Super-Combo). A disadvantage of the longer toolstring is that additional hole has to be drilled to ensure coverage of the Objective by all sensors. A development by Schlumberger is the Platform-Express (“PEX”), which is a Super-Combo but reduced in size and with higher accuracy sensors, thus allowing less “rat-hole” and to log faster and thus save rig time.

Depth of investigation versus resolution of logging tools The nuclear tools (gamma-ray, neutron, density) used for porosity and lithology determination have a rather shallow depth of investigation (typically 1 - 2 ft) because nuclear particles are quickly absorbed (Fig. 7). Because of this these tools mainly read the mud filtrate invaded zone (Fig. 8). Therefore, for instance, the apparent fluid density to be taken in the calculation of porosity from density is a combination of mud filtrate and gas densities (see Quicklook evaluation, below). The fact that the nuclear tools read the invaded zone rather than the virgin zone is not a big problem, as the porosity determination is rather insensitive to the invasion process. Most petrophysical tools consist of a shallow and a deep measurement (Fig. 7), where the shallow one is used to correct the deep one for mudcake and invasion effects. However, the main tools for determination of hydrocarbon saturation in open hole are resistivity tools. Of course, the desired saturation is that of the virgin (not invaded) zone (Figs. 8 & 9). Therefore, the resistivity tools have been designed such that they can read deep into the formation (deep laterolog / induction), such that they will (hopefully) be influenced mainly by the virgin formation (Fig. 10). In all tools a compromise is made between depth of investigation and resolution, i.e. the deeper a tool "sees" into the formation, the more its response will also be influenced by neighbouring beds above and below its actual position (if a tools sees deep horizontally, it will also read far vertically). Hence, resistivity tools can have a far larger depth of investigation than nuclear tools, but their vertical resolution is correspondingly less (worse).

Hence, the depth of investigation of a logging tool (in a vertical well) is the horizontal distance away from the borehole that a logging tool can still "see" into the formation (the word "depth" is misleading here: the concept refers more to a horizontal investigation distance). E.g. a density tool only reads about 1 foot into the formation, whereas a deep induction log sees about 2 metres away from the borehole (Fig. 10), so that in many cases it reads beyond the invaded zone, whereas a density tool does not. The "depth of investigation" is in general related to the spacing between source and detectors in the logging tool: the farther the source is away from the detectors the larger in general is the depth of investigation

(Fig. 7). However, this spacing is limited by the tool physics, e.g. some nuclear particles are absorbed rapidly by the formation, such that the spacing can not be made too large because in that case no particles would be left to measure. Hence, many nuclear tools do not read beyond the mudfiltrate invaded zone, whereas deep resistivity tools often do.

The resolution of a logging tool refers to its capability to distinguish and properly measure thin beds. A tool with a good vertical resolution, like the formation image log (chapter 12), is capable of properly measuring rather thin beds, say of a few millimeters thickness. A tool with a bad vertical resolution, like the induction log deep is only capable of properly resolving rather thick beds, say of more than 1 metre thickness. Obviously, the resolution of a logging tool is again related to the source / detector spacing: the larger the spacing, the worse the resolution (everything between source and detctors is seen as one average value by the tool): Fig. 7. Hence, the vertical resolution is also related to the depth of investigation: a tool with a bad vertical resolution generally has a large depth of investigation and vice versa. Many tools have several detectors, e.g. a short spacing and a long spacing detector (Fig. 7). The short spacing detector reads closer to the borehole than the long spacing detector. The short spacing detector reading is then used to correct the log spacing detector reading for borehole and mudcake effects. For instance, large and irregular boreholes can adversely affect the accuracy of the measurements. The log correction needed in these cases can often be quantified using contractor provided environmental correction charts (e.g. Schlumberger’s or Baker-Atlas’ chart books). In some difficult cases, however, such charts are not sufficiently accurate, and tool response modelling & inversion have to be used instead (see chapter 6). Modern tools often have many detectors on a so called "array", such that a profile of the invaded zone can be made (e.g. Schlumberger's "array imaging (induction tool", the AIT). This requires tool response modelling & inversion in any case.

Quicklook method (see also list of symbols at the end of this chapter)

Reading log responses All tools have a limited vertical resolution. Close to lithology boundaries the measurements will be affected by the adjacent beds. In very thin beds this could lead to tool responses which deviate from the true formation profile. In a quicklook evaluation "constant" log values are assigned to each formation bed. These values are then used to calculate the petrophysical parameters of each bed. In a quick look evaluation one can limit the amount of blocks by taking average readings over intervals with a more or less constant log responses. The block boundaries must be at the same depth on all involved logs.

The Hydrocarbon volume in place The Hydrocarbon volume in place is given by the following equation (Figs. 11 & 12):

HCIP = A * h * (N/G) * φ* (1 - Sw) where:

HCIP = volume of hydrocarbon in place

A = area of the reservoir, determined by geophysicists and geologists, mainly on the basis of surface seismic.

h = thickness of the reservoir, determined by geologists and

petrophysicists from logs and cores. N/G = net-to-gross ratio (i.e. fraction of the reservoir that consists of

porous rock, e.g. sand or carbonate, hence excluding shale), determined by geologists and petrophysicists from logs and cores. In many cases this boils down to discriminating sand from shale intervals using the gamma-ray log, possibly together with the density/neutron combination (see also Fig. 12 and chapter 5).

φ = porosity of the reservoir, i.e. that fraction of the rock bulk volume that consists of pore space, determined by the petrophysicist from logs and cores. In many cases the porosity is obtained from the density log. Other porosity logs like the neutron and sonic are only used as second bests.

Sw = water saturation, i.e. that fraction of the pore space that contains water, determined by the petrophysicist from logs. In most cases the resistivity logs will be used for this.

Basic steps in Quicklook log evaluation (see also Fig. 13)

1. Review The Logs - Inspect the mud log for intervals with reservoir rock, hydrocarbon shows and

mud gains. - Review the quality of the wireline logs checking headers, depths, scales

calibrations and tool checks as required. Read the remarks section, if present.

- Use logs from surrounding wells, if available, to identify any obvious anomalies in the data.

2. Identify Reservoir Rock (Gamma-ray) - Discriminate potential reservoir rock from non-permeable rock, preferably

using the Gamma-Ray (GR): intervals with low GR values are probably sand (reservoir), intervals with high GR are probably shale (non-reservoir): Fig. 14.

- If the sands are radio-active, a spectral Gamma-ray tool (which distinguishes between uranium, thorium and potassium) should be used. The discrimination can be enhanced by using the neutron-density combination (in shale the neutron lies to the left of the density). Sometimes the SP and/or caliper (mud cake) logs can (also) be used. Prepare a sand count using 1:200 scale logs (preferably the density curve)

- Square porosity and resistivity log readings in the reservoir sections.

3. Discriminate hydrocarbon zones (Resistivity + density/neutron) - Water-bearing intervals are characterised by low resistivity and tramlining

between density and resistivity (porosity is displayed increasing to the left, hence density and neutron scales are chosen accordingly !). Hydrocarbon-bearing intervals are characterised by high resistivity and (often, but not always) by anti-correlation between density and resistivity: Fig. 15.

- In case of saline mud the laterolog deep LLD resistivity is used to obtain the uninvaded zone (“true formation”) resistivity, whereas in case of non-saline mud (e.g. OBM) the induction log deep ILD is used (in ideal cases, i.e. if these logs are available). The resistivity should normally be corrected for borehole/invasion effects using shallow and very shallow auxiliary resistivity measurements (laterolog shallow LLS or induction log medium, ILM and/or Micro-Spherically Focused Log, MSFL). In quicklook evaluations such corrections are often ignored though.

- Separation between deep, shallow and micro resistivity tracks indicates movable hydrocarbons.

4. Gas / oil differentiation - Gas-bearing intervals can often be discriminated from oil-bearing intervals by

looking for high density/neutron separation (in gas bearing zones the neutron

lies to the right of the density), combined with anti-correlation between density and neutron (Fig. 16). However, this effect is obscured if shale is present, because shale gives rise to the opposite effect. Oil can cause some density/neutron separation, but this will not give anti-correlation. Often the sonic is higher and spikier in the gas bearing intervals as well.

5. Calculate Porosity & confirm lithology (Density/neutron) - Calculate porosity preferably using the density log, possibly in combination

with the neutron log, depending on lithology (in some cases the sonic has to be used).

In sandstones calculate the porosity φ from the density log ρlog, by using a matrix density ρma of 2.65 g/cc (unless otherwise known) and a fluid density ρfl = 1.0 (unless otherwise known: see below):

φ ρ ρρ ρ

=−

−ma LOG

flma

In carbonates use the density/neutron crossplot provided in chart books to establish the matrix density, ρma, of any limestone/dolomite mixture before using the above formula.

- The matrix density and apparent fluid density can also be obtained from a calibration of the density log against laboratory measured porosities on core plugs taken over the same interval as the log: see Fig. 17.

- Estimate the fluid density, ρfl, based on the salinity of the mud filtrate e.g. from the mud filtrate resistivity Rmf (see log header) and resistivity vs. salinity charts.

- In hydrocarbon bearing zones approximate the invaded zone fluid density using the mud filtrate density and an estimated hydrocarbon density with

ρ ρ ρfl mf hc≈ +0 7 0 3. .

If in a hydrocarbon bearing zone a fluid density of 1.0 is taken in stead of the correct (lower) value, the calculated porosity will be too high: see Fig. 18.

- Alternatively, in gas-bearing zones, a gas-corrected porosity can be calculated as 2/3 times the density porosity plus 1/3 times the neutron porosity (see Figure 19: the value will be at 1/3 of the distance between density and neutron curves).

- The density / neutron crossplot also gives information on lithology: see Figs. 20 & 21 (and chapter 5).

Intermezzo: the Archie-equations - The amount of hydrocarbon can be calculated via the water saturation

obtained from the resistivity log, for instance using the Archie equations, outlined below. For that purpose, first the water resistivity Rw is obtained from the resistivity in the water-bearing zone, and then the water saturation Sw in the hydrocarbon-bearing zone is calculated using the Archie-equations and the just obtained Rw value. The water saturation is the fraction of pore volume

filled with water. Hence, 1 - Sw is the fraction of pore volume filled with hydrocarbon: the hydrocarbon saturation.

- In many cases substantially more oil can be found by applying more advanced measurement and/or evaluation techniques, especially in the case of thin beds and/or thinly laminated shaly sands. Such techniques will be described in various other chapters of this manual. Moreover, often auxiliary data are required for accurate log evaluations. Such data can for instance be obtained from core analysis (see next chapter), and/or wireline formation (pressure and fluid) tests.

- The Archie-equation for water-bearing rock In a clean water bearing reservoir, all the pore space is filled with formation water. The matrix is an electrical insulator. The only conductor present is the formation water (Fig. 22). Its resistivity (Rw) depends on the concentration of salts dissolved in the water and the temperature of the reservoir. The total resistivity of a water bearing formation (Ro) depends on the resistivity of the water (Rw), the amount of water present (equal to φ) and the shape of the water body (expressed by the cementation factor: m).

Ro = Rw φ-m

This is the first Archie equation. It is sometimes written in terms of the ratio between the resistivity of the fully water-bearing rock Ro and the water-resistivity Rw. This ratio is called the formation resistivity factor (FRF, or F) (Fig. 23):

F = Ro / Rw = φ-m

The cementation factor m depends on the shape of the pore space (Fig. 24). m is reasonably constant within granular rocks, independent of porosity φ. It 's value can be measured on core plugs, deduced from various combinations of logs or estimated for the described rock type. Please note that each individual fully water saturated core plug yields one value of m, and hence a number of plugs have to be measured to obtain good statistical accuracy. For quick look evaluations use the following m values, if no other accurate estimate is available: Sandstone: m = 1.8, Carbonate: m = 2.0 The Archie equation predicts that a double-logarithmic plot of the deep resistivity log versus porosity log in a fully water bearing rock yields a straight line, with slope m and intercept Rw (Fig. 25). This is called the Pickett plot (see also step 6 below).

- The Archie-equation for hydrocarbon-bearing rock In a hydrocarbon bearing reservoir part of the water is replaced by oil or gas, which are also electrical insulators. If the rock is water-wet, the hydrocarbon is

accumulated in the centre of the pore spaces. The remaining water coats the grain surfaces. Electrical current can still travel through the reservoir, along the water layer around the grains. The total resistivity of the reservoir (Rt) can be orders of magnitude higher than the Ro of a similar water bearing formation, because the volume and the connectivity of the conductor (water) is smaller (hence, in a Pickett plot hydrocarbon bearing points would lie above the line through the points of the water-bearing zone). Therefore, in addition to the parameters of the first Archie equation, the total resistivity also depends on the water saturation (Sw = fraction of the pore volume which is filled with water) and the geometry of the water coating the grains (expressed by the saturation exponent n). The increase of the resistivity Rt of the partly hydrocarbon-filled rock over the resistivity Ro of the fully water-filled rock is called the resistivity index I (Fig. 26). It is a function of the water saturation Sw:

I = Rt / Ro = Sw –n

Similar to m, n is often constant within a particular rock, independent of Sw. It's value can be measured on core plugs or estimated for the described rock type. For quick look purposes n is often assumed equal to m. Please note that measurement of each core plug in the laboratory would involve desaturation of the plug to yield various values of Sw and the associated Rt, thus yielding one complete I – Sw curve for each individual plug.

- The combined Archie equations

Combination of the first and second Archie equations gives the following equation which describes how the actually measured resistivity depends on the water resistivity, porosity and water saturation (in case of clean sands or carbonates, for which the Archie equation applies):

Rt = Rw φ -m

Sw-n

6. Establish the water resistivity Rw

To calculate Rw from log readings across a water bearing interval:

- Identify an appropriate fully water bearing section on the logs.

- Calculate porosity φ from a porosity log over this section. - Estimate an m-value (preferably obtain it from laboratory measurements on core plugs), otherwise use the values quoted above for sandstone and carbonate. - Read the resistivity of the water bearing zone Ro from a deep resistivity tool.

-If the resistivity and porosity show sufficient variation over this interval, plot them on a double logarithmic Pickett plot to obtain Rw by regression (Fig. 25).

- Otherwise take average values over the entire water-bearing interval and apply the first Archie equation, re-written as:

R Rw om= φ

- If there is no obvious water bearing interval available, Rw can be estimated using local well data, regional knowledge / experience, an Rw atlas, the SP log, or from measurement on a water sample taken from the same formation in a nearby well.

7. Calculate the water saturation Sw in the hydrocarbon bearing reservoir (Resistivity / porosity)

To calculate Sw from log readings across a hydrocarbon bearing interval:

- Identify the hydrocarbon bearing section on the logs.

- Calculate porosity φ from a porosity log over this section. - Estimate m and n values (preferably obtain it from laboratory measurements on

core plugs), otherwise use the values quoted above for sandstone and carbonate.

- Assume Rw to be equal to the Rw in the water bearing interval.

- Read the resistivity of the hydrocarbon bearing zone Rt from a deep resistivity tool.

Use as the approximate true resistivity, Rt, the deep laterolog reading, RLLD. In the absence of a laterolog, assume the deep induction log approximates Rt. - Calculate hydrocarbon saturation, Sh, from the combined Archie equation, re-

written below in terms of Sw, using (if not known otherwise) m=n=1.8 in sandstones and 2.0 in carbonates:

wh

n

w

SS

mt

wSRR

−=

= ⎟⎟⎠

⎞⎜⎜⎝

⎛

1

1

φ

- The whole procedure is summarised in Figs. 27 and 28. - A simplified procedure is possible if n is close to 2.0 and the porosity of the

hydrocarbon zone is about equal to that of the water zone. In that case above equation for Sw reduces to (Fig. 29):

Sw = (Ro / Rt) 1/2

8. Hydrocarbon Distribution(Wireline Formation Tester - Determine, as far as possible, the presence of the various fluid contacts

(GOC, OWC, GDT, OUT, ODT WUT: Fig. 30) from the logs. Identify the presence of transition zones.

- Use sidewall samples, wireline pressure data and wireline fluid samples to confirm the presence of oil and gas and identify pressure regimes. Target wireline sampling at areas of uncertainty from the log evaluation, particularly where calculated Sh values are between 50 % and 70 % pore volume.

When selecting wireline sample depths take note of the following:

− Specify depths with respect to a named and dated log (e.g. GR of density/neutron/GR of 4/5/94)

− Use the caliper to identify smooth hole on-gauge hole sections − For the wireline pressures pick high porosity intervals where possible to avoid

supercharging: identify these by high porosity and low GR (shale content) − In picking wireline pressures, consider the requirement spacing and position

required for gradient calculation and establishing communication between reservoir units. In long reservoir units take sufficient pressures to identify changes in fluid properties with depth.

9. Reporting - Report the results of the quicklook evaluation summarising the following

elements for each major reservoir and fluid type: Total net hydrocarbon sand count (Net/Gross ratio if gross interval known/defined) Average porosity Average hydrocarbon saturation (transition zone separate) Observed fluid contacts and source (RFT or logs)

Petrophysical parameters used (ρma, Rw , m, n, etc.) Special considerations or peculiarities of the evaluation

Summary of nomenclature: φ Porosity (fraction of bulk volume)

ρb Bulk density (measured by the density log) (g / cc)

ρfl Fluid density (g / cc)

ρg Grain (= matrix) density (g / cc)

ρhc Hydrocarbon (= fluid) density (g/cc)

ρlog Formation density measureds by the logging tool (g / cc)

ρma Matrix (= grain) density (g / cc)

ρmf Mud filtrate (= fluid) density (g / cc)

F Formation Resistivity Factor = Ro / Rw I Resistivity Index = Rt / Ro m Cementation exponent in first Archie equation n Saturation exponent in second Archie equation

Ro Resistivity of fully water bearing rock (Ohmm) Rt Resistivity of partly water (partly hydrocarbon) bearing rock (Ohmm)

Rw Resistivity of the water (brine) (Ohmm)

Sh Hydrocarbon saturation (fraction of pore volume) = 1 - Sw

Sw Water saturation (fraction of pore volume)

Figure 1 - Well Logging

Figure 2 - Depth Measurement

Depth wheelsMagnetic markdetector

Tension device

Derrick floor

Datum level

Tool zero

Figure 3 - Depth Checks

Figure 4 - Standard Log Presentation

GR in previous section

± 50m overlap(through casing)

GR

TD

Casing shoe

Casing shoe: Depth logger = Depth driller ± 0.1%TD: Depth logger ≤ Depth driller

Heading

Remarks

Tool sketch/Well sketch

After surveycalibration

Before survey calibration

Shopcalibration

Direction ofsurvey run

Data quality form(optional)

Main log(1/200 scale)

Repeat section(1/200 scale)

The LOG

Figure 5 - Standard Log Presentation

Figure 6 - Resistivity of NaCl Solutions

200

300

40050060070080010001200140017002000

30004000500060007000800010.00012.00014.00017.00020.000

30.00040.00050.00060.00070.00080.000100.000120.000140.000170.000200.000250.000280.00075

10 20 30 40 50 60 70 80 90 100 120 140 160 180 20050 100 125 150 200 250 300 350 400 20.000

15.000

10.000

50004000

300025002000

1500

1000

500

400

300250

200

150

100

50

40

3025

20

15

10

1

2

3

4

56

8

10

0.8

0.6

0.5

0.4

0.3

0.2

0.1

0.08

0.06

0.05

0.04

0.03

0.01

0.02

Temperature (°F or °C)

°C°F

Conversion approximated by: R2=R1[(T1+6.77)/(T2+6.77)] °F or R2=R1 [(T1+21.5)/(T2+21.5)]°C

Gra

in/g

al a

t 75°

F

ppm

Res

istiv

ityof

sol

utio

n (Ω

-m

)

NaC

lcon

cent

ratio

n (p

pmor

gra

in/g

al)

Figure 7- Depth of Investigation and Resolution

Figure 8 - Mud Filtrate Invsaion

Longspacingdetector

Shortspacingdetector

Source

Invaded zone

Long spacing detector readsdeeper into the formation(maybe beyond invaded zone),but has a less good vertical resolution(almost equal to spacing)

Short spacing detector readsless deep into the formation(still in invaded zone),but has good vertical resolution(almost equal to spacing)

Mudcake

dh

Invadedzone

UndisturbedZone

Undisturbedzone

HIGH Φ

MODERATE Φ

di

di

Invadedzone

Figure 9 - Invaded Zone and Virgin Zone (nomenclature)

Figure 10 - Logging Tools: Investigation Depths vs. Resolution

Rm

Rmc

Rt

Rw

Ro

Rw

Rxo

Rxo

Resistivities Saturations

Sw

1

Sxo

1

Rmf

Rmf

Fluid

Rockw. fluid

0 cm50 cm100 cm150 cm200 cm250 cm2 cm

5 cm

60 cm

20 cm

30 cm

40 cm

80 cm

80 cm

Dipmeter

Micro resistivityMicro log

Sonic

Density

Gamma-ray

Neutron

Laterolog

Inductionlog

0 cm50 cm100 cm150 cm200 cm250 cm2 cm

5 cm

60 cm

20 cm

30 cm

40 cm

80 cm

80 cm

Dipmeter

Micro resistivityMicro log

Sonic

Density

Gamma-ray

Neutron

Laterolog

Inductionlog

Resistivity

Radioactivity

Acoustic

Resistivity

Depth of Investigation and Resolution of Logging Tools

Depth of Investigation

Res

olut

ion

Figure 11 - Volume of Hydrocarbons In Place

Figure 12 - Hydrocarbon Volume

HCVOL = A * h * (N/G) * φ * (1 - Sw)

Hydrocarbonvolume

Net over gross

Reservoirvolume

Porosity

Watersaturation

A = area

hh * (N/G)Sand

Clay

Sand

Oil

Water

MatrixReservoir

Figure 13 - Basic Petrophysical Evaluation Steps

Figure 14 - GR Interpretation in a Sand-Shale Sequence

0 100GR (API)

0% Shale

100% Shale1840

1830

1820

1810

1800

Shale

Sand

Shaly sand

Shale

Sand

Shale

DEPTH IN m

50 %shale

Rock

Reservoir

Non-reservoir

Hydrocarbonbearing

Waterbearing

Gas bearing

Oil bearing

Evaluate

Evaluate

1. Locate reservoirs2. Detect hydrocarbons3. Distinguish oil and gas4. Evaluate: Shc, φ, h, k

Figure 15 - Hydrocarbon Effect

Figure 16 - Quicklook Evaluation

0 GR (API) 150 2.0 Density (g/cc) 3.042 Neutron (lpu) 18

0.2 Resistivity (Ωm) 20

2200

2150

2100

2050

GOC

OWC

Figure 17 - Core Porosity Calibration

Figure 18 - Gas Effect on Density Porosity

100

80

60

40

20

0 1.0 1.5 2.0 2.5 3.0

Log density (g/cc)

Core matrixdensity

ρma

Apparentfluid

densityρfl

Cor

e po

rosi

ty (%

bv)

Density log (g/cc)

Core porosity(% bv)

100

50

0

0 1.0 2.0 3.0

Apparentgas density

Assumedfluid density

True φApparent φ

Figure 19 - Quicklook Porosity Determination in Gas Bearing Zones

Figure 20 - Neutron / Density X-plot

Raw Data (Limestone Presentation)Results Data (Sandstone Presentation)

2/31/3Gas

effect

Gas corrected porosity

40302010

03.0

2.9

2.8

2.7

2.6

2.5

2.4

2.3

2.2

2.1

2.0

1.9

Neutron Porosity Index (pu)

Bul

k D

ensi

ty (g

/cc)

ρf = 1.0

15

20

25

35

40

Porosity

Sandsto

ne

Limes

tone

Dolomite

Salt

Langbeinite

Polyhalite

Anhydrit

e

ApproximateGasCorrection

0

5

10

30

40

35

30

25

20

15

10

5

00

5

10

15

20

25

30

35

40

Figure 21 - Density/Neutron Response in Various Lithologies

2.0 2.2 2.4 2.6 2.8 3.0

30 18 6 -6

Neutron (lpu)

Lithology Porosity Fluid

Salt

Anhydrite

Limestone

Limestone

Dolomite

Shale

Sandstone

Sandstone

Sandstone

5%

15%

Water

Water

15% Water

20% Gas

20% Oil

20% Water

Density (g/cm3)

Figure 22 - Current Path Through Clean (non-shaly) Porous Rock

Figure 23 - First ARCHIE Equation: fully water-bearing rock

Elec

tric

al c

urre

nt

Elec

tric

al c

urre

nt

Matrixnon-conductive

Matrixnon-conductive

Formation waterconductive

Formation waterconductive

F

φ 1.00.11

100

10m

F = Formation resistivity factor (FRF)

Ro = Resistivity of 100 % brine saturated rock

Rw = Brine resistivity (Ωm)φ = Porositym = Cementation factor

F = Ro / Rw = φ-mEach pointrepresentsa separatecore sample

Figure 24 - Influence of pore structure on FRF

Figure 25 - “Pickett” Plot

F high(≅ 300)

F moderate(≅ 50)

F low(≅ 10)

Porosity

Res

istiv

ity

Rw

x

x x

x

x

xx

x

Slope = m

0.01

0.1

1

0.01 0.1 1

10

Figure 26 - Second ARCHIE Equation: partly water (hydrocarbon) bearing rock

Figure 27 - Water Saturation from Resistivity Logs

n

I

Sw 1.00.11

100

10

I = Resistivity indexRt = Resistivity of

partly brine saturated rock

Ro = Resistivity offully brinesaturated rock

Sw = Water saturationn = Saturation exponent

I = Rt / Ro = Sw-n All points are

measured onthe samecore sample

Oil zone

Water zone

Resistivity depends on:- Porosity- Constants m & n- Water resistivity- Water saturation

Resistivity depends on:- Porosity- Constant m (≈ 1.8 - 2.0)- Water resistivity1

2

Resistivity loglow high

Figure 28 - Quicklook Evaluation Steps

Evaluate net sand from GR

Evaluate φfrom Density

Identify water zone and

calculate Rw

Find gas zonefrom D/N andre-calculate φ

in HC zone

Calculate Sw using the Rw calculated in the water zone

11 22 33

44 55

Figure 29 - Quicklook Evaluation Steps – Simplified Procedure

Evaluate net sand from GR

Evaluate φfrom Density

Identify water zone and assess Ro

Identify gas zonefrom D/N separation

Sw = Ro/Rt

11 22 33

44 55

Figure 30 - Uncertain Fluid Contacts

1840

1830

1820

1810

1800 0 200GR(API) 2 3Density (g/cm3)42 -18Neutron Porosity

0.2 2000Resistivity (Ωm)

ODT

OUT

GDT

WUT

3. Coring and Core analysis

Summary

In this chapter the following subjects are discussed: - Coring methods - Core handling procedures - Depth and quality control - Routine core analysis for petrophysical properties (porosity, permeability, grain

density) - Averaging of porosities and permeabilities - Special Core Analysis (SCAL) for petrophysics (especially resistivity

parameters, i.e. Archie’s m & n and Waxman-Smits parameters, and compaction)

Why do we need cores ?

In several stages of log evaluation parameters are required which are not available from the logs, e.g. the matrix density, Archie's cementation factor (m) and saturation exponent (n), similar parameters for more advanced saturation models used in shaly sands, permeability, rock compressibility, strength, etc. Moreover, cores are important for geological descriptions and evaluations as well as for other disciplines (e.g. reservoir engineering: relative permeability, capillary pressure; Production Technology: compatibility tests, strength). Also, core measurements may give an independent estimate of the formation hydrocarbon content, e.g. via measurement of the capillary pressure curve. The Value of Information (VOI) in core analysis in many cases is sufficiently high to justify it. An extreme example is the case of the rapid subsidence (caused by reservoir compaction) of the Phillips Ekofisk field. Proper core analysis (i.e. laboratory compaction measurements) prior to production would have cost about 1 million US $. Because of lack of such high quality tests (some low quality test data were available which didn’t highlight the potential compaction danger), Phillips only noticed the rapid subsidence of the field when it was already too late. They had to jack up a production platform with about 6 metres (which required stopping production for several months), costing them in total about 1 billion (1000 million) US $, hence a thousand times more than a proper core analysis study would have cost them. Not all cases will be this dramatic, but core analysis will pay off in many cases very easily. The different discipline needs for core data can be summarised as follows:

Petrophysics - Basic rock properties (porosity, permeability, grain density) - Saturation from capillary pressure - Effect of stress and reservoir (production induced) compaction / subsidence - Electrical properties (m, n) and Cation Exchange Capacity (CEC) - Acoustic properties

Geology - Core description - Facies analysis (also for Special Core Analysis [SCAL] sampling)

- Mineral identification - Diagenesis and clay typing - Depositional information - Formation age - Microscopic and X-ray analysis

Reservoir engineering - Relative permeability (not discussed here: see courses on Reservoir Engineering) - Capillary pressure curves - Critical gas saturation - Pore volume compressibility - Flooding tests

Production technology - Well injectivity - Sand control parameters - Rock mechanical data - Mineralogy for acid stimulation

Core analysis planning

As coring is expensive it has to be carefully planned. Different types of coring jobs are required in different circumstances (lithologies, fluid/pressure regimes, objectives). Once the core has been obtained careful planning is again required to get the most out of it: sample handling and the measurement sequence have to be defined in advance and agreed by all disciplines involved. The following is an example list of things to consider.

Coring / Core analysis planning flow sheet Prior planning

Company SCAL focal point available ? And/or: Consult Company manuals, guidelines, strategies Contact Company specialists if scope is outside that of standard contractors

Define core objectives Dependent on reservoir and well objectives To be defined by multi-discipline planning:

Multi-disciplinary planning Define what is needed for each discipline & how many routine / SCAL samples (also very much dependent on lithology & wettability). Decide which sections/intervals to be cored. Discuss with all parties involved (drilling contractor, mud engineer, coring and core analysis companies).

Discipline requirements See section above;The petrophysicist normally coordinates coring and core

analysis. Drilling input: Identify & advise on possible well problems (shale, over-pressure, fractures, sticking hole), bit type, mud type, cased sections, etc.: see also Wellsite planning (below)

Calculate costs & VOI of core

May go for SWS, rotary coring tool, etc. (adv. / disadv.) In all of the below: cost aspects drive the decisions Decide whether core will be taken. If yes:

Make a justification for the core: Get it approved Prepare budget for all the below: Including budget for QA/QC, post-mortem review Select coring & CA contractors: Tender; criteria: audit reports --> reliability vs.

time/costs Put contract in place Wellsite planning Choice of drill bit, ROP, WOB, ..

Roller cone, PDC or diamond bit: dependent on lithology etc. Best core quality if well is drilled slowly Clean consolidated: standard Unconsolidated: special bits & barrels, core freezing?, stress Shaly sandstones: fluids that don't cause swelling, drying process

Choice of drilling mud, overbalance Dependent on presence of swelling clays, overpressure, ..

Choice of core barrels: Dependent on lithology, temperature, consolidation, fractures

Choice of core types ROS requirements ? (sponge, or pressurised coring): depends on pressure/consolidation/deviation, costs, safety Oriented cores ? (if special geological considerations)

Wellsite handling Bringing the core to surface: Running Out of Hole (ROH): preferentially: slow !! Core handling / preservation: Freezing, wax sealing required ?, etc. Transportation to the lab.: Avoid shocks & vibrations Laboratory handling Define requirements: Reporting: raw data should be kept (tell contractor) Reassemble core; Core screening / preparation: Depth matching (Gramper, Cat-

scan) SCAL screening: Preserve SCAL sections Whole core required ? If not: slab, UV/normal photo; geol. descr.; take plugs

(Slabbing: slicing off part of the core parallel to its axis). Preservation & storage

Don't neglect these aspects: core & samples can deteriorate pretty quickly Plug taking # horizontal & vertical plugs (see discipline requirements above)

Routine: every ft; SCAL every 20 - 100 ft Be aware of impact of well deviation & laminae Core disturbance observed?: may lead to biased sampling Take into account: facies description, critical parameters, number of samples required per lithological unit

Core sampling / Sample preparation: Cleaning & drying (wettability & clay considerations)

Core analysis measurements See discipline requirements defined above Choice of CA/SCAL method dependent on: plug conditions, lithology, required stress level, need for simulated in-situ conditions, accuracy vs. costs/time

Evaluation / analysis: Corrections, averaging Reconciliation with log data. Discrepancies can be due to:

problems with the core data: biased sampling, core disturbance, vugs, incorrect measurement equipment or procedure, scale / averaging effects, improper correction for clay effects, stress, temperature, wettability, fluid type problems with the log data: incorrect interpretation model and/or parameters, thin bed and/or invasion effects, clay/lithology effects, use of wrong tool type, tool failure / malfunctioning

Repeat measurements ? May be required dependent on CA / SCAL results QA/QC

Check tables & figures for anomalies. If possible: check consistency against available data for similar wells / fields.

Report and review: May be input for annual audit report Discuss with contractor: Possible improvements in their procedures Store data in database Close out. Return core; pay the bills

Core Acquisition

Coring methods Coring has to be done using special drilling bits and core barrels (Figs. 1-2). Special attention also has to be paid to the coring fluid used (WBM, OBM etc.). Conventionally one used a fixed steel inner barrel. However, core damage was quite common, especially in unconsolidated sands. Therefore, nowadays containerised coring methods are used. They make use of a disposable inner sleeve or liner. This gives improved handling, less core exposure and easy stabilisation (e.g. using resin, or freezing).

Common inner barrels are: - fibreglass (standard) - aluminium ( used at high temperature) - plastic (soft liner: used in very unconsolidated sands) - (chrome plated) steel (used in fractured formations, high temperatures, deep wells or at high vibrations)

Another coring technique is wireline coring. In this technique, a drill bit can be transformed to a coring bit by removing the centre of the bit downhole using a wireline removable plug.

Yet another technique is oriented coring. In this method a groove is cut in the core during the coring process. This groove is aligned to the EMS survey tool. However, this process can damage / destroy the core (e.g. due to jamming) and is, therefore, not very popular.

The fluid saturation in the core at surface can be entirely different from the in situ saturation, because of flushing by the mud and because of fluid (gas) expansion while the core is transported to surface (pressure release). For instance, if the in-situ oil saturation is 70 % (hence brine saturation 30 %), the oil saturation in the core down-hole after mud filtrate invasion might for instance be reduced to 30 % (brine / mud filtrate saturation 70 %). During the trip to surface, solution gas will expand, driving oil and water out, such that at surface we might have 12 % oil, 40 % gas and 48 % brine (just as an example:actual numbers will depend on many factors).In case of a gas reservoir, if the in-situ gas saturation is 70 % (hence brine saturation 30 %), the gas saturation in the core down-hole after mud filtrate invasion might for instance be reduced to 30 % (brine / mud filtrate saturation 70 %). During the trip to surface, the gas will expand, driving water out, and partly form condensate, such that at surface we might have 1 % oil, 49 % gas and 50 % brine (again: just as an example:actual numbers will depend on many factors). Therefore, in general, fluid saturations obtained from cores (e.g. using the Dean & Stark technique, see further below) are not very reliable. If one still wants to preserve the in situ fluids, two techniques are available, which are especially used in Residual Oil Saturation (ROS) studies (and are, therefore, not very popular at these current times of low oil prices):

1. Sponge coring: the fluids that leak out of the core because of the pressure release are captured by an oil-wet sponge which surrounds the core. In the laboratory the total amount of fluids (those in the core and those in the sponge) are analysed: together they should come closer to the in situ saturation. Sponge coring is about twice as expensive as conventional coring. It requires two trips. It has a high chance of success (about 95 %).

2. Pressure coring: the core is kept at in situ pressure by using a special valve / closing system. hence, at surface the core and the fluids in the core are still contained in a pressurised barrel which is at in situ pressure (though not at in situ temperature). This process is obviously dangerous (high pressure !) and therefore safety measures have to be taken. The method can only be applied for consolidated reservoirs which are at ROS, with reservoir pressure less than 5000 psi. Also the borehole deviation should not be very strong. Pressure coring is more than ten times as expensive as conventional coring. It requires four trips. The success rate is rather limited (65 – 75 %).

A new coring method is gel coring in which a protective gel is put around the core during the coring process.

Alternatives to taking cores are taking Sidewall Samples (SWS) (Fig. 3) or using a rotary coring tool (Fig. 4). Sidewall samples have the advantage that they are fast and cheap, available up to 500 deg. F, one can individually select the sample depths, and a large number of samples can be aqcuired in a single trip (up to 90). However, the sample quality can be low (because of the impact of the bullet), such that petrophysical parameters can not be trusted. Also, the samples are small, and they can not easily be obtained in large holes. SWS are normally used in a qualitative sense, namely for identification of lithology and fluid type.

Another alternative to coring is using a wireline rotary coring tool, which drills samples out of the borehole wall (rather than cutting them out with the SWS bullet). Because of this process the sample quality is better, especially in hard rock. Again, the sample depths can be selected individually. However, the number of samples per run is more limited (maximum 30). Furthermore, the tool is ineffective in unconsolidated formations and in washouts. Finally, the costs are substantially higher than costs for SWS.

Core handling The standard core handling scheme after the core has been got out of the hole and laid on the well site surface is depicted in Fig. 5. A standard colour coding is used to identify top and bottom, namely two lines are drawn on the core surface from top to bottom: a blue and a red one, where the red one is to the right of the black one.

Core Analysis

Quality and depth control A good means of quality control (QC) is using a CT (Computed Tomography) X-ray scanner. This is basically a medical device, but in stead of scanning humans, it can also be used to scan cores (Fig. 6). A CT scan can reveal inhomogeneities and irregularities inside the core which would otherwise be invisible. It also yields a density (g/cc) image of the core.

A Gamma-Ray Attenuation device (Fig. 7) (very similar to a density tool measurement) can be used to obtain a core density log which can be compared to the density log for depth matching and to identify zones where core may have been lost.

Plug preparation, cleaning and fluid assessment Plug samples will be drilled out of the slabbed core, to allow measurement of petrophysical and other properties. Plugs can be drilled using different types of fluid (normally water). The plug orientation should be chosen relative to the bedding. The plugs are normally cleaned such that they become water wet. Oil is removed with solvent extraction (Soxhlett) and methanol/chloroform diffusion. Fluid saturations are obtained in the Dean-Stark method (Figs. 8-9). After the cleaning the samples are dried. Various methods exist, of which vacuum oven drying (16 hours at 95 degrees C) is considered (in Shell) to be the most reliable. A special technique is Critical Point Drying, which is an option in case of sensitive clays 9especially illite fibres). This technique is rather costly and time-consuming though and is therefore rarely used.

Routine core analysis Routine core analysis is normally defined as the measurement of basic parameters like porosity, permeability and grain (matrix) density.

Porosity (fraction) is defined as:

φ = Vp / Vb = (Vb – Vg) / Vb

where:

φ = porosity

Vp = pore volume of the sample

Vb = bulk volume of the sample

Vg = grain volume of the sample

Because Vb = Vp + Vg , only two of the three volumes have to be measured to define porosity.

Grain density is defined by:

ρg = A / Vg

where: A = mass (weight) of the dry sample

Bulk volume can be measured using: - buoancy in mercury (Fig. 10): the mercury does not invade the sample, hence the amount of mercury displaced is equivalent to the sample bulk volume - mercury displacement (similar to Fig. 10, but just recording the raise in mercury level) - caliper measurements (only works with nice cylinder-shaped samples)

Pore volume can be measured by comparing the weights of the dry and the liquid saturated sample.

Grain volume can be measured by using: - buoyancy in chlorotene (Fig. 11): the chlorotene does invade the sample pore

system, hence the amount of chlorotene displaced is the sample grain volume

- Boyle’s law porosimetry: helium expansion using Boyle’s law. Two vessels of known volumes V1 and V2 are connected via a tube which can be closed off

with a valve. A dried and cleaned rock sample is put into vessel 1, and the total system is evacuated. Subsequently vessel 1 is filled with helium to pressure p1, and vessel 2 is filled with helium to pressure p2 (valve in between is closed). Next, the valve in between the vessels is opened: the pressures change until an equilibrium pressure p is obtained in both vessels. The grain volume Vg can then be obtained from Boyle’s law:

p1(V1 – Vg) + p2V2 = p (V1 + V2 – Vg) Grain density can be measured using a pycnometer. A crushed dry sample is put into the cell and weighed. Thereafter, toluene is added and mixed with the sample, degassed, and the cell is weighed again. The grain density is calculated from the weights (empty cell, cell with sample, cell with sample and toluene), the cell volume and the toluene density.

Permeability is defined via Darcy’s law. The gas (air) permeability is routinely measured using the Ruska permeameter (Fig. 12). A more detailed profile can be obtained with the mini-permeameter (Fig. 13). For low permeabilities (< 1 mD) the pressure pulse permeameter has to be used (Fig. 14).

In situ permeability is influenced by lithology (e.g. clay type / content), stress, pore structure (also coupled to grain size) etc. Permeability is normally low if pore bridging clay is present, moderate if pore lining clay is present and high if clay is not present or present as discrete particles (i.e. not obstructing the fluid flow).

Laboratory measured permeability is influenced by the following factors: - Confining stress (see section on compaction below) - Pore content (e.g. brine permeability may be different from air permeability due to clay swelling. This is especially important at low salinities) - Gas slippage: the so called “Klinkenberg” effect (Fig. 15) - Turbulence - Cleaning / drying effects Normally, air permeabilities are measured routinely. They should be converted to in situ brine permeabilities, by correcting for above mentioned effects, in particular for stress and clay swelling. The Hill-Shirley-Klein equation can be used for the latter. The correction may be a factor of ten in some cases (air permeability being higher than brine permeability). Permeability (plotted logarithmically) is often correlated to porosity to enable derivation of a continuous permeability log from the porosity log. Such correlations are never very good (a standard deviation of a factor of ten is already considered to be good !). A better estimate of the permeability can normally be obtained from the NMR (Nuclear Magnetic Resonance) logging tool.

Averaging core data Core analysis data are measured on plugs of about 1 – 2 inches size. Hence, they represent an extremely small portion of the reservoir. Therefore, grand scale reservoir properties (e.g. reservoir simulation grid block properties) have to be derived from the core measurements by averaging or “upscaling”. For porosity a simple linear (“arithmetic”) average will do in most cases. Some simple analytical equations exist for averaging permeabilities in cases of parallel horizontal flow through horizontal bedding (“arithmetic average”) or series

vertical flow through horizontal bedding (“harmonic average”) or a well-defined combination (“geometric” or “logarithmic” average):

Arithmetic average: kav = (k1h1 + k2h2 + k3h3)/(h1 + h2 + h3) (equations are given for permeability k, assuming layers with thickness h)

If the thicknesses are all equal, this boils down to a straight linear average of k The arithmetic average would normally be used for quantities having no directional dependence, and/or to average parallel flow properties (flow parallel to layering).

Harmonic average: kav = (h1 + h2 + h3)/(h1/k1 + h2/k2 + h3/k3)

If the thicknesses are all equal, this boils down to a straight linear average of 1/k (inverse permeability) The harmonic average would normally be used to average series flow properties (flow perpendicular to layering).

Geometric average: kav = (k1)a.( k2)

b.( k3)

c

with: a = h1/(h1 + h2 +h3)

b = h2/(h1 + h2 +h3)

c = h3/(h1 + h2 +h3)

If the thicknesses are all equal, this boils down to a straight linear average of ln(k), hence of the logarithm of k. The geometric average is sometimes used to estimate the average for random flow properties (randomly mixed systems). However, in such cases it is better to use a more realistic calculation method, e.g. finite element modelling, effective medium theory, etc. For more complex geometries and/or for other properties this upscaling is still largely a subject of research. In some cases, other measurements are available which have a larger depth of investigation. For instance, grand scale permeability can be derived from well tests which may have an investigation depth of hundreds of metres. If such tests are not available, or if such test results disagree with the core measurements, the latter have to be upscaled. For permeability this might be done using a combination of geological modelling and reservoir simulation.

Special core analysis (SCAL) Special core analysis (SCAL) normally covers measurements like the Archie m and n factors, other resistivity parameters like Qv (used in the Waxman-Smits equation), reservoir compressibility, capillary pressure, relative permeability (discussed in the courses on Reservoir Engineering), etc. Here we only discuss the resistivity parameters and compaction parameters.

The Archie cementation exponent m and the associated Formation Resistivity Factor (F, or FRF), are measured together with stressed porosity in a special

pressure cell (Fig. 16). The sample is first cleaned and made fully water wet. Then the atmospheric porosity is measured. Artificial formation brine is made which is equal in composition to the actual formation brine. The resistivity of this brine is measured in a separate cell. The rock sample is cleaned again and fully saturated with this brine. It is then put into the measurement cell (Fig. 16) and subjected to hydrostatic stress (about 70 bar), and the resistivity is measured. The amount of brine expelled gives the reduction in pore volume from which the in situ porosity can be calculated.

The Archie saturation exponent n and the associated Resistivity Index can be measured with several methods.

1) Continuous Injection (Fig. 17) This is the recommended method. Only a drainage curve (curve obtained starting with 100 % brine and ending with low brine saturation) is available. The cleaned sample is saturated with brine , placed in a core holder, and subjected to confining stress (about 70 bar). The resistivity at 100% brine saturation is measured. Subsequently, laboratory oil (e.g. kerosene) is injected very slowly (about 1 nanoliter per second, thus displacing approximately one pore volume in 14 days) at the top, and the displaced water is pushed out at the bottom via a water wet filter. About every 8 hours the resistivity, temperature and amount of brine produced (collected in a vessel below the cell) are recorded. From the latter quantity the water saturation is easily calculated. Thus a (semi-) continuous curve of resistivity index I versus brine saturation Sw is derived.

2) Pressure equilibrium Very similar to the continuous injection method. Both a drainage curve (curve obtained starting with 100 % brine and ending with low brine saturation) and an imbibition curve curve (curve obtained starting with low brine saturation [i.e. the end of the draining cycle] and ending with high brine saturation, hence re-injecting brine) can be measured. This is possible because there also is an oil wet filter at the top. In stead of injecting the kerosene continuously at a slow rate, the kerosene is injected in discrete pressure steps, and after each pressure increase one waits for pressure equilibrium to be restored. Because these wait times can be long, a typical pressure equilibrium test takes about 6 weeks per sample and is therefore time-consuming and expensive. The measurement is considered to be the most accurate one though.

3) Porous plate This is an old contractor method and is no longer recommended. In this method several samples are placed on a big porous plate and desaturated simultaneously by applying a gas pressure step (brine leaves via the porous plate). The samples are then removed from the plate and their resistivities are measured in separate resistivity cells. The saturations are obtained by weighing the samples. Because of the many manual handling steps involved the corrections required are big and the inaccuracies are often unacceptable.

The Cation Exchange Capacity (CEC or Qv), an important parameter in the Waxman-Smits equation (the Archie replacement for shaly sands) can again be measured using several methods.

1) Membrane potential (Fig. 18) This is the recommended method. Top and bottom of the core plug are brought into contact with brines of different salinities. Because of diffusion of ions from the liquid with greater salinity through the sample to the liquid of

lower salinity, a potential (voltage) will arise, called “membrane potential”, from which the CEC can be calculated using expressions given by L.J.M. Smits in his paper on membrane potential (see SPWLA reprint volume). The advantages of this method are: it is relatively fast and very accurate, and the sample is left in tact.

2) Multiple salinity (Fig. 19) The Waxman-Smits equation itself (chapter 10) is used in this method. The conductivity (1/resistivity) of the brine saturated sample is measured using brines with different salinities (hence different conductivities). This involves resaturating the sample each time with a new brine and waiting for equilibrium. This may take a long time for each new brine, and therefore the method is slow and expensive. The method is very accurate though, and the sample is left in tact.

3) Conductometric titration This is the usual contractor method. The sample is crushed (disadvantage of this method !) and the Cation Exchange Capacity is measured by titration, e.g. using Ba-ions. Sometimes Ammonium acetate is used, but this is not prefered. The method is very fast and cheap but less accurate because possible clay structure effects are not taken into account, as the sample is destroyed (crushed) to allow the measurement.

Formation samples

Cuttings Cores

Size: ca 1 x 3 mmLag timeSlippageCollected every 1 - 2m

Length: 9 - 18 - 27mDiameter: 10 - 20cmCosts: variable (depth, length)

say 1500$/m

Drillingbit

Corehead

Figure 1 - Coring Process

Core bit and Barrel

Inner barrel

Core catchersub

Outer barrel

Core catcher

OD gage

ID gage

Bit faceor crown

Fluidcourses

Core catcher

Figure 2 - Core Barrel

Sidewall sample gun

Bullet

Sample

Formation

Igniter

Powdercharge

Figure 3 - Sidewall Sample Gun

Sidewall coring tool

Hydraulic drill motor

Drill bit

Core storage tubeCore recovery indicator

Core punchRecovered core

Figure 4 - Sidewall Coring Tool

Core handling on the well site: containerised coring

Standard handling 1m (3ft) sections1) Draining, cleaning2) Marking3) Logging4) Sawing5) Sampling6) Capping7) Plugging8) Resination9) Chilling/freezing10) Racking/boxing11) Transport

6/m9m/12m sections1) Draining, cleaning2) Marking3) Logging4) Capping5) Plugging6) Resin injection7) Transport

1

2

3

45

6 (4)

7

11 (7)

10

9

8

1m (3ft)

Figure 5 - Core handling on the Wellsite (Containerised Coring)

CT Scanner Principle

Coresection

Core positioner

Detectors

X-ray source(fixed position)

Figure 6 - CT X-ray Scanning

Gamma ray attenuation

Detector

Source

Shield Shield

ShieldCore

d

lo l

lo = Initial intensity (counts/sec)

l = Attenuated intensity (counts/sec)

d = Diameter (cm)

σ = Mass attenuation coefficient (cm^2/gr)

δ = Bulk density (gr/cm^3)

dl/lln

ell

o

do

σ=δ

= σδ−

Figure 7 - Gamma Ray Attenuation

Dean-Stark apparatus

Figure 8 - Dean Satrk Apparatus

Dean-Stark distillation

• Weigh sample + fluids Wt• Toluene distillation (112°C) Ww• Chlorothene extraction to remove

remaining oil• Dry core (95°C) Wd• Calculate Wo

Wt = Wd + Ww + Wo

Wt = total weightWd = dry weightWw = weight waterWo = weight oil

Figure 9 - Dean Stark Distillation

Bulk volume (Vb)

Plug

MercuryA

B

Vb = -M - AρHg

A = Dry weight of sample

B = Buoyancy of sample = V • ρHg

M = Weight of sample in mercury = A - B

Figure 10 - Porosity: Determination of Bulk Volume

Grain volume (Vg)

Plug

ChlorotheneA

B

Vg = -M - AρChl.

A = Dry weight of sample

B = Buoyancy of sample = V • ρChl.

M = Weight of sample in chlorothene = A - B

Figure 11 - Porosity: Determination of Grain Volume

“Ruska” permeameter

PlugP1 P2

Air

N2 gas50bar

≈ 2 bar ≈ 1 bar

Rubber sleeve

Kair =2000 • Pa • Qa • μ • L

(P12 - P2

2) • A

Kair = Permeability (mD)Pa = Atmospheric pressure (atm)Qa = Flowrate (cm3/s)m = Viscosity of air (cp)L = Length of sample (cm)P1 = Upstream pressure (atm)P2 = Downstream pressure (atm) A = Cross section area (cm2)

Figure 12 - Determination of Permeability

Schematic diagram of the mini-permeameter

Air supply

Core

Air flowAir flow

Rubber orifice

Flow meter

Pressure

PermeabilityPermeability is a measure of the fluid conductivity of a rock.The unit of permeability is the Darcy.

K Permeability L Length (cm)Q Fluid flow (cm3/sec) A Area (cm2)μ Fluid viscosity (cP) ΔP Pressure difference (atm)

K =Q μ LA ΔP

Figure 13- - Determination of Mini Permeability

V2

Pressure pulse permeameter

Plug

P1 P2ΔP

V1

101 bar 100 barHydrostatic

pressure110 - 400 bar

• Valve opened• Measured ΔP vs time• Plot log ΔP vs time (decay curve)• Permeability can be calculated from

straight part of the curve

• No turbulance• No slippage• Good for low K

Figure 14- - Determination of Permeability

Kgas Kliquid

XX

X

0 10 20 30 40

20

40

60

K

1/Pm

• K is independent of fluid type and ΔP

• Kgas > Kliquid, due to slippage of the gas along the rock wall:Effect high at: - Low pressure

- Low K

• At high pressures gas acts as fluid

factorgKlinkenberb

Pmb1

KK g

l =⎟⎠⎞

⎜⎝⎛ +

=

Figure 15- - Klinkenberg Correction

Pressure cell for combined measurements of porosity and formation resistivity factor

Burette

Burette

Polyethylene sleeve

Platinum electrode

Oil pressure for lateral stressRock sample

Platinum electrode

Oil pressure for axial stress

Figure 16 – Measurement of FRF

Continuous injectionOil

Water

Resistivitymeasurement

Injected oil volume

Measuredresistivity

*****

**

Sample is originally filled 100 % with brine.Oil is injected at a low rate (1 nanolitre/second) --->most of the pore volume is filled with oil in about two weeks time.

Figure 17 – Continuous Injection Method

Dr.no. NWH 9805025

Principle of membrane potential method

T = 25°C

m1 m2

ΔUm3

ΔU = f [m1, m2, Cw, Ce]

Figure 18 – Measurement of Qv: Membrane Potential

Dr.no. NWH 9805025

Principle of multiple salinity methodCeCw

Co

0

2

4

6

8

10

12

14

0 50 100 150 200 250

Slope 1/F*

Cw

Co= [Cw+ Ce]1F*

Figure 19 – Measurement of Qv: Multiple Salinity

4. Capillarity and wettability

Summary

Capillary pressure curves are used by petrophysicists and reservoir engineers. In this chapter only the petrophysical applications are discussed. Petrophysicists use capillary pressure curves to get an independent check on log derived hydrocarbon saturation. This can be done because a saturation/height function can be derived from laboratory measured capillary pressure curves on core samples (Fig. 1).

The phenomenon of capillarity refers to the rock’s capability to suck up liquid. This capability depends on surface tension, wettability, and pore size distribution. The surface tension describes how the bubble remains in shape. The wettability describes which fluid is wetting the rock. The capillary pressure curve describes how much wetting fluid can be pulled up, against gravity (buoyancy). This is a function of (water) saturation because the smaller pores are capable of pulling up water to a higher level above the oil/water contact than the larger pores (influence of the pore size distribution). In the reservoir capillarity leads to a transition zone above the hydrocarbon/water contact. The OWC (oil/water contact, obtained from logs) may be above the FWL (free water level, obtained from RFT pressures), dependent on the magnitude of the capillary entry pressure. The capillary pressure curve can be measured in the laboratory, and converted to field conditions. From this laboratory measured curve a saturation / height curve can be obtained which can be compared with (resistivity) log derived saturations.

References

- L.P. Dake, Fundamentals of reservoir engineering, Elsevier, 1995 (15th ed.), pp. 343 - 349

Introduction

Capillary pressure curves are used by petrophysicists and reservoir engineers. The petrophysicists use them to get an independent check on log derived hydrocarbon saturation, as a saturation/height function can also be derived from laboratory measured capillary pressure curves on core samples. To understand this, we have to dive a little bit into the physical chemistry of this phenomenon.

Rock / fluid interactions Porous rock is characterised by its lithology/mineralogy and its pore structure. Fluid is characterised by several properties such as chemical composition, density, viscosity and surface tension. For instance, mercury has a large surface tension, meaning that its surface has a strong tendency to pull a droplet of mercury to its

minimum size, i.e. a sphere. The same phenomenon can be seen when a water droplet is hanging below a tap: it tends to the shape of a sphere. If two liquids are in contact, their interfacial tension determines what happens to the shape of their interface. For instance, in most oil/water systems the water will tend to curve around the oil (hence, the water surface is concave, the oil surface is convex). When fluids are in contact with porous rock, the fluid distributions are governed by the interfacial tensions, the pore size distribution and the wettability of the rock. This latter property describes which of the fluids preferentially sticks (adheres) to the rock (i.e. "wets" the rock). Important parameters, therefore, are:

- Fluids: interfacial tension and fluid density (viscosity does NOT come into it, because capillary pressure is a static, not a dynamic phenomenon).

- Rock: pore size distribution and mineralogy.

- Rock / fluid interaction: wettability (or: contact angle). These parameters will now be described in more detail.

Surface (interfacial) tension

A soap droplet floating in air has a pressure P1 inside which is greater than the outside pressure P2 (Fig. 2). The pressure diffence can be sustained by the droplet because of its surface tension: the attraction between the molecules at the surface holds the droplet together. The droplet can only be stable if the shearing force (proportional to the pressure difference), acting across the cross-section is kept in balance by the interfacial tension force acting along the circumference of this cross-section: Fig. 3. This force balance equation reveals that a droplet can hold a greater pressure difference if the interfacial tension is high (e.g. mercury) and / or if the droplet is small. Interfacial tension may vary considerably for different oil/water, gas/water or gas/oil systems, and is also dependent on temperature and pressure. People have tried to find empirical and theoretical relations to predict interfacial tension for a given fluid system and given pressure & temperature. So far these attempts haven’t yielded useful relationships, hence the interfacial tension has to be measured in the laboratory for each new field. For oil/water systems a typical range is: 15 – 35 dyne/cm.

Wettability Wettability describes which fluid preferentially adheres to the rock. In the past most rocks were believed to be water-wet, i.e. the water will preferentially form a thin layer (film) sticking to the rock (grain, pore wall) surface, such that the oil is expelled to the center of the pores. This is due to chemical forces between water molecules and molecules in the rock minerals. (In some cases these forces are such that they want to bind oil rather than water to the rock: in that case the system is called oil wet, and the roles of water and oil in our story are reversed). Water-wet rocks will spontaneously imbibe water (Fig. 4), whereas their oil saturation can only be increased by forcing the water in, applying pressure (the chemical forces of the mineral molecules repel the oil molecules). Oil wet rocks will spontaneousluy imbibe oil, whereas neutral wet rock don’t have any preference and hence won’t imbibe anything spontaneously, and mixed wet rocks may imbibe both liquids simultaneously (some parts of the rock surface being water wet, some

oil wet): Fig. 4. Nowadays many people believe that actual reservoir rocks (in situ) are mixed wet rather than water wet.

Another way of defining wettability is via the concept of contact angle: Fig. 5. This definition has the advantage that it can be used quantitatively.

Capillary pressure The chemical forces alluded to in the previous sections are called capillary forces. Small pores have relatively more grain surface per volume of pore than large pores. Therefore, capillary forces are larger the smaller the pore size (there is an inverse proportionality). This means that it is easier to force the non-wetting fluid (oil) into large pores, and it becomes increasingly more difficult to force oil into the rock as more and more of the larger pores have already been filled, so that the oil has to be forced into smaller and smaller pores (actually the oil has to be forced into the pore throats, but the difference between pore throats and pores will be neglected for this simplified discussion). One needs a finite pressure, called the capillary entry pressure, to enter the largest pore. Only if this pore were very large, would the entry pressure be close to zero. (Because of this relation between capillary pressure and pore size, there is normally a good relation between capillary pressure and permeability as the latter is also strongly related to pore (throat) size). On the other hand, only at very high pressures would we be able to completely fill the rock with oil. At the finite pressure reached in practice, always some water will remain (the irreducible water saturation).

Saturation / height functions In the previous section we have viewed the capillary pressure curve from the point of view of the injected fluid (the oil). Now let's reverse the roles and view it from the point of view of the wetting fluid (the water). The water is attracted to the rock surface by chemical forces, and can therefore be sucked in spontaneously. In the reservoir, therefore, water can thus rise above the OWC (actually the Free Water Level [FWL], as the OWC can be above the FWL because of the capillary entry pressure; see below) because it is sucked up into the oil zone against the force of gravity which tries to pull the heavier water down (buoyancy force): Fig. 6 (the reverse happens in oil wet rock: Fig. 7). Application of the force balance equation for a droplet (Fig. 3) now constrained to a tube of a certain radius, leads to the capillary pressure equation given in Fig. 8. Porous rock consists of pores of various sizes. Mathematically it is convenient to treat these pores as tubes (“capillary tube model”). This model then gives a relationship between height above free water level (related to pressure [pressure gradient]: see right hand side of Fig. 9) and the capillary rise in tubes (pores) of different sizes (left hand side of Fig. 9). For a porous rock consisting of many different pore sizes this will lead to a capillary pressure curve as shown in Fig. 10. The relationship between capillary pressure and height above free water level can be obtained by equating the capillary pressure equation (Fig. 8) to the buoyancy equation: Fig. 11. This equation says that water can rise to a certain height in a capillary tube (pore) of a certain size, against buyoancy (trying to pull it down, because water is heavier than oil), and the rise will be higher for smaller pores. hence, the shape of the capillary pressure curve is heavily influenced by the pore size distribution (Figs. 12, 13 and 15).

Some terminology related to capillary pressure curves is described in Fig. 14. Fig. 15 shows that in general good rock (see also Fig. 1), i.e. high permeability rock, has low residual water saturation and low capillary entry pressure, and poor rock (low permeability) has high residual water saturation and high capillary entry pressure. In general there is a very good relationship between the position of different capillary pressure curves of the same field in such a plot and permeability. Often though, this correlation is made with porosity (because permeability can’t be obtained from logs): this correlation is normally less good though. The process of oil accumulation in the reservoir, during geological history, will have happened long ago, and thus a transition zone will have formed leading from the FWL/OWC via zones with steadily decreasing water saturation to a zone where the water saturation is minimal (irreducible water): Fig. 16. The water saturation as a function of height is just the capillary pressure function, where the buoyancy force plays the role of pressure trying to force the oil in against the water. At a large height above the OWC the buoyancy force is so high that only irreducible water can remain. At lower and lower heights, more and more water can remain "glued" to the rock surface due to the capillary (chemical binding) force, against the buyoancy (gravity) force. Hence, the higher above the FWL, the more difficult it is for the pore system to hold water by capillary forces against the gravitational force (wanting to pull it back to the FWL): at increasing height only fewer and fewer (smaller and smaller) pores will be able to do that.

Drainage and imbibition Petrophysicists normally use the drainage curve as this describes the static fluid saturation before the field starts to be produced. Reservoir engineers are more interested in the behaviour following water flooding, and hence use the so called imbibition curve: Fig. 17. From this curve the residual oil saturation can be derived (Fig. 18).

Laboratory measurement equipment Interfacial tension can be measured under simulated in situ conditions by using the pendant drop equipment. For measurement of an oil/water system, the cell of this equipment is filled with the reservoir brine at reservoir pressure and temperature. Then a drop or reservoir crude is slowly pushed through a needle which inserts the cell from the bottom. The shape of the droplet hanging (up) from the needle tip (surrounded by the brine in the cell) is photographed. From this shape the interfacial tension can be calculated.

Wettability can best be measured from a series of drainage imbibition capillary pressure cycles: Fig. 19. From such a measurement the so called Amott and USBM indices can be derived (Figs. 19 and 20). In general, core plugs are made water wet by applying certain cleaning procedures. Therefore, if the reservoir is suspected not to be water-wet, measurements have to be carried out under “aged” conditions, i.e. the in situ wettability has to be restored in the laboratory equipment by using crude oil, reservoir brine and high pressure and temperature, and the samples have to be aged under such conditions for a sufficiently long period of time (normally several weeks). Because this process is time-consuming and expensive it is not done on a routine basis.

A drainage capillary pressure curve (Fig. 21) can be measured using one of the following methods: - Mercury injection (Fig. 22), also available for measurement under confining

stress. - Centrifuge (Fig. 23). - Equilibrium: same measurement equipment as used to measure Resistivity

Index curves. The advantages & disadvantages of these methods are summarised in Fig. 24.

Relating laboratory measured capillary pressure curves to field saturations From wireline formation (RFT / MDT) tests the free water level (FWL) can be determined as the intersection of the water and the oil pressure gradients. Knowing the capillary pressure curve from core measurements then enables the determination of the oil saturation as a function of the height above FWL, independent of log measurements. In this way, hydrocarbon saturations can be determined from core measurements as an independent check (or even replacement) of log derived saturations. Log resistivity measurements give the oil/water contact (OWC), which may be a bit above the FWL because of the capillary entry pressure effect. Hence, by measuring a capillary pressure curve in the laboratory and making a standard conversion from the pressure scale and fluids used in the lab to the height scale and fluid conditions in the reservoir one can predict the saturation/height curve in the field. In good permeability rock the transition zone is very flat, such that there is a sharp transition from the water layer to the oil layer (Fig. 1). In such cases the OWC is generally very close to the FWL. However, in poor permeability rock one can have a transition zone of hundreds of feet, and an OWC well above the FWL. The conversion that has to be made to correct for the conditions and fluids used in the laboratory experiment are given in Figs. 25 and 26.

Corrections to be applied Laboratory capillary pressure curves have to be corrected for the following effects (see also Fig. 27):

- Closure (the effect of surface irregularities of the core plug, giving a non-sharp capillary entry zone).

- Micro-porosity, leading to “double curves”: the micro-porosity system may give rise to a new capillary entry at a lower water saturation.

- Confining stress: this can often be done by correcting the capillary pressure by the square root of the ratio of non-stressed over stressed porosity, and the non-wetting saturation by the ratio of stressed over non-stressed porosity.

- Clay bound water: this can often be done using the Juhasz approach. Using the Hill-Shirley-Klein equation, the capillary pressure is corrected by the square root of the ratio of total over effective porosity, and the non-wetting saturation is corrected with the ratio of effective over total porosity.

- Wettability and interfacial tensions: see Figs. 25 and 26.

Curve fitting and averaging Various mathematical equations are available to fit a laboratory measured capillary pressure curve, e.g. various entry-height relations, the exponential, hyperbolic, lambda, polynomial, sigmoidal, Thomeer and trigonometric tangent fit curves. Of these the lambda-fit normally works best. It fits the wetting saturation Sw to the capillary pressure Pc using three fit constants, a, b and λ, according to:

Sw = a.Pc-λ + b

If trying to construct a volumetric average of various flow units, the matrix method can be applied, in which an average is made of capillary pressure curves attached to certain porosity classes, based on the porosity log.

Possible sources of difference between capillary and log derived saturations Many times the capillary pressure derived saturations will deviate from the ones derived from the resistivity log. Various factors may cause these differences, e.g.:

Capillary pressure curve (core) Resistivity log Drilling: disturbance Choose proper tool Depth matching / plug selection Tool calibration; Tool measurements Sample cleaning Log QC; Environmental corrections: Rt Laboratory measurement of Pc Rw determination; m, n, Qv Corrections (clay, stress, ..); Curve fitting

Resistivity model (Waxman-Smits, ..)

Pc --> saturation/height conversion Sw versus depth Porosity classes (“matrix method”) Saturation / volumetrics

Causes of errors in capillary pressure curves

- core plugs: disturbance, biased sampling, size, shape - cleaning: wettability & clays - equipment: (e.g. centrifuge: force lines, wait time for equilibrium, footbath) - translation from laboratory to field conditions: * stress, temperature, fluid pressure * clay bound water * interfacial tension, contact angle, densities * closure, unit conversions, extrapolation - curve fitting, averaging (w.r.t. porosity)

Causes of errors in water saturation determination from resistivity logs - resistivity tool: type (IL, LL, ..), calibration / QC - thin beds, invasion, Groningen effect - values of m, n, Qv (good samples?, cleaning, differences between laboratory / field) - value of Rw

- resistivity interpretation model (Waxman-Smits, Dual Water model, Indonesia eq....): influence of lithology, temp., etc.

Other causes for discrepancies

- different conditions: * field may have been partly depleted * drainage or imbibition case ?

- difference in depth of investigation (size/scale effects, lateral variability) - depth matching core/log

depth

water saturation0 1.0

OWC from logs

Fig. 1 Capillary pressure: determines transition zonefrom water leg to HC leg

Dependent on rock type (permeability)

poor rock

good rock

Fig. 2 Surface Tension (1)

P1

P2

Fig. 3 Surface Tension (2)

σσ σ

P1

rσπ rF 2↓=

PrF Δ↑= 2π

ΔP r= 2σ P: dyne/ cm dyne/ cm

r: cm

2

σ:

togetherdrop thehold to tendingforce total:Fdrop shear the to tendingforce total:F

↓

↑

Fig. 4 Wettability concepts

Water-wet Oil-wet

Neutral-wet Mixed-wet

Oil

Water

Fig. 5 What is wettability ?

Rock surfaceRock surface

Water-wet:contact angle

0 - 70 deg.

Oil-wet:contact angle110 - 180 deg.

oilwater water

Fig. 6 Water Wet

θ waterair

glass plate

oil

water

water oil

free waterlevel

ΔP

pressure

height

Fig. 7 Oil Wet

oil

water oil

free waterlevel

ΔPpressure

height

θair

mercury

glass plate

water

Fig. 8 Capillary pressure

θPw

Pnw

rc

r1

Pnw - Pw = 2σ/r1

rc = r1 cos θ

r1 = rc / cos θ

Pnw - Pw = 2σ cos θ / rc

Fig. 9 Capillary Pressure

water

air

free waterlevel

pressure

height

h gΔρ

A

A1

B

B1

C

C1 C1

B1

A1

Pnw-Pw

air

water

Fig. 10 PORE SYSTEMS AND CAPILLARY PRESSURE CHARACTERISTICS

5

321Pore Systems

Pc

0 Sw 10

Measured Curve

5

3

2

5

33

3

21

Core Plug

Fig. 11 Capillary Tube Model

P ghb = ΔρP ghb = ΔρP ghb = ΔρPrc

R R=2σ θcos

Prc

R R=2σ θcosP

rcR R=

2σ θcos

Capillary Force Buoyancy Force

but... pore interconnections not modelledhysteresis not modelled (imbibition vs drainage)assumes completely water or oil wet

Fig. 12 Shape of Capillary Curve through the Transition Zone is Strongly Affected by the Distribution of Grain Size

Fig. 13 Capillary Pressure tube model

free waterlevel

Water saturation

heightoil

water

Fig. 14 Capillary Pressure and Fluid Distribution

Swc

region ofirreducible

water saturation

transition zone

water saturation0 100

Pcorh

Capillary entry pressure

Fig. 15 ROCK TYPES AND CAPILLARY PRESSURE CHARACTERISTICS

PcReservoir

5

321Rock Types

5

3

2

1

0 Sw 10

Average Reservoir

5

33

3

21

Height

Fig. 16 SATURATION and PRESSURE DEVELOPMENT DURING HYDROCARBON ACCUMULATION (DRAINAGE)

Pc

0

Phase Pressure

Height Above Free Water Level

FWL 0

Pc1

Pc1

Sw1

Sw1

0 Sw 1

5

33

3

21

Pc

or

Height

0 Sw 1

0 FWL

OWC

Swir 1-Sor

EntryPressure

Fig. 17 CAPILLARY PRESSURE CURVE TYPES AND COMPONENTS

Drainage Curve

Imbibition Curve

The drainage process is the displacement of the wetting phase by the non-wetting phase.

RESERVOIR CHARGE

The imbibition process is the displacement of the non-wetting phase by the wetting phase.

RESERVOIR DEPLETION

Fig. 18 Residual Oil Saturation

the oil is immobile At end of waterflood

Residualor

“Capillary Trapped”Oil

Sand Grains

Oil

Oil and connate water

Increased water saturation

Water

time

Fig. 19 Wettability measurement

Irreduciblewatersaturation

ROS

p q

r sA1

A2

1

2 3

45

Capillarypressure(psi)

- 10

0

10

0 100Water saturation (%)

Curve:1. Initial oil drive2. Free imbibition of brine3. Brine drive4. Free imbibition of oil5. Oil drive

Amott index:water: pq / psoil: rs / ps

USBM index:log (A1 / A2)

Fig. 20 Measuring Wettabilty

Water Wet Neutral Wet Oil Wet

Contact Angle 0-70° 70-110° 110-180°

AMOTT Indexwater ratio + 0 0oil ratio 0 0 +

USBM Index near 1 near 0 near -1

Fig. 21 Capillary Pressure Curves

entry pressure

extrapolatedentry pressure

0 25 50 75 100

20

15

10

5

0

irreducible watersaturation

Water Saturation (% pv)

Fig. 22 Mercury injection equipment

Sample

MercuryPump

Displacement reading

Pressuregauge

rotoraxis

rotor

sample

rotation

waterproduced incollection tube

Centrifugal force plays role of gravitational force

Increasing rotation speed ---> increasing force ----> increasing Pc

Gives increasing water production ---> Sw

Fig. 23 Centrifugemeasurement

Fig. 24 Measuring Capillary Pressure

Equilibrium Air/Hg CentrifugeDuration 5 weeks 1day 3 days/runMax Height (m gas/oil) 30/60 7000/14500 80/160At stress? Yes Yes NoOn cuttings? No Yes NoSample damaged? No Yes Weak onlyUnconsolidated Yes Yes Yes?Equilibrium reached? Yes Yes NearlyClay correction No Yes NorequiredCosts Expensive Cheap MediumAdditional Imbibition Imbibition ImbibitionInformation RI Wettability

Capillary curves can be converted from lab conditions to the reservoir as follows:

θ = 0° except Air/Hg where θ = 140°

Lab surface tensions have been measured e.g.mercury/air σ = 480 dynes/cmkerosene/brine σ = 50 dynes/cm

Reservoir values are ill-defined - some data is available but a range should be used

Fig. 25 Laboratory/Reservoir Conversion

P Pc RR R

L Lc L, ,

coscos

= σ θσ θ

Fig. 26 CONVERSION OF LABORATORY MEASURED CAPILLARY PRESSURE CURVES TO HEIGHT ABOVE FREE

WATER LEVEL

Pc

00 Swlog 1

H

From the capillary tube model

85.0 0.1)/( 26cos

)/( 367cos

433.0)(coscos

coscos)(

coscos

====

−=

=−=

=

=

oilwat

resres

lablab

oilwat

lab

lablab

resres

lablablab

resresoilwatres

lablablab

resresres

wateroilmercuryair

PcxH

PcgHPc

PcPc

ρρθσθσ

ρρθσθσ

θσθσρρ

θσθσ

θσr

cos2Pc

Assumptions

H (ft) = 1.091 x Pclab(psi)

Conversion factor is established by correlation with log data 0 Swcap 1

Fig. 27 Stressed cap. curves

Mercury / air Gas / water

Nostress

Stress

Standard measurement

Standardmeasurement:centrifuge

Specialequipment

To be inferred from:- effect of fluid

(no stress), and- effect of stress

stress effect

fluid effect

5. Porosity & Lithology

Summary

In this chapter the determination of porosity and lithology from logs is discussed in somewhat greater detail than done in Chapter 2. Additional tools (e.g. SP and sonic) are covered, and the methods are outlined in more detail. The first choice porosity tool is the density, possibly combined (in carbonates) with the neutron. The neutron or sonic tools should only be used if there is no other choice. Porosity determination is rather different for different lithologies, therefore the two are treated together. First one has to discriminate between clastics and carbonates. This can in most cases be done (apart from using mudlog, core, sidewall samples or regional information) by using the density/neutron combination in conjunction with the gamma-ray (to distinguish between dolomite and shale, who have similar density/neutron responses).

Clastics In clastics, it is important to distinguish between clean sands, shaly sands and

shales. In most cases this can be done using the above mentioned density/neutron combination in conjunction with the gamma-ray. Special techniques also exist to distinguish laminated from dispersed shaly sands, again using the density/neutron crossplot ("Thomas-Stieber" crossplot). Laminated shaly sands can often be described better by using high resolution borehole imaging tools, such as Schlumberger's FMI and Western-Atlas' STAR tools. As the neutron response in clastics is very heavily influenced by shale, it is best to determine porosity straight from the density only.

Carbonates In carbonates, it is important to distinguish between limestones, dolomitic

limestones and dolomites. This can in most cases be done very well using the density/neutron crossplot technique. As carbonates are non-shaly the density/neutron combination can also be used to determine the porosity. Statistical analysis software can also be used to determine porosity and lithology as an alternative to the density/neutron technique. In this software it is possible to take more logs into account.

Most of the contents of this session are covered in much more detail in standard text books: see references. References - Schlumberger, Log Interpretation Principles/Applications, 1989, and

Schlumberger, Log Interpretation Charts, 1991 - Western Atlas, Introduction to Wireline Log Analysis, 1995,

and Western Atlas, Log Interpretation Charts, - Richard M. Bateman, Open-hole log analysis and formation evaluation, D. Reidel,

1985 - John T. Dewan, Essentials of modern open-hole log interpretation, PennWell Books,

1983 - R. Desbrandes, Encyclopedia of well logging, Editions Technip, 1985

- Darwin V. Ellis, Well logging for earth scientists, Elsevier, 1987 - M. Rider, The geological interpretation of well logs, Whittles Publishing, 1996 (2nd

ed.) - Zaki Bassiouni, Theory, measurement and interpretation of well logs, SPE, 1994 - Donald P. Helander, Fundamentals of formation evaluation, OGCI publications, 1983

Gamma-ray

Principle Some elements in nature emit radiation (Gamma Rays). Examples of such elements common in the earth's crust are potassium (K), thorium (Th) and uranium (U). Most reservoir rocks (e.g. Sandstone, Limestone, Dolomite) contain none or only small amounts of these elements and therefore have a low GR radiation level. Some other rock types (e.g. shales) have a large amount of K- and Th- atoms. The resulting high GR radiation levels contrast with the low GR levels of the adjacent reservoir formations.

Tools The conventional Gamma Ray Tool consists of a single GR detector, which records the natural gamma rays against the depth. The total GR level is recorded and plotted in API units on a scale of (normally) 0 - 150 API. Sometimes sands themselves contain radio-active minerals, like Thorium or Uranium. In case of such “radio-active sands” the Natural Gamma-ray Spectroscopy Tool (NGT - Schlumberger) or Spectral Log (Baker Atlas) can be used. It analyses the gamma-ray energy and measures the intensity in different energy windows. Because Potassium, Thorium and Uranium gamma-rays have different energies, in this way (in addition to the conventional total gamma-ray signal) three separate logs are obtained: a Thorium log, a Uranium log and a Potassium log. . This tool can recognise shale layers by their high "potassium and thorium GR". Some non-reservoir rocks contain little or no radioactive material. Additional information is required to discriminate between these and reservoir rocks.

Depth of Investigation: 0.5 - 1.0 m Vertical Resolution: +/- 1.0 m

Evaluation Objective of the Gamma-Ray tool - Discriminate between reservoir and non-reservoir. (Net/Gross) - Estimate shaliness of reservoir rock.

Additional Uses - Correlating reservoirs between wells, based on their GR signature. - Depth matching subsequent logging runs with the first logging run in the well.

Evaluation Technique The interval of interest should consist of reservoir rock (lithology determined from cutting descriptions) and shale layers only. In that case, in general (i.e. except in case of “radio-active sands), low gamma-ray is indicative for sand, high gamma-ray is indicative for shale (Figs. 1 & 2). Hence:

- Within this interval, the GR level of thick shale beds is read. - This reading is assumed to represent 100% shale. - A straight line through these points is called the shale-line. - Similarly a sand-line is constructed by reading the average GR level of thick clean sands (= sands with the lowest GR level). - A near vertical line in the middle between the shale- and the sand-line (called the cut-off line) is often constructed for an initial quicklook evaluation. - All intervals where the GR log is on the left of this cut-off line are assumed to be reservoir. - The level of GR within a reservoir interval is a measure of its shaliness.

Remarks

- Beware of KCL mud, as this may give high GR readings even over sand intervals.

- The cut-off thechnique is best applied in Quicklook evaluations only. In computerised (e.g. LOGIC) evaluations normally cut-offs are only applied in the final (reporting) stage, to prevent that one ignores certain shalier but still good reservoir sections.

Spontaneous Potential (SP)

In the past the Spontaneous Potential or SP curve was often used to discriminate sands and shales. The method relies on the potential created by the interplay of three mechanisms: electrokinetic potential, membrane potential and liquid-junction potential (see text books). The resulting curve is best interpretable if the water-based mud is less saline than the formation water (the method does not work in non-saline mud though). As this is not often the case, the gamma-ray is nowadays used much more often for sand/shale discrimination than the SP. In principle the formation water resistivity Rw can be obtained from the SP response. However, the accuracy of such determinations are rather questionable. In case the SP is used for Rw determination it is in general better to rely on local correlations. Note that the SP can be useful in “wild-cat” exploration where the interpreter may have very little knowledge of Rw. Even if the SP is not used, the curve (if available) should be provided (free of charge) by the Contractor, both on print and tape.

Density log

Principle A strong gamma ray (Cesium) source bombards the rock with medium energy level gamma rays. These gamma rays collide with electrons in the formation. In the process gamma rays are attenuated (Compton scattering). The count rate of these scattered gamma rays at a fixed distance from the source is inversely related to the electron density of the formation. From the electron density the bulk density can be calculated. Reservoir rock consists of rock matrix (e.g. quartz, calcite, dolomite) and pore fluid (e.g. water, oil, gas). The bulk density (ρb) of a reservoir rock is the weighted

average density of the pore fluid(s) present (ρfl) and its rock matrix (ρma). All densities ρ are in g/cc.

ρb = φ ρfl + (1-φ) ρma The matrix density equals 2.65 for quartz, 2.71 for limestone and 2.87 for dolomite. The fluid density equals 1.0 for fresh water, and 1.13 for salt saturated water. The density tool has a limited depth of investigation (see below), and therefore, normally, measures entirely in the invaded zone. Because of that, for mudfiltrate invaded oil bearing formations, an apparent fluid density of about 0.92 can be taken, and for mudfiltrate invaded gas bearing formations, an apparent fluid density of about 0.74 can be taken (or the rules of thumb given during Day 1 can be applied).

The Tool The source and two detectors are mounted in a pad, which is pressed against the bore hole wall. From the far detector count rates the tool computes and plots the bulk density ρb on a scale of 1.95 - 2.95 g/cm3. The near detector count rate is used to automatically correct the measurement for mud cake and the effect of small wash outs (using the so called “spine and rib” method: see Schlumberger’s Principles book). The applied correction (Δρ), plotted along side the ρb curve, can be utilised as a quality indicator. If this correction across an interval exceeds + 0.05 g/cm3 the quality of the main log over that interval is doubtful. The correction curve, Δρ, can be used as a quality indicator. Note that the correction has already been applied by the contractors, and therefore should not be applied again to the actual density curve by the user.

Depth of Investigation: 0.15 m Vertical Resolution: 0.6 - 1.0 m

The current tools measure both density and photo-electric effect Pe (see below). New tools (Schlumberger) emerged which have 3 detectors and where the impact of mud-cake and washouts is solved through an inversion process (not requiring the “spine and rib” method anymore).

The Photo-electric effect The current density tool (LDT,ZDEN) measures the total gamma-ray spectrum (Fig. 4). The high gamma-ray energies arise from Compton scattering and are indicative for density. The low energy gamma-rays arise (partly) from the photo-electric effect. Hence, from the spectrum both density and photo-electric effect can be calculated. The latter, called Pe is claimed to be a good lithology indicator (sometimes a quantity U is used, which is Pe times density). However the Pe is very heavily influenced by barytes additives to the mud which puts a limit to its usage.

Evaluation Objective of the density tool Calculate the porosity (φ) in layers of known lithology. The density tool is the first choice porosity log.

Additional Uses - Evaluate lithologies of formations in combination with the Neutron tool (see below).

- Check consistency of the lithologies as seen by the mudlog and the GR.

Evaluation Technique The density tool measures bulk density of the formation. To calculate fractional porosities the previous expression can be rearranged as follows:

φ = (ρma - ρb) / (ρma - ρfl) (where ρb is read from the log).

The Density tool has a very shallow depth of investigation. It measures the ρb in the invaded zone only. All formation water and most of the hydrocarbons originally present in this zone are replaced by the mud filtrate. For a quick look interpretation one can therefore use the parameters mentioned above (see “Principle).

Neutron log

Principle A neutron source bombards the formation with high energy Neutrons. Most collisions of the neutrons with heavy atoms of the formation are near elastic. As a result hardly any energy is lost. A collision with a hydrogen atom (H) lowers the speed (energy level) of the neutron significantly, as both have the same mass. The distance over which the neutrons travel before they reach a lower (thermal) energy level, is therefore related to the amount of hydrogen atoms present in the formation.

Tools The conventional tool is called CN or CNL: Compensated Neutron Log. A high energy neutron source and two detectors are mounted in a tool, which is pressed against the bore hole wall. The tool looks rather similar to a density tool, but it has neutron source and detectors rather than gamma-ray ones, and it is run on a bowspring (pressing the tool against the borehall wall). The detectors only count returning neutrons which have a thermal energy level. From the ratio of thermal neutrons detected by the far and the near detector, the amount of hydrogen (H) atoms in the formation is empirically determined. The tool assumes all H atoms to be present in the porespace (water or hydrocarbons). The tool is calibrated to read the true porosity in water filled limestone. These limestone-porosities are computed and plotted against depth in porosity units (p.u.). The matrix type has a small influence on the Neutron response. Across other lithologies the readings must therefore be corrected using an empirically derived chart.

Depth of Investigation: 0.15 - 0.20 m Vertical Resolution: 0.60 - 1.00 m

A more recent development is Schlumberger's Array Porosity Sonde (APS), which is part of their Integrated Porosity Logging Tool (IPLT). The APS uses an accelerator neutron source (like the one in the Pulsed Neutron Logging: ref. chapter on Cased Hole Logging) in stead of the chemical source in the CNL.

Anomalies In gas bearing formations the neutron porosity recorded is too low, because of the low density of H atoms in the gas phase. It is not possible to determine porosities in gas bearing formations based on the Neutron log alone. Shales contain clay-bound water (water which is chemically attached to the clay particles). The Neutron tool interprets this water as porosity, where in reality no effective porosity is present. Hence, the neutron porosity in shaly sands is too high.

Evaluation Objective Calculate the porosity in layers of known lithology.

Additional Uses - Evaluate lithologies of formations in combination with the Density tool (see Density/Neutron X-plot). - Detection of gas bearing reservoir in clean formations. - Check consistency of the lithologies as seen by the mudlog, GR and Density.

Evaluation Technique - In general the density of H atoms in water is similar to the H-density in oil.

For a quick look porosity evaluation one can therefore disregard the pore fluid type (except in case of gas).

- Across water bearing limestone the log gives the true porosity. - Across water- and oil- bearing Sandstones or Dolomites, the log has to be

corrected for lithology using a chart: see Density / Neutron combination below.

Density / Neutron combination

Evaluation Objective - Evaluate lithologies of formations. - Detection of gas bearing reservoir.

Principle The Density and the Neutron tool both determine the porosity of a reservoir, but do this by measuring different quantities: - The Density tool measures the bulk density. - The Neutron measures the hydrogen concentration (hydrogen index). For this reason, both tools react differently to certain pore fluids and lithologies (Fig. 5). It is standard practice to plot both logs in one track, using a scale such that both logs overlay in water bearing limestone (Fig. 6). Using these scales, the logs will separate uniquely in other lithologies or pore fluids. For example:

- In gas bearing reservoirs the recorded neutron porosity is lower and the bulk density is reduced, compared with the responses in a similar water/oil bearing formation. These effects can be significant (depending on the gas saturation in the invaded zone). The resulting (large) separation with Neutron to the right and Density to the left is called gas separation.

- Shales have an inverted effect (shale separation). Due to the clay-bound water, which is chemically attached to the clay particles, in shaly sandstones the neutron tool will record higher porosity than indicated by the density. Hence in that case we will get: Neutron to the left and density to the right

Hence, in gas-bearing sandstones and in shaly (non gas-bearing) sandstones the density and neutron separations are opposite (Fig. 6).

Density/Neutron X-plot A Density/Neutron X-plot is available, with an overlay of the points where common lithologies plot. For reservoir rocks lithology lines are drawn, which indicate the influence of changing porosity (Fig. 5).

Evaluation Technique (works best for carbonates and clean sandstone) - Read off the Density- and Neutron- responses across the layer of interest and plot the results in the X-plot. - Cross check with the mudlog, GR and Caliper whether the indicated lithology is consistent. - If the lithology is known one can read of the porosity from the porosity scale on the relevant lithology line. - Salt and Anhydrite have zero porosities.

Mixture of lithologies (for carbonates only !) If the plotted point falls in between two lithology lines, cross check with the mudlog whether a combination of lithologies were described. By constructing a line through the plotted point and the points of equal porosity on the two relevant lithology lines, one can estimate the porosity.

Gas effect Gas bearing reservoir will plot away from the relevant lithology line towards the upper left corner in Fig. 5/6. To estimate the porosity in these intervals, draw a line through the plotted point, parallel to the Approximate Gas Correction arrow. At the point of intersection of this line with the relevant lithology line, the porosity can be read off.

Shale effect If a reservoir is shaly, the plotted points will be displaced towards a shale point, which may be defined by the density and neutron values in adjacent shale beds. Normally this point will be in the lower right corner of Fig. 5. Cross-check with the gamma ray and the mudlog to recognise the main lithology. Shaly and gas bearing sandstones may plot very close to the clean sandstone line, because the gas-effect and the shale effect pull the points in opposite directions. Therefore, this crossplot most accurately determines lithology in carbonates or non-shaly sandstones.

Thomas-Stieber crossplot Dispersed, structural and laminated clay distributions (Fig. 7) can be recognised from the Density / Neutron crossplot using the Thomas-Stieber technique (Fig. 8): Dispersed shaly sandstones plot in the lower left triangle, structural clay plots in the upper right triangle, and laminated shaly sands plot on the line connecting the clean sand point and the shale point.

A remark about porosity Theoretical considerations show that porosity is independent of grain size. Porosity does depend on: - grain shape, packing and sorting - overburden stress level, cementation and clay content

In clastic rocks one has to distinguish between total and effective porosity. The latter is total porosity excluding clay bound water: see Fig. 9 (isolated porosity is very rare in clastic rock and can be ignored). In carbonates many different pore systems can exist, each with their own influence on petrophysical parameters (see e.g. Fig. 10).

Sonic

Principle The sonic tool measures the “time” it takes for sound pulses to travel through the formation (Δtlog). The results (called “travel time”) are displayed on a log in µs/m (or μs/ft): hence, actually an inverse velocity is measured rather than a “time”. This measurement of formation travel time (μs/m) can be translated into a seismic velocity (m/s) of the formation (velocity = 1/travel time): again, note that “travel time” is used here for a quantity in µs/m. The main use of the sonic is in seismic applications, calibration and generation of synthetics. Also, the sonic measurement is an essential parameter in the time to depth conversion of seismic data. The travel time can also be used to estimate formation porosity. The Wyllie time average equation assumes the formation travel time to be a linear combination of the travel times of matrix (Δtma) and pore fluid (Δtfl):

Δtlog = φ Δtfl + (1-φ) Δtma

Tools A transmitter (T) sends out a sound pulse. The difference in arrival time of the pulse at two receivers (R1 & R2), which are 60 cm apart, is measured. In the conventional Borehole Compensated sonic tool, a second transmitter and pair of receivers measure the same physical parameter in the opposite direction. By averaging the two measurements, the borehole effects on the travel time are eliminated. The first arrival at the receivers is the compressional (or “primary” P) wave which travelled through the formation. Other waves, like the slower formation shear (or “secondary” S) wave, and P-waves which travelled through the mud and the logging tool, will arrive later. Furthermore, waves may travel along the

borehole wall that are influenced by the interface between borehole fluid and borehole wall (so called “surface waves”, e.g. Rayleigh and Stoneley waves). Depth of Investigation: 0.25 m

Vertical Resolution: 0.50 m Conventional sonic tools (e.g. the BHC) only reliably measure the compressional wave transit time (first arrival). Modern tools like the Array (Long spaced) and Dipole sonic tools (with a dipole source as opposed to the monopole source of the standard sonic tools), e.g. Schlumberger’s DSI and Baker Atlas XMAC, measure the full wave train, hence also shear and Stonely waves (see also Fig. 13). Shear wave velocities can be used to calculate rock elasticity parameters which sometimes relate well to rock strength parameters. The Stonely wave may provide information on fractures and permeability.

Evaluation Objective - Calibration of seismic data. - Calculate the porosity (φ) in layers of known lithology. - Evaluation of secondary porosities in combination with Neutron and/or Density tools.

Evaluation Technique The Time Average (Wyllie) equation, represented by the straight lines on the interpretation chart (Figs. 11 & 12), can be rearranged as follows:

φ = (Δtlog - Δtma) / (Δtfl - Δtma) The sound wave travels along the borehole/formation interface and sees essentially only mud filtrate in the pores. The following parameters can therefore be used to calculate the porosity φ: Δtfl = 620 µs/m (189 μs/ft)

Δtma = 184 µs/m (54 μs/ft) for sandstone

= 161 µs/m (45 μs/ft) for limestone;

= 144 µs/m (41 μs/ft) for dolomite A second interpretation method is to use empirical correlation lines for sandstone, limestone and dolomite (curved lines), called the Raymer-Hunt equations: see Schlumberger chart book. These lines were obtained by comparing many sonic logs with porosities obtained from other sources (e.g. core measurements).

Undercompaction Unconsolidated sands may not adhere to the time average equation and have longer Δt's at a given porosity. In some cases this may be corrected for by using an empirical correction factor Bcp: see Fig. 12. The stronger the undercompaction effect, the higher Bcp should be chosen.

Effect of gas In gas bearing formations, small quantities of gas in the invaded zone may have a significant effect on the log. The gas will increase the Δt dramatically. Therefore, the sonic log may serve as a good (additional) indicator for gas: in gas zones the sonic is often spiky (irregular) and measures rather high Δt's.

Secondary Porosity The presence of secondary porosity (e.g. fractures, vugs) has the effect of reducing the amount of sonic energy that reaches the receiver. The travel time of the formation however is still determined by the properties of the homogeneous rock matrix. In other words, the sonic log responds to the primary (matrix) porosity only. A density tool measures the total porosity. A difference between the two measurements may indicate the presence of secondary porosity.

Anomalies The conventional sonic might be affected by several artefacts, e.g.: - Noise: a noise peak is picked as the first arrival, rather than the formation

signal. This leads to too low transit times (sharp peaks to the right). - Cycle skipping: the first arrival of the formation signal may be missed if the

signal is too weak to be detected. This leads to detection of a later (higher amplitude) cycle, hence to a too high transit time (blocky signal, to the left).

- In big holes or bad holes (in which the region around the borehole has been damaged / altered by the drilling process) the mud arrival may be faster than the formation arrival. This problem is solved by using array tools in which the transmitter / receiver spacing is much greater than in conventional tools.

Many of these effects have been overcome with modern (long spaced) tools and/or modern processing techniques.

Advanced applications using the Dipole Sonic tool The dipole sonic tool uses a dipole source (rather than the conventional monopole source) to allow measurement of shear waves also in slow formations (shear wave velocity lower than the sound velocity in the mud [“mud velocity”]). In those cases shear waves could not be measured with a monopole source, but dipole sources generate a good signal. The actual wave generated is called the flexural wave, and this is related in a straightforward way (which depends on frequency, due to dispersion) to the shear wave. Compressional, shear and Stoneley waves (Fig. 13) are measured and displayed in a “semblance plot” (Fig. 14). In this plot the travel time (“slowness” in μs/ft) measured by a certain receiver is plotted against the actual (real) time (in μs) measured on the same receiver. Such a plot has the advantage that anomalies and measurement errors are easily detectable.

As P, S and Stoneley acoustic velocities depend in a different way on porosity, lithology, confining stress, fluid type and saturation, lithology and the presence of fractures, the combination of these measurements can give much information (Figs. 15 & 16). One should be a bit cautious though: the Stoneley has been claimed to give information on fractures (reduced amplitude) and permeability, but good examples are rare. For instance, the Stoneley permeability measurement is hampered by the presence of mudcake.

SOME TYPICAL LOG VALUES IN FORMATION EVALUATION

GR Density Neutron Sonic (API) (g/cc) (pu) (μs/ft) Reservoir Rocks Mineral Quartz SiO2 0 2.65 -2 56

Mineral Calcite CaCO3 0 2.71 -1 49

Mineral Dolomite CaCO3MgCO3 0 2.85 1 44

Formations Sandstone 10 - 30 Limestone 5 - 10 Dolomite 10 - 20 Shale 80 - 140

Evaporites Halite NaCl 0 2.04 -3 67 Anhydrite CaSO4 0 2.98 -2 50

Sylvite KCl >500 1.86 -3

Others Coal (anthracite) 0 1.47 38 105 Pyrite FeS2 0 4.99 -3 39

Pore Fluids Fresh Water 1.00 Saline Water (200 g/l) 1.15

For typical log reponses to other materials and other logs, consult the logging company chart books

Copyright 2001 SIEP b.v.

1800

1805

1810

Dep

th (m

bdf)

0 100GR (API)

Sand / shale discrimination

Vshale

Figure 1 - GR Interpretation in a Sand-Shale Sequence

Copyright 2001 SIEP b.v.

Poro

sity

Gamma Ray

Sands

Shales

GRsand GRshale

Sand / shale discrimination

Vshale

Figure 2 - Sand/shale Discrimination

A low count at the LONG SPACING DETECTOR isindicative of a high density formation

e-

e-

e-

e-e-

e-e-

7"

16"

Long spacingdetector

Short spacingdetector

Source

Gamma ray

Formation density log

Figure 3 - Formation Density Log

Region of photoelectric effectand Compton scattering(ρ & Pe information

Region of Comptonscattering (ρ information only)

Low. U.

Med. U.

High. U.

CPS/KeV

s H E (KeV)

662

Gamma Ray detection in windows S and H

Figure 4 - The Gamma Ray Spectrum from the Density Tool

40302010

03.0

2.9

2.8

2.7

2.6

2.5

2.4

2.3

2.2

2.1

2.0

1.9

Neutron Porosity Index (pu)

Bul

k D

ensi

ty (g

/cc)

ρf = 1.0

15

20

25

35

40

Porosity

Sandstone

Limes

tone

Dolomite

Salt

Langbeinite

Polyhalite

Anhydrit

e

ApproximateGasCorrection

0

5

10

30

40

35

30

25

20

15

10

5

00

5

10

15

20

25

30

35

40

Figure 5 - Density/Neutron Crossplot

Salt

Anhydrite

Limestone

Limestone

Dolomite

Shale

Sandstone

Sandstone

Sandstone

Lithology Porosity Fluid

5 %

15 %

Water

Water

15 % Water

Water15 %

20 %

20 % Gas

Oil

Figure 6 - Density/Neutron Responses in Various Lithologies

Quartz

φ

Quartz

φ

Qtz

φ

Quartz

φ

Lam

Str

Dis

Cleansand

Laminarshale

Structuralshale

Dispersedshale

Figure 7 – Types of Shale Distribution

0. 0.1 0.2 0.3 0.4 0.5Neutron porosity (fraction)

0.5

0.4

0.3

0.2

0.1

0.

Densityporosity(fraction)

y = x line

Structural

Dispersed

Cleansandpoint

Shalepoint

VL

VD

Figure 8 - Thomas-Stieber Crossplot

Quartz Clay

Stru

ct. w

ater

Clayboundwater

Connectedpore volume

Isol

ated

por

e vo

lum

e

Φ DENSITY LOG

Φ NEUTRON LOG

Φ TOTAL

Φ EFFECTIVETotally dried core(Historical definition)

Wireline logs

Grain volume

Figure 9 - What is porosity (clastic environment)

Basic types of porosity in carbonate sediments

5 Intercrystalline

Figure 10a - What is porosity (carbonate environment)

Permeability as a function of carbonate porosity typeRef. J.W. Focke 1985

Figure 10b - What is porosity (carbonate environment)

100

50

0

50 100 150 200

Poro

sity

, % B

V

Δt, microsec/ft

Fluid point

ΔtflΔtlogΔtma

Matrix point

Δtlog - Δtmaφ =

Δtfl - Δtma

Δtlog = φ Δtfl + (1- φ) Δtma

Figure 11 - Time Average Equation

18,00

0

19,50

0

26,00

023

,000

21,00

0

1.61.5

1.4

1.3

1.21.1

BcpDolom

iteSan

dsto

ne

Limes

tone

Vma(ft/s)

30 40 50 60 70 80 90 100 110 120

Δt (μs / ft)

50

40

30

20

10

0

Poro

sity

(%)

Time averageField observation :Raymer - Hunt

Raymer-Hunt & Time Average

Figure 12 - Porosity Evaluation from the Sonic

Stoneley

First motion

Compressional

Shear

Figure 13 - Full Wave Train

Slowness

Arrival time

ST plane(Semblance contour plot)

STC dot logComp Shear

Slow

ness

Dep

th

z

Depth z

Figure 14 - Semblance Plot

Characteristic Compressionalslowness

Shearslowness

Stoneleyslowness

Fractures - + ***

Permeability + + ***

Lithology *** *** -

Porosity *** + -

Fluids *** *** -

*** required, + often useful, - not needed

Figure 15 - Use of Sonic Information

Y, σ K, μ ρ, vp2, vs

2

Shear modulus, μ Y2 ( 1 + σ)

μ ρ vs2

Bulk modulus, k Y3( 1 - 2σ)

K ρ ( vp2 – 4/3 vs

2 )

Poissons ratio, σ σ 3k - 2μ

2 ( 3k + μ )

( vp2 - 2vs

2 )

2( vp2 –vs

2)

vp2 Y ( 1 - σ)

ρ ( 1 + σ) ( 1 – 2σ)( k + 4 / 3μ )2 ( 3k + μ )

vp2

vs2 Y

2 (1 + σ) ρμρ

vs2

Figure 16 - Relationships between Seismic Velocities and Some Elastic Constants

Tool Overview – Sperry Sun Dir/incl/DR Collar Size Incl/dir &

Incl/dir/GR (collar)

Incl/dir(probe) Incl/dir/GR (probe)

Incl/dir/GR (Retrievable)

Incl/dir/GR High Temp

2 3/8” - - - - - 3 1/8” - Directional

While Drilling (DWD) (>3 3/8”)

Directional Gamma While drilling (DGWD)(>3 3/8”)

- Solar 175 (3 3/8”)

4 ¾” - DWD DGWD - Solar 175 6 ¾” Mud Pulse

Telemetry (MPT) & MPT + Dual GR (DGR)

DWD DGWD - Solar 175

8 ¼” MPT & MPT DGR DWD DGWD - Solar 175 9 ½” MPT & MPT DGR DWD DGWD - Solar 175 Operating Limits/Specs

140°C 10-8°/100ft (rot.) 3 BPS Max Negative Pulse (250hr Battery only) 50% of collar tools have ability to have DGR with DDS.

140°C 2 BPS Max 14-8°/100ft(rot) (Positive Pulse) Probe tools will have VSS (single axis vibration) in the future.

125°C 2 BPS Max 30-8°/100ft (Positive Pulse and uses DGR sub)

N/A 175°C (200°C survival) 2 BPS Max

* Electromagnetic telemetry dir/incl also available in 3 ½”, 4 ¾” and 6 ½” OD’s. 125°C & 200hr battery. * Azimuthal DGR also available from 4 ¾” to 9 ½”.

Resistivity and Geosteering Collar Size

GR/Res (Qualitive – collar)

GR/Resistivity (Quantative – collar)

GR/Resistivity (Quantative – probe)

Geosteering

3 1/8” - - - - 4 ¾” Slim

Electromagnetic Wave Resistance Phase-4 (Slim EWR ph-4)

- - -

6 ¾” EWR ph-4 - - Instrumented Mud Motor (IMM) (sizes unknown) At-Bit Inclination Sensor. (ABI)

7 ¾” - - - 8 ¼” EWR ph-4 - - ABI 9 ½” EWR ph-4, EWR ph-

4D - - -

Operating Limits /Specs

2Mhz 4 attenuation, 4 phase curves. Not-compensated. (Used with MPT or DWD systems, 4 ¾” uses special positive pulse system. )

- - -ABI communicates acoustically - 125°C.

Density and Neutron Collar Size Density

/Lithology (collar – not acoustically borehole standoff corrected)

Neutron Porosity (collar – not acoustically borehole standoff corrected)

Density /Lithology (collar – acoustically borehole standoff corrected)

Density/Neutron (collar – acoustically borehole standoff corrected)

3 1/8” - - - - 4 ¾” Stabilized Litho-Density

Sensor (SLD) Compensated Thermal Neutron Sensor (CTN)

- -

6 ¾” SLD Compensated Neutron Porosity Sensor (CNO) (Capture GR)

- -

7 ¾” - - - - 8 ¼” SLD ( 8”) CNO - - 9 ½” - - - - Operating Limits /Specs

Uses spine and rib correction up to 1” stand-off. Rotational ρ only with stand-off greater than 1”. No caliper. +/- 0.025g/cc Incorporates near and far receivers. Combined with MPT only. String must be rotated.

No caliper. +/- 0.5-1pu@20pu, 24” resolution. Combines with MPT only except CTN (which combines with Slim EWR ph-4). 6 ¾” and 8” tools being upgraded to CTN.

- -

* Acoustic caliper available for wellbore evaluation only – not for combination with Neutron/Density tools. Vibration, Dynamics and Pressures, Rotary Drilling Collar Size Vibration Drilling

Parameters Pressure Steerable Rotary

Drilling 3 1/8” - - Pressure While

drilling (PWD) – 3 3/8”

-

4 ¾” Drillstring Dynamics Sensor (DDS)

- PWD -

6 ¾” DDS - PWD - 7 ¾” - - - 8 ¼” DDS WOB/TOB PWD - 9 ½” DDS - PWD - Operating Limits/Specs

Tri-axis accelerometers (lateral, torsional and longitudinal) providing real-time peak and average loads. DDS is incorporated in DGR sub.

Downhole weight on bit and torque on bit. (New tool)

Annular and internal pressure. Compatible with DWD and MPT.

-

Sonic Collar Size Sonic (memory only) Sonic (memory/real time) 3 1/8” - - 4 ¾” Scout Bi-modal Acoustic Sonic Tool

(BAT) 6 ¾” Scout BAT 7 ¾” - - 8 ¼” Scout BAT 9 ½” - - Operating Limits/Specs Memory tool ex-Halliburton, not

being developed further. 4 recievers. Monoploe only 7-9 kHz 12” resolution.

Field testing. 150°C (165°C survival) 40-180μs/ft Memory 240hrs at 40s acqu. rate 7+7 receivers real time Δt comp. (Δt shear in memory.) Monopole 12-15kHz Dipole 7-9kHz 6” resolution.

New Technology Azimuthal propagation resistivity for geaosterring in all mud types. Commercial ? (field testing – no commitment yet) Super Slim 3 3/8” 175°C Hot Hole LWD. Prop Resistivity first. Commercial ? (field testing – no commitment yet) LWD NMR tool. Commercial 2000 Q? (field testing – no commitment yet) MWD Gyro. Commercial ? (field testing – no commitment yet) Rotary steerable system Commercial? (planned commercial release.) Gamma-at-bit GAB. Commercial ? (planned commercial release.)

MWD/FEWD Functionality Matrix Maximum

ROP Recorded

Maximum ROP Real-time (Rotating)

Maximum ROP Real-time (Sliding)

Memory Capacity

GR 225ft/hr 185ft/hr 185ft/hr 551Hrs GR/Res1 225ft/hr 97ft/hr 97ft/hr 248Hrs GR/Res1/Res2 225ft/hr 56ft/hr 56ft/hr 248Hrs GR/Res1/Res2/Res3/Res4 225ft/hr 35ft/hr 35ft/hr 248Hrs GR/Res1/Res2/Dens/Neu 128ft/hr 38ft/hr 38ft/hr 232Hrs GR/Res1/Res2/Res3/Res4/Dens/Neu

128ft/hr 27ft/hr 27ft/hr 232Hrs

GR/Res1/Res2/Dens/Neu/Son 128ft/hr RO RO 232Hrs GR/Res1/Res2/Res3/Res4/Dens/Son

128ft/hr RO RO 232Hrs

RO = Recorded only until BAT tool fully available. Nuclear tools give very poor data in sliding mode.

Tool Overview - BHI Dir/incl/DR Collar Size Incl/dir &

Incl/dir/GR (collar)

Incl/dir(probe) Incl/dir/GR (probe)

Incl/dir/GR (Retrievable)

Incl/dir/GR High Temp

3 1/8” - Navitrack (also 3 7/8”)

Navigamma (also 3 7/8”)

- -

4 ¾” - Navitrack Navigamma Navitrack/Navitrack

Navi185

6 ¾” Directional MWD and Directional-Gamma (GR)

Navitrack Navigamma Navitrack/Navitrack

Navi185

8 ¼” Directional MWD and Directional-Gamma (DG) (also in 7 ¾’)

Navitrack Navigamma - Navi185

9 ½” Directional MWD

Navitrack Navigamma - Navi185

Operating Limits

125°C 6 ¾” 24 KNm 8 ¼” 51KNm 9 ½” 99KNm 1.2BPS

150°C 3 1/8” 3.5KNm 3 7/8” 4.2KNm 4 ¾” 13.4KNm 6 ¾” 30.9KNm 8” 71KNm 9 ½” 119KNm 1.2BPS

150°C 3 1/8” 3.5KNm 3 7/8” 4.2KNm 4 ¾” 13.4KNm 6 ¾” 30.9KNm 8” 71KNm 9 ½” 119KNm 1.2BPS

150°C 4 ¾” 13.4KNm 6 ¾” 30.9KNm

185°C 4 ¾” 13.4KNm 6 ¾” 30.9KNm 8” 71KNm 9 ½” 119KNm

Resistivity and Geosteering Collar Size GR/Resistivity

(Qualative – collar)

GR/Resistivity (Quantative – collar)

GR/Resistivity (Quantative – probe)

Geosteering

3 1/8” - - Ultra slim MPR (Navitack)

-

4 ¾” - - Ultra slim MPR (Navitack)

-

6 ¾” - Multiple Propagation Resistivity (MPR)

- Navigator (motor+GR/res/dir/incl below motor)

7 ¾” Dual Propagation Res. (DPR)

- - -

8 ¼” DPR MPR - Navigator (8” not 8 ¼”) (motor+GR/res/dir/incl below motor)

9 ½” DPR - - Navigator (motor+GR/res/dir/incl below motor)

Operating Limits/Specs

125°C 6 ¾” 24 KNm 8 ¼” 51KNm 9 ½” 99KNm 2 MHz –2 depths Not-compensated

125°C 6 ¾” 24 KNm 8 ¼” 51KNm 9 ½” 99KNm 2 MHz & 400Khz – 8 depths Compensated

125°C (special equip for 150°C) 3 1/8” - ? 4 ¾” 13.4KNm 2 MHz & 400Khz – 8 depths Compensated

125°C (special equip for 150°C) 8” 51KNm 9 ½” 99KNm 2 MHz & 400Khz – 8 depths, 2 x GR (180° apart) Mach 1XL motor

(DPR and MPR also contain dir/incl depending upon definition used) Density and Neutron Collar Size Density

/Lithology (collar – not acoustically borehole standoff corrected)

Neutron Porosity (collar – not acoustically borehole standoff corrected)

Density /Lithology (collar - borehole standoff corrected)

Neutron Porosity (collar – borehole standoff corrected)

3 1/8” - - - - 4 ¾” - - Optimised

Rotational Density (ORD)

Caliper Corrected Neutron (CCN)

6 ¾” Modular Density/Lithology (MDL)

Modular Neutron Porosity (MNP)

- -

7 ¾” - - - - 8 ¼” MDL MNP - - 9 ½” - - - - Operating Limits/Specs

125°C - 6 ¾” 150°C - 8 ¼’ 6 ¾” 24 KNm 8 ¼” 51KNm Repeatability +/-0.025g/cc@27m/hr Resolution 18” ρ, 6” photo effect. Tool needs to be rotated.

125°C - 6 ¾” 150°C - 8 ¼’ 6 ¾” 24 KNm 8 ¼” 51KNm Repeatability +/-0.6 pu @ 20 pu Resolution 24” for pu, Tool needs to be rotated.

No specs available – due in service Q3 1999 Uses 3 acoustic transducers to measure stand-off. Best recording selected. Dip/density available 2000.

No specs available – due in service Q3 1999 Uses 3 acoustic transducers to measure stand-off and correct porosity recordings.

Vibration, Dynamics and Pressures, Rotary Drilling Collar Size Vibration Dynamics/Pressure Steerable Rotary

Drilling 3 1/8” - - - 4 ¾” VSS (only in

Navi185) Annular Pressure Sub (AP)

-

6 ¾” Vibration Stick-Slip (VSS)

Modular Dynamics Pressure (MDP)

Autotrak Rotary Closed Loop System, Autotrack Lite

7 ¾” VSS - - 8 ¼” VSS MDP Autotrak,

AutotrackLite 9 ½” VSS - - Operating Limits/Specs

Torsional, lateral and axial vibration.

125°C WOB, torque-on-bit and annular/internal pressure

Rotary drilling incl motor, dir/incl/GR/VSS/res (MPR) 150°C

VSS has been included in all BHI collar based systems and will be incorporated in all probe based systems in the future. AutotrackLite is the same as Autotrack but without the FE (MPR & GR) subs. Sonic Collar Size Sonic 3 1/8” - 4 ¾” - 6 ¾” Sonic MWD 7 ¾” - 8 ¼” - 9 ½” - Operating Limits/Specs In development, 6 ¾” to be

developed first. Δt shear and compression 40-180μs/ft.

New Technology Acoustic short hop telemetry Commercial Q3 1999 Azimuthal Density Commercial Q1 2000 Seismic MWD Commercial Q4 2000 Sonic MWD Commercial Q3 1999 Next Generation MWD Q1 2001 Acoustic Long Hop Telemetry Commercial Q4 2000 Gyro MWD 2-axis Commercial Q1 2000 (Probe based kick-off tool only, collar based tool ‘parked’) Gyro MWD 3-axis Commercial Q4 2000 MWD/FEWD Functionality Matrix Maximum

ROP Recorded

Maximum ROP Real-time (Rotating)

Maximum ROP Real-time (Sliding)

Memory Capacity

GR 360ft/hr 210ft/hr 105ft/hr 1100hrs GR/Res1 180ft/hr 105ft/hr 70ft/hr 840hrs GR/Res1/Res2 180ft/hr 70ft/hr 53ft/hr 840hrs GR/Res1/Res2/Res3/Res4 180ft/hr 42ft/hr 30ft/hr 390hrs GR/Res1/Res2/Dens/Neu 120ft/hr 42ft/hr 30ft/hr 560hrs GR/Res1/Res2/Res3/Res4/Dens/Neu

120ft/hr 30ft/hr 24ft/hr 310hrs

GR/Res1/Res2/Dens/Neu/Son 120ft/hr 35ft/hr 27ft/hr 560hrs GR/Res1/Res2/Res3/Res4/Dens/Son

120ft/hr 30ft/hr 24ft/hr 330hrs

Only tools less than or equal to 4 ¾’ OD operate with a battery, battery life always exceeds memory life. Based on splitphase 1.2BPS. New system based on combinational telemetry at 3BPS due by end 1999.

Tool Overview - Anadrill Dir/incl/DR Collar Size Incl/dir &

Incl/dir/GR (collar)

Incl/dir(probe) Incl/dir/GR (probe)

Incl/dir/GR (Retrievable)

Incl/dir/GR High Temp

2 3/8” - SHARP-XS SHARP-XS - - 3 1/8” - SHARP-XS SHARP-XS - - 4 ¾” - Slim Hole

Adaptable Platform (SHARP)

Slim Hole Adaptable Platform (SHARP)

Slim Hole Adaptable Platform (SHARP)

-

6 ¾” PowerPulse & PowerPulse+GR

SHARP SHARP -

8 ¼” PowerPulse & PowerPulse+GR

- - - -

9 ½” PowerPulse & PowerPulse+GR

- - - -

Operating Limits/Specs

Torque,WOB additional option. Continuous dir/In 150°C (option to 175°C) 4°/100ft (rot.) 6 ¾” 53KNm 8 ¼” 103KNm 9 ½’ 156KNm 6 BPS Max (3BPS normal)

150°C 1.0 BPS Max GR also possible. Dogleg??

Continuous dir/In 150°C (option to 175°C) 145°/100ft 1.0 BPS Max

Continuous dir/In 150°C (option to 175°C) 145°/100ft 1.0 BPS Max

Most tools have option to be modified to 175°C.

Slim 1 also available – a lower tech and lower reliability retrievable probe tool for greater than 2.06” OD collar.

Resistivity and Geosteering Collar Size

GR/Res (Qualitive – probe)

GR/Resistivity (Quantative – collar)

GR/Resistivity (Quantative – probe)

Geosteering

3 1/8” - - - - 4 ¾” - IMPulse(Vision

475)

SHARP &ARC SHARP-AIM (inclination at bit with EM transmission of survey), AIM-475,

6 ¾” - Vision 675, Compensated Dual Resistivity CDR6

- AIM-675, Resistivity at Bit (RAB), GeoSteering Tool (NBS+motor)

7 ¾” - - - - 8 ¼” - CDR8 - RAB 9 ½” - CDR9 - - Operating Limits /Specs

- 150°C (option to 175°C) 15°/100ft (rot) 4 ¾” 35KNm 6 ¾” ?KNm 8 ¼” ?KNm 9 ½” ?KNm 6 BPS

Continuous dir/In 150°C (option to 175°C) 145°/100ft 1.0 BPS Max (no specs available)

150°C (135°C for GeoSteer) Modular and combined with MWD system in use. (i.e. VISION, PowerPulser or SHARP) Geosteering tool uses EM to communicate to receiver subs (either RCV, RWOB or GVRS)

ARC = 2 attenuation and 5 phase depths, 2MHz compensated, GR. VISION = ARC + PowerPulseGR + 400kHz CDR = 2 depths, 2MHz compensated +GR and PCAL (WBM only caliper), Pe option. RAB = Laterlog Res + GR optional azimuthal for DIP & imaging. *RWOC = RCV+WOB, GVRS=RCV+Resistivity Density and Neutron Collar Size Density

/Lithology (collar – not borehole standoff corrected)

Neutron Porosity (collar – not borehole standoff corrected)

Density /Lithology (collar - borehole standoff corrected)

Density/Neutron (collar – borehole standoff corrected)

3 1/8” - - - - 4 ¾” - - - Azimuthal Density Neutron

ADN4 6 ¾” - - - ADN6 , VISION 675 7 ¾” - - - Compensated Density

Neutron/Caliper (CDN8) 8 ¼” - - - - 9 ½” - - - - Operating Limits /Specs

- - ADN & CDN: porosity accuracy +/- 0.5pu ,10pu, +/- 0.5%pu >10pu, 12” resolution, ρ accuracy +/- 0.015g/cc resolution 6”. (except CDN porosity resolution 13.2”) Acceptable data in 3” stand-off.

150°C VISION-advanced resolution with 16 bins – not 4. Logging during rot. only Source Retreivable Azimuth with ADN & VISION only.

CDN provides rotational ρ using acoustic caliper to QC data (not to correct it) and compensated neutron. ADN uses caliper to determine which ρ is correct and provides average ρ and quadrant ρ and Pe. Also caliper and compensated neutron. LWD Inductive Coupling Tool (LINC) available for fishing sources or downloading data from tools. Vibration, Dynamics and Pressures, Rotary Drilling Collar Size Vibration Dynamics Pressure Rotary Drilling 3 1/8” - - - - 4 ¾” - - - 6 ¾” Included in

PowerPulse WOB/Torque Option in PowerPulse

Vision Pressure While Drilling (VPWD)

CAMCO PowerDrive, Schlumberger tool.

7 ¾” - - - - 8 ¼” Included in

PowerPulse WOB/Torque Option in PowerPulse

VPWD CAMCO PowerDrive, Cambridge tool.

9 ½” Included in PowerPulse

WOB/Torque Option in PowerPulse

VPWD -

Operating Limits/Specs

Lateral vibration only providing real-time shocks/sec. Triaxial vibration special option to PowerPulse but not in combination with GR.

Annular and internal pressure. Provides power to IMPulse to logWTrip Annular pressure also available in CDR as option.

No data provided. All tools in market however Anadrill prefers own tool which has a target MTBF of 1400hrs.

Sonic Collar Size Sonic 3 1/8” 4 ¾” Due year 2000. 6 ¾” Ideal Sonic Tool (ISONIC) 7 ¾” 8 ¼” ISONIC 9 ½” Operating Limits/Specs Compressional Δt uphole and

down hole, shear Δt uphole. 150°C 40 - 180μs/ft. Max logging speed 110m/hr

New Technology No information provided….

MWD/FEWD Functionality Matrix Maximum

ROP Recorded

Maximum ROP Real-time (Rotating)

Maximum ROP Real-time (Sliding)

Memory Capacity

GR ft/hr ft/hr ft/hr Hrs GR/Res1 ft/hr ft/hr ft/hr Hrs GR/Res1/Res2 ft/hr ft/hr ft/hr Hrs GR/Res1/Res2/Res3/Res4 ft/hr ft/hr ft/hr Hrs GR/Res1/Res2/Dens/Neu ft/hr ft/hr ft/hr Hrs GR/Res1/Res2/Res3/Res4/Dens/Neu

ft/hr ft/hr ft/hr hrs

GR/Res1/Res2/Dens/Neu/Son ft/hr ft/hr ft/hr hrs GR/Res1/Res2/Res3/Res4/Dens/Son

ft/hr ft/hr ft/hr hrs

Not provided…..(calculator provided).

6. Resistivity tool modelling, FEWD & horizontal holes

Summary

The main tools for determination of hydrocarbon saturation in open hole are resistivity tools. Such tools are rather sensitive to the presence of borehole, mud filtrate invasion, neighbouring layers, dip / deviation and tool physics. Therefore, corrections are often required, especially in thin beds, heavily invaded beds, and strongly deviated / horizontal holes. In horizontal holes the basic petrophysics measurements are often acquired while drilling (MWD: Measuring While Drilling, LWD: Logging While Drilling, FEWD: Formation Evaluation While Drilling). FEWD tools often work quite differently from conventional wireline tools. Hence, tool modelling is also required for such measurements. In part A of this chapter, resistivity tools and their response modelling (incl. inversion) will be discussed. Most of the information on the actual tools is described in the Schlumberger Principles book, and will therefore only be dealt with very briefly here. In part B of this chapter, Formation Evaluation While Drilling (FEWD) is discussed.

Part A: Resistivity tools and tool response modelling

Resistivity tools

Principle Reservoir formation brine is normally saline and hence conductive to electric current. Hydrocarbon is not conductive. Hence a logging tool that measures the electric resistivity (1 / conductivity) of the formation can distinguish between water bearing rock (low resistivity) and hydrocarbon bearing rock (high resistivity).

Tools: laterolog or induction ? There are two types of resistivity tool: electrode tools (e.g. the laterolog) and induction tools. Electrode tools (e.g. laterologs) are normally used in conductive (saline) muds, and induction tools in non-conductive (e.g. OBM) muds. These conventional resistivity tools (laterolog, induction log) only work in formations with reasonably saline formation water. For the case that the formation water is extremely fresh (very low salinity), dielectric tools (EPT, DPT) have been developed. Their success is limited, however, by their very shallow depth of investigation, such that they do not read beyond the invaded zone. They will not be discussed here.

Saline muds: laterolog tools The first electrode type tools (used in saline muds), called (short and long) normal tools, consisted of a current emitting electrode and a potential measurement electrode at a short (16”) or long (64”) distance away from the current emitter (see chapter 7 of the Schlumberger Principles book). The current return was at surface. These tools had the disadvantage that much of the current leaked away via the

(normally conductive) borehole mud. An intermediate tool was the lateral tool which worked with two measuring electrodes. This tool was very difficult to interpret in those pre-computing days. Therefore, the laterolog was introduced. In the laterolog measurement the electric current is forced (by surrounding guard, or bucking electrodes, at the same potential as the current emitter) to flow perpendicular to the borehole, i.e. (in a situation of a vertical hole, horizontal layering) laterally. The current is returned to a point higher up the cable. Thus the borehole leakage problem is minimised and the current probes the formation as deeply as possible, hopefully far into the uninvaded (“virgin”) zone. This “deep” measurement is combined with shallower measurements (current return on the tool) to allow correction for invasion: see further below. The standard DLL (Dual Latero Log: bottom right of Fig. 1) consists of (MSFL is not shown): LLD = Laterolog deep: looks deep into the reservoir LLS = Laterolog shallow: looks shallow into the reservoir MSFL = Micro-spherically focused log (a pad-type tool): reads the resistivity close to the wellbore Combination of these measurements can give information on the effect of the mud filtrate invaded zone on the true resistivity, if the bed is thicker than about 30 ft: such corrections can be done using the so called "Tornado" correction charts (the name describes the shape of these correction curves). Such charts are also available as correction algorithms in petrophysical evaluation software. For beds thinner than about 30 ft such correction charts will not work, hence tool modelling / inversion techniques have to be used. The Laterolog Deep (LLD) measurement can read anomously high (falsely indicating hydrocarbons) just below a high resistivity bed, e.g. a salt layer. This effect is called the Groningen effect (Fig. 2) and is due to the squeezing of the current back into the (cased) borehole (normally the current would also go back via the top shoulder bed, but as this is prevented now, the current has less freedom, hence the apparent higher resistivity). This effect is very pronounced below the salt layer in the Groningen gas field in The Netherlands, hence its name. Special techniques exist to correct for this effect. The newest laterolog type devices (e.g. Schlumberger's Azimuthal Resistivity Imager, ARI: see below) have their own correction for the Groningen effect. A modern version of the laterolog is Schlumberger’s Azimuthal Resistivity Imager, ARI, which is a DLL with an azimuthal section at the top (Fig. 3). This section consists of 12 azimuthal measurements, each covering 30 degrees. The claimed vertical resolution is 8 inch. The ARI provides an azimuthal image, resembling images of the high resolution formation image tools (e.g. FMI, STAR), but having lower resolution. The ARI has a correction for the Groningen effect (see above).

Non-saline muds: induction tools In boreholes containing non-saline muds, e.g. oil-based mud (OBM), the induction tool can be used. The induction tool (Fig. 4) has a transmitter coil which is operated at a frequency of about 20 kHz. This generates an electromagnetic field which generates eddy (or Foucault) current loops in the formation. Eddy currents would also be generated in the borehole if the mud were saline: that's why the induction tool was designed for non-conductive (non-saline) mud environments. The eddy currents in the formation will be proportional to the formation conductivity

(= 1/resistivity). The eddy currents in their turn will generate a voltage signal in the receiver coil.

The standard induction tool (non-conductive muds) is the DIL (Dual Induction Log), which has more coils than the basic tool of Fig. 4, and yields two curves: ILD = Induction log deep ILM = Induction log medium An example of a more recent induction tool developent is Schlumberger’s Array Induction Imager Tool (AIT). It combines measurements of many coils to obtain resistivity curves with different depths of investigation. In this way invasion profiles can be obtained. The AIT has one 3-frequency transmitter and 8 balanced receiver arrays. It measures in-phase and out-of-phase (so called R and X signals). Six arrays measure at dual frequency. By means of processing, five resistivity curves are obtained, ranging from 10 to 90 inch depth of investigation. Moreover, enhanced vertical resolution processing yields curves with 4, 2 and 1 ft resolution. The tool also gives a resistivity image around the borehole. This yields profiles for invasion, Rt, and volume of mud filtrate. Baker Atlas is marketing the 3D Explorer (originally developed by Shell) which has coils perpendicular to each other. This set-up allows the tool to identify resistivity anisotrophy.

Separation between the deep and shallow curves for the dual laterolog (Figure 5) In non-reservoir (e.g. Shale, Anhydrite, Salt), there is no invasion of mud filtrate in the formation, because of the lack of permeability in non reservoir rock. All three resistivity devices will therefore read the same resistivity (e.g. Rshale). In porous reservoir, mud filtrate (resistivity = Rmf) will invade the zone close to the wellbore, replacing all the formation water (resistivity = Rw) and part of the hydrocarbons (if present). - The LLD is less influenced by the borehole, mudcake and invaded zone. It will

read closest to the resistivity of the uninvaded reservoir rock (Ro or Rt). - The LLS is significantly influenced by the borehole, mudcake and invaded

zone. (It can be used to correct the LLD when necessary.) - The MSFL reads the resistivity of the invaded reservoir rock (Rxo).

Evaluation objective

- Differentiate between hydrocarbon and water bearing intervals. - Quantify the water resistivity Rw in water bearing intervals - Quantify the water saturation Sw in hydrocarbon bearing

Quicklook clean sand evaluation technique - Identify potential reservoir intervals by looking for separation of the resistivity

curves in combination with GR and porosity logs. - Water bearing reservoir can usually be recognised by a relatively low deep

resistivity. The density and the deep resistivity will adhere to the first Archie formula. This means that an increase in porosity (more water) will cause a decrease in resistivity and visa versa. As a result both logs will tramline.

- Hydrocarbon bearing reservoir can be recognised by a relative high (deep) resistivity. Instead of tramlining the density and deep resistivity logs will show the opposite effect. Because of capillary forces, the lower porosity intervals

tend to have higher water saturations. A decrease in porosity will cause a decrease in resistivity, resulting in a Mae West log pattern.

- Rw and Sw's can be calculated with the Archie equations. - The water saturation in the invaded zone (Swxo) can be determined by

inserting Rxo and Rmf in the Archie equation. In most cases Swxo will be a lot higher than the initial Sw, showing that part of the hydrocarbons were displaced by the invading mudfiltrate.

Resistivity tool modelling and inversion

Why environmental corrections are often required for resistivity logs Ideally, logging tools should only measure properties of the "virgin" formation. Unfortunately, however, the responses of most logging tools are affected (disturbed) by the presence of the borehole (mud) and the mudfiltrate invasion. In all tools a compromise is made between depth of investigation and resolution, i.e. the deeper a tool "sees" into the formation, the more its response will also be influenced by neighbouring beds above and below its actual position (if a tools sees deep horizontally, it will also read far vertically). Nuclear tools in general don't read deep, because nuclear particles are absorbed rapidly. Hence, they mainly read the invaded zone. On the other hand they have a good vertical resolution (discriminate well between different beds). Resistivity tools, however, have been especially designed to read beyond the invaded zone, so that they can see the hydrocarbon in the virgin reservoir. Because of this great depth of investigation, the vertical resolution of resistivity tools is poor (worse than 6 – 7 ft). Because of that they are heavily affected by neighbouring (non-hydrocarbon bearing) beds, and also by the borehole and by the mudfiltrate invaded zone. A hydrocarbon bearing reservoir normally has a high resistivity and is normally surrounded (top and bottom) by less resistive shoulder beds, e.g. shales or water bearing zones. Furthermore, the mudfiltrate invaded zone is normally less resistive than the uninvaded (hydrocarbon bearing) zone. Because of that the resistivity log will read an apparent resistivity that is lower than the true resistivity of the uninvaded reservoir layer. Hence, a calculation of the hydrocarbon saturation based on the apparent (log measured) resistivity would yield a too low hydrocarbon saturation. Therefore, this effect has to be corrected for. The process with which we obtain the true uninvaded zone formation resistivity Rt from the measured resistivity Rlog is called deconvolution, or inversion. This is especially important for beds wit thicknesses less than 20 – 30 ft. In relatively thick beds (thicker than 100 ft) the bad resolution doesn’t cause a problem. However, if the bed thickness is lower than 100 ft, corrections have to be applied. For beds thicker than 20 ft contractor correction charts might be applied for this purpose.

Standard environmental corrections using contractor correction charts The standard correction sequence is (see Schlumberger Chart book): - Borehole: especially for laterolog - Layering (shoulder beds) - Mud filtrate invasion (Tornado charts): especially for laterolog For beds thinner than about 20 – 30 ft these corrections become very inaccurate and tool response modelling / inversion techniques have to be applied.

Resistivity tool response modelling and inversion For beds with thicknesses between about 2 and 20 ft a mathematical inversion (“deconvolution”) has to be applied (for beds thinner than 2 ft deconvolution is no longer possible). Deconvolution methods have been developed and incorporated in petrophysical software.

The first step is to set up a mathematical model describing the layering (depths, thicknesses) and the properties of the layers (e.g. the resistivities of the invaded and uninvaded zones in each layer). Using the electromagnetic (Maxwell) equations from physics, one can then calculate what a resistivity tool would measure over such a sequence, if a suitable approximation for the tool physics is available. This step is called forward modelling (Figs. 6 and 7) and it yields a calculated output resistivity log. If this log actually ressembles the field (e.g. Schlumberger) measured log response in sufficient detail, then the input formation layering model with its properties was probably correct. If not, the formation layer model and its properties (e.g. its layer resistivities) are updated and the procedure is repeated. This iterative forward modelling until a good fit is reached between calculated log and actually measured log is called inversion, or deconvolution.

Example As a very much simplified example, let’s consider a four layer sequence, in which the layers have the following true formation resistivities (borehole and invasion are ignored):

Layer Depth range (ft) True layer resistivity Rt

(unknown in practice !)

Average induction resistivity log response

Rlog

1 3000 - 3010 10 13

2 3011 – 3016 100 43

3 3017 – 3026 10 10

4 3027 - 3048 1 1.1

A typical induction log resistivity response would be as given in the fourth column (as a simplified tool response function it has been assumed that the tool measures a logarithmic average over 9 feet; in the column the average response over the whole layer is indicated). We see that because of the bad vertical resolution the tool has made averages of several layers and therefore, in general, shows a too low resistivity in the hydrocarbon bearing zone (layer # 2).

The resistivities Rlog (last column) are the only ones available. From them we have to make an estimate of the true resistivities Rt, hopefully coming as close as possible to the actual values (given in the third column, and of course in practice unknown to the evaluator). For this purpose we are going to use iterative forward modelling.

We will start with an estimate of Rt, called Rt_1 (which is simply arrived at by guestimating it from Rlog): see Table given below. If Rt_1 were the true formation profile (=Rt), then the log calculated from it, called Rlog_1, would be equal to the actually measured log (Rlog: given above). If this is not the case, we try a new Rt-profile, a second guess, called Rt_2.

Herefrom we again calculate (using forward modelling) what kind of log-profile that would give (called Rlog_2). We can repeat this process n times, until Rlog_n is close enough to the actual Rlog.

The thus obtained Rt_n estimate should then be a reasonably good estimate of Rt. In the table below, we have started with an Rt_1 profile that is too low (in layer 2), giving an Rlog_1 that is much weaker than Rlog. Subsequently we have boldly taken an Rt_2 which is too high (in layer 2), giving an Rlog_2 that is too sharp.

Subsequently we have taken an Rt_3 which is somewhere in between Rt_1 and Rt_2. This gives an Rlog_3 profile that is reasonably close to the actual Rlog. So, one might take Rt_3 as a reasonably good estimate of Rt (comparison with the table above shows that it is not perfect yet though: one can increase the accuracy [for which the deviation between the calcualted Rlog_n and the measured Rlog is the only measure available !] by continuing the iteration process).

Layer Rt_1

(too weak)

Rt_2

(too sharp)

Rt_3

(in between Rt_1 and Rt_2)

Compare to Rt

Rlog_1

(forward modelled

from Rt_1)

Rlog_2

(forward modelled from

Rt_2)

Rlog_3

(forward modelled

from Rt_3)

above Compare to Rlog above

1 10 13 11 11 15 13

2 39 150 77 27 82 47

3 8 7 7 7 8 7

4 2.7 1 1 1 1 1

From this example we see that the accuracy of the result we end up with (the Rt_3 profile in this case) depends on how closely we are able to match the calculated log (Rlog_3 in this case) with the actual one (Rlog). The discrepancy between the calculated log (Rlog_n) in the nth iteration and the actual log (Rlog) is a measure for the accuracy of the result (Rt_n) as an estimate of the true resistivity profile (Rt). In this example some further iterations might be tried to improve that accuracy.

Uniqueness The formation layering model that is thus obtained yields a best estimate for the true formation resistivities and thus serves as a corrected resistivity log profile, an estimate of Rt. However, it has to be realized that many different Rt profiles might give very similar log responses (measured by the tool), and thus the inversion process may not deliver unique results.

Modelling and inversion software Too mathematically simulate the full reservoir geometry and tool physics would be very complicated and time-consuming. Therefore, approximations have to be made (Fig. 8). There are three different levels of complexity in resistivity tool response modelling (in all models the formation layers are assumed to be extended indefinitely in the lateral dimensions): 1. 1-D (one-dimensional) modelling:

The formation layering is taken into account and formation dip combined with borehole deviation is accounted for as well. However, the effects of the borehole and mud filtrate invasion are not taken into account. This approximation is quite valid for induction tools if indeed run in non-conductive muds (for which they are intended). The approximation normally is less good for laterologs because they are run in conductive muds (hence, effects of borehole and invasion cannot be ignored).

2. 2-D (two-dimensional modelling): The formation layering is taken into account, but formation dip combined with borehole deviation are not accounted for. On the other hand, the effects of the borehole and mud filtrate invasion are taken into account. This approximation is quite valid for laterologs as they are run in conductive muds (for which they are intended). The approximation normally is not required (and unnecessarily restrictive) for induction tools, for which 1-D modelling can be used, taking into account dip/deviation.

3. 3-D (three-dimensional modelling) The formation layering is taken into account and formation dip combined with borehole deviation is accounted for as well. Also, the effects of the borehole and mud filtrate invasion are taken into account. This is the most complex

approximation, and therefore it is used only if it is really required. It is especially useful to model laterologs in cases of strong dip/deviation, e.g. in horizontal holes.

Impact Typically, increases of about 10 % absolute can be obtained in the hydrocarbon saturation as a result of applying inversion. Fig. 9 gives an example of the application of 1-D inversion software: the output resistivity curve is called “Rt model”. The resulting water saturation, calculated from Archie, is called “Sw-Rt model”. The average decrease in Sw (hence increase in hydrocarbon saturation) is about 10 % in saturation percent units. The tool response modelling and inversion methods can also be used for formation evaluation while drilling (FEWD). For instance, FEWD resistivity logs run in strongly deviated holes may show spikes near bed boundaries, called "polarisation horns". These are artefacts of the tool physical principle, and have to be removed by resistivity tool response modelling / inversion.

Part B: Formation Evaluation While Drilling

Some terminology MWD, measurement While Drilling, is a name normally reserved for the acquisition of drilling related parameters like Rate Of Penetration, Weight On Bit, Inclination, Azimuth, etc. during the drilling process. LWD, logging while drilling, also called FEWD, Formation Evaluation While Drilling, are names normally reserved for the acquisition of petrophysical data while drilling, like gamma-ray, resistivity, density and neutron porosity. Sometimes, unfortunately, the term MWD is also used for this process.

MWD / FEWD applications Typical applications of measurements while drilling are:

- Welltrack steering (while drilling), also called geosteering. - Replacement for wireline logging in difficult situations (e.g. long horizontal

holes). - Replacement of wireline formation evaluation in all situations (may

sometimes be better than wireline because there may be less mud filtrate invasion just after drilling).

- Comparison of FEWD and wireline logs may give information about the invasion process.

- FEWD tools often have a better vertical resolution than wireline tools (especially the resistivity tools).

- Data safe-guarding (FEWD data are available if the hole collapses before wireline logs can be obtained): “insurance logging”.

- Pore pressure (kick) prediction. - Correlation with nearby (vertical) wells.

Data transmission A wireline logging cable is not available while drilling and hence the data have to be either memorised downhole (using a battery pack) or transmitted to surface by mud pulsing. Typically only a few bits can be transmitted per second, but this is not a problem, because much time is available during the (slow) drilling process anyway.

Geosteering One important application of logging while drilling is the possibility to use the acquired real-time data for steering the drill bit (“geosteering”). Obviously this helps in geologically complicated cases (Fig. 10). To enable geosteering the measurement tools have to be placed as closely behind the drill bit as possible. This enables much quicker feedback to the drilling process (Fig. 11) than was possible conventionally where the tools were placed further behind the bit.

For this purpose the major data acquisition contractor have developed geosteering systems (Figure 12) . As an example of tool configurations in a geosteering tool, the IDEAL geosteeing system (Schlumberger) is explained below: - Either a geosteering or a “resistivity at the bit (RAB)” unit directly behind the

bit. The geosteering unit has a steerable Positive Displacement Motor (PDM) and measurements of bit speed & inclination, azimuthal resistivity and gamma-ray. The RAB measures resistivity at the bit (current is generated via the bit), and it has a near bit stabiliser and is combinable with a steerable motor.

- A Receiver Weight on Bit and Torque (RWOB) tool, just behind the geosteering or RAB tool. The RWOB tool receives data from sensors and sends them to the MWD tool just above (behind) it. It also measures the drilling mechanics.

- A power pulse MWD tool (just behind the RWOB tool): it pulses the mud with a special siren such that it can go up to 10 bits/s (sending & receiving mud pulses to/from surface). It also measures tool face, azimuth and inclination.

- The density/neutron and resistivity tools (behind the MWD tool): Compensated Dual Resistivity and Azimuthal Density / Neutron (ADN: Fig. 13) plus spectral gamma-ray.

Petrophysical measurements

The gamma-ray measurement is very similar to the wireline measurement and is as accurate. The neutron measurement (Fig. 13) again is similar to the wireline measurement and is OK as long as the borehole is not too rugose. The first LWD density measurements suffered very much from borehole rugosity effects. Because of that the current generation LWD density tools have been made similar to wireline density tools, with source and detectors measuring via a pad (Fig. 14). The tool has to be run using a stabiliser to allow good contact with the borehole wall. Even so, the measurement deteriorates in rugose boreholes. The LWD resistivity tool (Fig. 14) is different in principle from the wireline tools. It works at a higher frequency (1 – 2 MHz, in stead of the 20 kHz used in the induction). A transmitter send out an electromagnetic wave. The travel time of the wave gives the phase resistivity whereas the amplitude reduction (attenuation) gives the amplitude resistivity. The amplitude measurement is believed by some people to read somewhat deeper than the phase measurement, although this has been disputed by others. The phase difference decreases with increasing formation resistivity. At resistivities higher than about 100 – 200 Ohmm the phase difference can not be measured with sufficient accuracy anymore. Therefore the phase measurement is restricted to resistivities lower than 100 – 200 Ohmm. The amplitude ratio increases with increasing formation resistivity, but reaches an asymptote (flattens off) for resistivities higher than about 10 – 50 Ohmm. Therefore, the amplitude derived resistivity is not reliable anymore for resistivities higher than about 10 – 50 Ohmm. This restricted resistivity range of the LWD resistivity measurement is one of the disadvantages of LWD versus wireline. Both the pase and the amplitude derived resistivities may display polarisation horns at bed boundaries (flat interfaces) if the borehole makes an angle different from 90 degrees with the interface. These horns arise because charge builds up at the

interface if the eddy currents collide with the interface (this doesn’t happen when a vertical borehole intersects a horizontally layered sequence, as the eddy currents will be parallel to the layers in that case). Polarisation horns can be corrected for using tool response modelling / inversion. They may be valuable though, because they are good indicators for the existence of interfaces, and hence are helpful while geosteering. Appendix 1 provides an overview of the current (2000) FEWD tools “on offer” by the three major Contractors.

Copyright 2001 SIEP b.v.

Measures deep and shallow resistivity

Deep: 35 Hz Shallow: 270 Hz

Deep resistivity gets past the invaded zone

Resistivity Oil saturation

Figure 1 - The Dual Laterolog

Copyright 2001 SIEP b.v.

Resistivity

LLS

LLD

Groningen effect

Distance between

return &

currentelectrodes

Limitations of Standard Tools

Figure 2 - Groningen effect on the Laterolog

Azimuthal electrodes of the ARI: on top of conventional DLL tool

Figure 3 - Electrode set-up of the ARI

Induction logging

Figure 4 - Principle of Induction Logging

Resistivity log readings over an oil and water bearing sand

OWC

0 10 20 30 40 50 60 70 80 90100

0.5

1.0 105

2960

2970

2980

2990

3000

Depthin m GR

Laterolog deepLaterolog shallowMSFL

Figure 5 - Separation of Resistivity Curves…an indication of permeability

True reservoir model

Update model

Properties

Tool modelling

Comparable ?No

Yes

Calculated Measured

Figure 6 - Modelling and Inversion of Logs

Tool modelling and inversion

Reality ComputerFormationlayering

Toolresponse

Noise

Field log

Layeringmodel

Toolmodel

Errors

Calculated log

Updatelayeringmodel

Match ?

Acceptlayeringmodel

no

yes

Figure 7 - Concept of Tool Modelling

Assumptions made inresistivity tool response modelling

1D model 2D model 3D model

LayersDip / deviation

LayersBoreholeInvasion

LayersDip / deviationBoreholeInvasion

Figure 8 - Typical Model Configurations

Inversion yields 8 % STOIIP increaseWell @ 44 deg. dip

Rt model Sw from Rt model

Figure 9 - Impact of 1-D Induction Tool Modelling on Sw

Geosteering:drilling geologically rather than geometrically

Geologically

Geometrically

May be over 10 km

Figure 10 - Drilling Geometrically vs. Geologically

North Sea Tern FieldExample of geosteering benefits

Shale

Oil sand

Watersand

CDN

MWDCDR

Steerablemotor

45’

Conventional drilling:* Top of sand identification

one hour after drilling* Well landed in water zone* Plugback necessary

Shale

Oil sand

Watersand

CDN

MWD

CDRGeosteeringtool

Using bit measurements:* Top of sand identification* Well landed in pay zone* Five days rigtime saved

because no pilot hole required Figure 11 – Geosteering 1

Schlumberger’s IDEAL system

Measurements close at the bit• Drilling problems: early warnings of

gas kicks, stuck pipe, washouts

• Geological uncertainty: geosteering

• Improved logging (LWD):before invasion / wellbore damage

Figure 12 - GeoSteering 2

Figure 13 – The Azimuthal Density (Schlumberger)

Copyright 2001 SIEP b.v.

Electromagnetic Wave Resistivity (EWR) principle

Transmitter:emits electromagnetic wave

(about 1 GHz)

Receivers:detect electromagnetic wave

R1 R2 Arrival time differenceresistivity phase shallow

Amplitude attenuationresistivity amplitude deep

Figure 14 – LWD, Resistivity Measurements

7. Saturation determination in dispersed shaly sands: The Waxman-Smits equation

Summary

In shaly sands the resistivity is lower than in clean sands with the same porosity and hydrocarbon saturation. This is caused by the additional electrical conductivity of the clay. Therefore, use of the Archie equation would give a too low hydrocarbon saturation. If the clay is coating the sand grains homogeneously (i.e. we have a “dispersed” clay distribution), we have to use the Waxman-Smits equation rather than the Archie equation. This chapter describes the use of the Waxman-Smits equation for accurate determination of the hydrocarbon saturation in dispersed shaly sands.

References

- SPWLA reprint volume “Shaly Sand”, July 1982 Contains many key articles, e.g. the ones by Waxman & Smits, Juhasz, Hill / Shirley / Klein, and many others.

- M.H. Waxman and L.J.M. Smits, Electrical conductivities in oil bearing shaly sands, SPE Journal, June 1968 The article that started it all.

- I. Juhasz, Normalised Qv - The key to shaly sand evaluation using the Waxman-Smits equation in the absence of core data, SPWLA 22nd Annual logging symposium, June 23-26, 1981

- Archie III: Electrical conduction in shaly sands, Oilfield Review, Vol. 1, Number 3, October 1989 Description of history and some alternative Schlumberger models.

- Worthington, P.F., The evolution of shaly sand concepts in reservoir evaluation, Log Analyst, Jan.-Feb. 1985, pp. 23 – 40. History and discussion of alternative models to the Waxman-Smits equation.

- Hill H.J., Shirley, O.J. and Klein, G.E., Bound water in shaly sands – Its relation to Qv and other formation properties, Log Analyst XX, no. 3, 1979

Why saturation modelling ?

Saturation models like Archie, Waxman-Smits and other shaly sand models (Dual Water model, Indonesia equation etc.), are used to calculate the hydrocarbon saturation from the resistivity log. As these equations contain empirical constants (e.g. Archie’s m and n constants), they have to be calibrated against cores in the laboratory. Such laboratory measurements yield the so called resistivity index (I-Sw) curve. Why can’t we use this laboratory derived curve straightaway to translate field resistivity into hydrocarbon saturation ? We could if this curve would have been measured in the laboratory at simulated in situ conditions, i.e. at high pressure and temperature, using the field crude and brine, and if a sufficiently low water saturation could be reached in the experiments. However, few laboratory experiments are carried out at simulated in situ conditions (such experiments are very time-consuming and expensive). Moreover, because of the limited capillary pressures that can be reached in such experiments, most experiments can only be carried out for water saturations down to 20 or 30 %. Hence, in many cases extrapolation of the laboratory I-Sw curves is necessary to lower Sw saturations and to different pressure / temperature and fluid type conditions. For this purpose the saturation models are used. According to the Archie equation, the I-Sw curve is a straight line on a double-logarithmic plot, and hence extrapolation is not difficult. However, in shaly sands the I-Sw relationship on a double-logarithmic plot is no longer linear, and extrapolation is, therefore, not straightforward. The extrapolation, in this case, has to be done using a mathematical equation, and this is the Waxman-Smits equation.

Brief history of saturation modelling

The Archie equation was introduced in 1942. It was entirely based on laboratory experiments on clean sands, and it is, therefore, an emprical model. In the 1950’s and 1960’s it became apparent that corrections had to be made in case of shaly sands. Many models were proposed (see the overview paper by Worthington), e.g. Schlumberger’s Dual Water model, the Indonesia equation etc. In 1968, Monroe Waxman (Shell Oil) and Lambert Smits (Shell Group) published their Waxman-Smits equation, which became one of the most important equations for shaly sands (besides the Dual Water Model, originally developed by Schlumberger). The Waxman-Smits equation is a semi-empirical model, i.e. it is based upon a combination of theoretical considerations, new experiments and the old empirical Archie equation. In the 1980’s people started to look for more complicated models, because of two reasons. 1. There were some doubts about the general applicability of the Waxman-Smits equation vis-a-vis the assumptions upon which that model is based. 2. People wanted to derive a model from fundamental physics rather than relying on semi-empirical models. This led to various so called Effective Medium Models. In this chapter only the Waxman-Smits equation will be discussed.

When to use which model ?

Saturation models are the models which relate measured resistivity to water saturation, from which hydrocarbon content is determined. The main saturation models currently used are:

1) Archie The Archie equations for water-bearing and oil-bearing rock have been stated in the chapter on Quicklook evaluation. The Archie model is purely empirical. It is mainly used for clean sandstone and (non-vuggy) carbonates.

2) Waxman-Smits The Waxman-Smits equation is a semi-empirical extension of the Archie equations, taking into account the additional conductivity caused by shale. The Waxman-Smits equation is mainly used for dispersed shaly sandstones. In case of laminated shaly sandstones, either the Archie or the Waxman-Smits equations can be used in combination with specialist software.

3) Dual Water Model This model, developed by Schlumberger, is very similar to the Waxman-Smits equation but takes into account the exclusion of salt around the clay particles, hence, uses a different salinity of the shale water as compared to the surrounding water in the sands.

Clay conductivity, Clay Bound Water, and Cation Exchange Capacity

Clay Bound Water (CBW) Clay particles (Aluminium or Magnesium containing hydrous silicates) are negatively charged at the outside / surface. Because of this, a clay layer attracts the positive ions, e.g. Na+ (so called “cat-ions”) present in the formation brine (Fig. 1). These positive ions are surrounded by water molecules, because the latter have a dipolar nature (i.e. they have a negative and a positive side) such that their negative side is attracted to the positive ion (Fig. 2). This gives rise to an electric “double-layer”, attached to the clay surface, which is the Clay Bound Water (CBW) layer (Figs. 2-3). This CBW layer is an additional conductance path for the electrical current, hence it gives rise to a clay conductivity, hence to a decreased resistivity of the rock (Fig. 5 & 6). It is this phenomenon (not described by the Archie equation) that is modelled by the Waxman-Smits equation.

Hill / Shirley / Klein Counter to intuition, the thickness of the CBW layer decreases with increasing brine salinity (Fig. 3). This is described by the Hill-Shirley-Klein equation:

φe/φt = 1 – (0.22 + 0.64/S1/2)*Qv where:

φe = effective porosity

φt = total porosity

S = salinity (g/l NaCl equivalent)

Qv = cation exchange capacity (meq/ml)

This phenomenon arises because at high water salinity the negative clay surface is very quickly “screened” off by the many positive ions available, decreasing its influence.

Cation Exchange Capacity CEC (meq/100 g), or Qv (meq / ml) The number of positive ions (i.e. the cat-ion concentration) attracted to the clay surface depends on the amount of clay and the type of clay. This number is called the Cation Exchange Capacity (CEC), also denoted by Qv. CEC is expressed in milliequivalent of exchangable ions per 100 grams of dry clay (meq/100 g), or (if expressed as Qv) in milliequivalent per milliliter (= cm3) pore volume.

Qv = CEC*ρg*(1 – φ)/(100*φ) where: Qv = cation exchange capacity expressed in meq/ml pore volume CEC = cation exchange capacity expressed in meq / 100 g dry clay

ρg = grain density (g/cc)

φ = total porosity fraction, incl. bound water (Fig. 4/5).

The CEC is low for kaolinite (3 – 15 meq/100 g), somewhat higher for illite and chlorite (10 – 40 meq/100 g), and very high for montmorillinite (80 – 150 meq/100 g). It is not directly related to the Gamma-Ray log, because some clays (e.g. Montmorillinite) have little Potassium (hence low GR) but a high CEC. The GR log will give some indication of the amount of clay though, and, therefore, there normally will be some correlation between Qv and shaliness. We will come back on the assessment of Qv later. Clean sandstones will have a Qv (in meq/ml) lower than 0.1, slightly shaly sandstones between 0.1 and 0.2, moderately shaly sandstone between 0.2 and 0.3, shaly sandstone between 0.3 and 0.5, and very shaly sandstone higher than 0.5.

Cation mobility B (mho cm2/meq) Another important factor in the clay conductivity is the mobility of the cat-ions. This gives rise to an equivalent conductance per cat-ion, called B which is (for a given type of brine, e.g. NaCl) solely dependent on the brine salinity and temperature: Fig. 7. B can be approximated by the following equation:

B = (-1.28 + 0.225T - 0.0004059T2)/(1 –(0.27 – 0.045T)Rw1.23)

With T in degrees centigrade.

B is expressed in mho.cm2/meq. (1 mho is the unit of conductance, it is 1/Ohm).

Clay conductivity Ce (mho/cm)

Ce = B.Qv

The clay conductivity Ce is B times Qv, and therefore has the unit mho/cm.

The Waxman-Smits Equation

The Waxman-Smits equation for water-bearing shaly sandstone Although the actual Waxman-Smits equation is the general one for didactic purposes it is easier to first start with the equation for fully water-bearing rock.

The Archie equation for clean water-bearing sandstone is:

Ro = φ-m Rw where: Ro = resistivity of the fully brine saturated rock Rw = brine resistivity

φ = total porosity m = cementation exponent This can be written in terms of the Formation Resistivity Factor, F, as:

F = Ro / Rw = φ-m In order to arrive at the Waxman-Smits equation it is easier to work with conductivities, rather than resistivities. A conductivity is just the inverse of a resistivity (C = 1 /R), hence:

Co = φm Cw where: Co = conductivity of the fully brine saturated rock = 1/Ro Cw = brine conductivity = 1/Rw

Waxman and Smits start with the last equation, but replace Cw by an “equivalent water conductivity” (Cw + Ce), thus taking the additional clay conductivity (taking place via the Clay Bound Water layer) into account. The “tortuosity factor” φm* (Waxman & Smits use a constant m* rather than m: see below) acts on this clay conductivity in the same way as it acts on the (pore) brine conductivity, because all clay is supposed to be in the pores (lining the pore walls). Hence, the Waxman-Smits equation for water-bearing shaly sandstone becomes:

Co = φm* (Cw + Ce) = φm* (Cw + B.Qv) where:

m* = cementation exponent in the Waxman-smits equation

Here, we have substituted B.Qv for Ce, as discussed at the end of the previous section Writing this equation in terms of resistivities rather than conductivities we obtain:

Ro = φ-m* Rw / (1 + Rw.B.Qv) If Qv did not depend on porosity, the double-logarithmic plot of F (= Ro/Rw) versus φ would be a straight line. However, Qv decreases with increasing porosity (less

surface to volume ratio). Therefore, the double-logarithmic plot of F versus φ is curved, especially for low porosities: “banana shape” (Fig. 8). Therefore, Waxman and Smits have introduced a modified Formation Resistivity Factor, F*.

F* = Ro* / Rw = φ-m* where:

Ro* = Ro.(1 + Rw.B.Qv) The double-logarithmic plot of F* versus φ is a straight line (by definition of F*).

The Waxman-Smits equation for hydrocarbon-bearing shaly sandstone

The Archie equation for clean hydrocarbon-bearing sandstone is:

Rt = φ-m Sw-n Rw

where: Rt = resistivity of the partly hydrocarbon-bearing rock Rw = brine resistivity

φ = total porosity m = cementation exponent n = saturation exponent This can be written in terms of the Resistivity Index, I, as:

I = Rt / Ro = Sw-n

In order to arrive at the Waxman-Smits equation it again is easier to work with conductivities (inverse of resistivity: C = 1 /R), rather than resistivities, hence:

Ct = φm Swn Cw

where:

Ct = conductivity of the partly hydrocarbon-bearing rock = 1/Rt

Cw = brine conductivity = 1/Rw

Waxman and Smits start again with the last equation, but replace Cw by an “equivalent water conductivity” (Cw + Ce / Sw), thus taking the additional clay conductivity into account. The additional term Sw arises because the surface to volume ratio for the brine has now changed with this factor. The “tortuosity factor” φm* acts on this clay conductivity in the same way as it acts on the (pore) brine conductivity, because all clay is supposed to be in the pores (lining the pore walls). Hence, the Waxman-Smits equation for hydrocarbon-bearing shaly sandstone becomes:

Ct = φm* Swn* (Cw + Ce / Sw)

or:

Ct = φm* Swn* (Cw + B.Qv / Sw)

where: m* = cementation exponent in the Waxman-Smits equation n* = saturation exponent in the Waxman-Smits equation

Again, we have substituted B.Qv for Ce.

The equation in the box above is the general form of the Waxman-Smits equation. Writing this equation in terms of resistivities rather than conductivities we obtain:

Rt = φ-m* Sw-n* Rw / (1 + Rw.B.Qv / Sw)

Hence:

I = Rt / Ro = Rt / Rt(Sw = 1) = Sw

-n* (1 + Rw.B.Qv) / (1 + Rw.B.Qv / Sw) This equation reveals that the Resistivity Index curve (plotted double-logarithmically) will be non-linear. Waxman and Smits have introduced a modified Resistivity Index, I*.

I* = Rt* / Ro* = Sw-n*

where:

Rt* = Rt (1 + Rw.B.Qv / Sw) The double-logarithmic plot of I* versus Sw is a straight line (by definition of I*).

The Waxman-Smits procedure has been summarised in Figure 9.

How to arrive at Qv ? There are three methods to measure Qv: 1. Measuring Qv on core samples in the laboratory. Several methods are

available, e.g. titration, membrane potential and Co-Cw methods: see the chapter on Core Analysis.

2. Determining Qv by fitting the Waxman-Smits equation to the resistivity log in the water bearing zone (in other words: to the "banana"-shape in the Pickett plot). This is similar to the Pickett procedure in Archie but now two unknowns (rather than the one unknown Rw) are fitted, namely Rw (from the intercept) and Qv (from the curvature) (Figs. 8 & 10). Constant m* has to be known from core analysis, or from regional data. Hence, the fit will give an Rw as well as a Qv value.

3. Determining Qv in a shale interval using method 2 above. Then calculate Qv in a shaly sand by multiplying the Qv in pure shale by the shale fraction Vsh. This is called the "normalised Qv" or Juhasz method. Parameter Vsh can be

calculated from the gamma-ray log or from a density / neutron cross-plot ("Thomas-Stieber" analysis: Figs. 11-12): see chapter on Porosity & Lithology from logs. The latter would indicate whether the clay distribution is “dispersed”, “laminar” or “structural”. The Waxman-Smits equation only applies in case of dispersed clay.

(Theoretically Qv is also related to the SP (Spontaneous Potential) log and could in principle be derived therefrom. However, this is in practice very inaccurate and therefore this method is not discussed here.)

The thus obtained Qv values would normally be regressed against porosity, or against 1/porosity, such that a continuous Qv-curve can then be obtained from the porosity log. Often used relationships are:

Qv = (a/φ) – b

or:

Qv = a.(φ-b)

The three methods may sometimes give rather different relationships. There are several reasons why this may be so, e.g. inaccurate laboratory method (titration is less accurate than membrane potential), biased core plug sampling, limited resolution of the resistivity logs (especially in laminated shaly sands / turbidites), inaccurate shale fraction assessment, and finally inapplicability of the Waxman-Smits equation.

Influence of shaliness on hydrocarbon saturation determination The Waxman-Smits equation in the hydrocarbon-bearing zone can be re-written in terms of Sw: Rw

Swn* =

Rtφm* (1 + Rw.B.Qv/Sw) From this equation two things are apparent:

1. The solution for Sw has to be iterative: this is taken care of in petrophysical evaluation software.

2. The water saturation will decrease, and hence the hydrocarbon saturation will increase the higher the term Rw.B.Qv/Sw is. If this term is equal to or less than 0.1 (i.e. 10 %), the effect of shaliness can be neglected. The higher the term is, the more important the effect of shaliness becomes. This will be the case if the formation water is relatively fresh (low Rw, also leading to high B), and/or if Qv is high (montmorillinite clay / much clay), and/or at high temperatures (high B).In that case Sw decreases and Waxman-Smits therefore yields more hydrocarbon than application of Archie ! (Fig. 13). It can be derived that the maximum increase in hydrocarbon saturation when applying Waxman-Smits rather than Archie is about 25 % (in absolute saturation %). Hence, if for example Archie would give Sw = 0.50, then Waxman-Smits would yield at best Sw = 0.75, in case Rw.B.Qv/Sw would be very high (Figs. 14).

Example calculation Waxman-Smits versus Archie

φ = 0.25; m = n = 1.8;m* = n* = 2.0

Qv = (1.0/φ) - 3.0. T = 100 deg. C Rw = 0.05 Ohmm Rt = 12 Ohmm in oil-zone. Archie

Sw = (Rw φ-m

/ Rt) (1/n)

thus:

Sw = 0.19 Waxman-Smits

For φ = 0.25: Qv = 1.0 meq/ml From chart: B = 17.0 mmho/meq/ml Hence, B.Qv = 17.0 mmho Substitute in W-S equation:

Ct = φm*

Swn*

(Cw + (B.Qv/Sw)) where: Ct = 1/Rt = 1/12 and Cw = 1/Rw = 1/0.05

and

φm*

= 0.252

This yields a quadratic equation for Sw:

0.083 = 0.0625 Sw2

(20 + (17/Sw)) From which:

Sw = 0.07

Conclusions

- The resistivity of a shaly sand is lower than that of a clean sand with the same porosity and hydrocarbon saturation.

- If no correction is applied for this effect, application of the Archie equation would yield a too low hydrocarbon saturation (being “misled” by the low resistivity): the Archie equation would wrongly attribute the low resistivity to a high water saturation, whereas the Waxman-Smits equation would correctly attribute it to the influence of clay, thus avoiding overestimation of Sw.

- The Waxman-Smits equation takes this additional clay conductivity into account as a correction to the Archie equation. Application of the Waxman-Smits equation therefore results in a correct prediction of the hydrocarbon saturation.

- With respect to the Archie equation, the Waxman-Smits equation contains the additional term B.Qv. The term B only depends on salinity and temperature, and is therefore not dependent on the type of rock / lithology. It is a fixed chart / algorithm and is therefore known: it doesn’t need to be measured again in the laboratory. The term Qv on the other hand is strongly dependent on rock type / lithology, and has therefore to be assessed anew (preferably from laboratory measurements on core samples) in each individual case.

- The term Qv can be obtained in three ways: 1. From core measurements. This is the most accurate method. 2. By fitting the Waxman-Smits equation to the water-bearing zone (“Pickett-plot”) 3. By fitting the Waxman-Smits equation to a nearby shale zone (“normalised Qv”).

- Application of Waxman-Smits will yield more hydrocarbon than application of Archie if the term Rw.B.Qv is much higher than 0.1. This will be the case if the formation water is relatively fresh (low Rw), and/or if Qv is high (montmorillinite clay / much clay), and/or at high temperatures (high B).

- The maximum absolute increase in hydrocarbon saturation is 0.25 (fraction of pore volume).

Evaluation of laminated shaly sands

Hydrocarbons in laminated shaly sands are difficult to recognise on traditional resistivity logs: the resistivity will be low as it tends to be dominated by the low resistivity shale laminae (via which the current will mainly flow). Hence, the electric current will avoid (and therefore "not see") the sand laminae in which the possible hydrocarbons would be. To solve this problem petrophysical evaluation software exists which corrects the resistivity response for the presence of shale laminae. This will in general give a higher corrected resistivity (believed to be closer to the true resistivity of the sand laminae), and hence a higher hydrocarbon saturation.

Why laminated shaly sands are difficult to evaluate Resistivity logging tools (laterolog and induction tools) have been designed to read as far as possible into the formation, away from the borehole, in order to obtain a reading which reflects the uninvaded (“virgin”) formation zone as much as possible. Because of this great depth of investigation, the vertical resolution of resistivity tools is poor (worse than 6 – 7 ft). In relatively thick beds (thicker than 100 ft) this bad resolution doesn’t cause a problem. However, if the bed thickness is lower than 100 ft, corrections have to be applied. For beds thicker than 20 ft contractor correction charts might be applied for this purpose. For beds with thicknesses between about 2 and 20 ft a mathematical inversion (“deconvolution”) has to be applied: see chapter 13. For beds thinner than 2 ft deconvolution is no longer possible. this is the area where special software maybe applied (Figs. 15). In laminated shaly sands where the sand and shale laminae are (much) thinner than 1 – 2 ft, the resistivity log will read an average reading of the mixture for the total interval. Because in general the resistivity of the shale laminae will be much lower than that of the sand laminae, the electric current will have a preference for going through the shale rather than the sand laminae. Hence, the sand laminae are avoided as much as possible by the current. This means that the resistivity log reading will mainly reflect the resistivity of the shale laminae and is hardly sensitive to that of the sand laminae. Hence, whether the sand laminae contain water of hydrocarbon doesn’t make that much difference to the actual log reading (Fig. 16 and 17). Therefore, the hydrocarbon saturation calculated from Archie would be too low.

Brief overview on how the analysis software works, ref. Figure 18 Suppose we are dealing with a laminated shaly sand sequence with no dip (horizontal layering). If a vertical well penetrates this layer, the electric current from the resistivity tool will flow horizontally (perpendicular to the borehole) and hence it flows parallel to the layering. Because of that the apparent resistivity Rp is that of a parallel resistor network:

Rp = Σ hi / Σ (hi/Ri)

where:

hi = thickness of the individual lamina i

Ri = resistivity of the individual lamina i

If, on the other hand, we are dealing with a horizontal borehole, part of the electric current would flow perpendicular to the laminations, described by a series resistor network:

Rs = Σ (hiRi) / Σ hi

where:

Rs = series resistivity

In the general case of a deviated borehole intersecting a dipping laminated sequence, the apparent resistivity Rα is given by: Rα = Rp / (cos2

α + (Rp/Rs).sin2α)1/2

where: α = angle between borehole and the normal to the laminated

sequence

Copyright 2001 S IEP b.v.

Freeions

Negativelychargedclay surface

Positiveions movingalong claysurface

Sand grainClay

Sand grain

Negatively charged clay surface creates additional conductance path

Figure 1 - Attraction of positive cat-ions (Na+) by negatively charged clay

surface

Copyright 2001 SIEP b.v.

-------

Claycrystal

Watermolecules

OH

H

Clay boundwater layer

- +

Sodium ion

Water moleculesbind to sodium ion

+

Saturation Models: What is Bound Water ?

Figure 2 - Cat-ions (Na+) are surrounded by water molecules because of the dipolar nature of the latter

Copyright 2001 SIEP b.v.

salinity S (g/l)

boundwaterfractionofporevolume

0.00

0.20

0.40

0.60

0.80

1.00

0 50 100 150 200

Thickness of water layerdecreases with

increasing salinity:

Hill, Shirley and Klein:1 - φe/φt = (0.22 + 0.64/ √S)*Qv

Figure 3 - Thickness of Claybound Water Layer as a function of brine salinity

Quartz Clay

Stru

ct. w

ater

Clayboundwater

Connectedpore volume

Isol

ated

por

e vo

lum

e

Φ DENSITY LOG

Φ NEUTRON LOG

Φ TOTAL

Φ EFFECTIVETotally dried core(Historical definition)

Wireline logs

Grain volume

What is porosity?

Figure 4 – Differences between Total Porosity and Effective Porosity

Archie Waxman-Smits

LogRo

Log φ

Rw

* * * * * LogRo Rw

* * * * ***

* ** *

***

Log φ

ShaleEffect

None

Clay

Solids

None

Clay

Solids

c

l

a

y

C

B

WWat

er HC

HC

SwSwt

φ φt

Wat

er

Saturation Models: The Waxman Smits Equation

Figure 5 - Effect of shale on resistivity vs. porosity plot

Additional conductance

More lanes --> less traffic jam.

Equally:more conductance paths -->less resistivity.

Hence, clay conductance leadsto decrease in resistivity.

Described by Waxman-Smitsequation

Saturation Models: Additional Conductance from Bound Water

Figure 6 - The clay-bound water layer acts as an additional conductance path for the electric current, hence the resistivity decreases

B

Rw

Temperature

Figure 7 - “B” chart – B as a function of water resistivity (coupled to salinity)

and temperature

Copyright 2001 SIEP b.v.

Figure 1

Archie fit through clean sands:parameters: m, Rw

Waxman-Smits fit through shaly sands:

parameters: m*, Rw, Qv

10

1

intercept gives Rw

0.10.01 1.0Porosity

Determination of Qv from log response in water zone

slope gives m, m*

0.01

Resistivity

0.1

The effect of theshale: Rt gets pulled

down ---> Qv

Saturation Models: The Waxman Smits EquationThe Effect of Shale on the Resistivity

Figure 8 - Determination of Qv from log responses across the water bearing

zone

Waxman-Smits procedure

Waxman-Smits:

1/Rt = φm*Swn*(1/Rw + B.Qv/Sw)

m* and n* from lab. measurementsRw from Pickett plotB from chart (using Rw and T)Qv from:

1. lab. meas., or 2. water zone, or 3. shale zone (normalised Qv)

Figure 9 - Waxman Smits procedure

Waxman-Smits: Qv from logporosity resistivity

depth depth

waterzone

hydrocarbonzone

porosity

resistivity Rtsaturation exponent n*

porosity

resistivity Rocementation exponent m*

Rw and Qv

Pickettplot

watersaturation

SwWaxman-

Smits

1 2

3 4

B

Figure 10 - Example of Waxman-Smits procedure: Qv determined from logs

Copyright 2001 SIEP b.v.

Density / neutron cross-plot

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.0 0.1 0.2 0.3 0.4 0.5 0.6

Neutron Porosity

Den

sity

Por

osity

Clean sand

Dispersed

Structural

Laminated

Saturation Models: Recognition of Other Shale Distributions from a Density/Neutron Xplot

Figure 11 - The Thomas-Stieber crossplot for Shale Typing 1

Copyright 2001 SIEP b.v.

Neutron porosity (fraction)

Density porosity(fraction)

0.5

0.4

0.3

0.2

0.1

0. 0. 0.1 0.2 0.3 0.4 0.5

Clean sandpoint

Shalepoint

Laminatedshaletrend

Shale fraction fromdensity / neutron cross-plot

Saturation Models: Recognition of Other Shale Distributions from a Density/Neutron Xplot

Figure 12 - The Thomas-Stieber crossplot for Shale Typing 2

Copyright 2001 SIEP b.v.

Archie

Waxman-Smits

extra oil

Water saturation

Res

istiv

ity

100

1

0.1 1

Waxman-Smits gives higherhydrocarbon saturation

Saturation Models: The Waxman Smits Equation

Figure 13 - Application of Waxman-Smits gives more hydrocarbons

Sandstone Qv (meq/ml)

Clean < 0.1Slightly shaly 0.1 - 0.2Moderately shaly 0.2 - 0.3Shaly 0.3 - 0.5Very shaly > 0.5

Saturation Models: The Waxman Smits EquationThe Effect of Qv on Saturation

So

Rw

Figure 14- Example of the influence of Qv on the calculated hydrocarbon saturation So

Copyright 2001 SIEP b.v.

Saturation Models: Reconciliation of Rt in Laminated Sequences

Tool resolution & bed thickness

1. Tool size much smaller than bed thickness: tool reads correctly

2. Tool size about equal to bed thickness: tool reads a bit too low

3. Tool size much greater than bed thickness: tool reads way too low

1 Ohmm10 Ohmm No correction 1 Ohmm

1 Ohmm10 Ohmm Deconvolution 1 Ohmm

1 Ohmm10 Ohmm

EQHCincr = φ*SHC_sand*(1 - Vlam)

Computed virgin zone sand resistivity:should be higher than input resistivity

logHC saturation of sand in virgin zone:should be higher than given by Archie

Figure 15 - Tool Resolution vs. Bed Thickness

Vertical well

Sand resistivity

Resistivity

log reading

0.01

0.10

1.00

0.01 0.1 1 10 100 1000

ideal response

actual response

no sensitivityto sand

resistivity

Example of influence of laminations on log response

Figure 16 - Influence of laminations on the resistivity

Copyright 2001 SIEP b.v.

Laterolog response in laminated shaly sands

Resistivity

Depth

Shale resistivity

Sandresistivity

Laterologresponse

A fewcentimeters

Figure 17 - Influence of laminations on the resistivity 2

shale

sand

shale

Vertical hole:parallel resistors:

plog

sand

sand

shale

shale

p

RR

RV

RV

R1

=

+=

shalesandshale

Horizontal hole:combination ofparallel & series

p

slog

sandsandshaleshales

RRR

RVRVR

=

+=

Deviated hole:shalesandshale

s

p22

plog

RR

sincos

RR

α+α

=

Saturation Models: Reconciliation of Rt in Laminated Sequences

Figure 18 - Calculation of Rt ina Laminated Sequence

8. Gas / oil differentiation

Introduction and Limitations

Hydrocarbon differentiation based on the interpretation of log responses is probably the most widely used method within the industry. In particular the density / neutron separation technique is used very often. In general, the methods used are quite reliable, but as no logging tool provides a direct measurement of hydrocarbon phase properties, the methods do have limitations. These are due to invasion, borehole condition, shaliness, lithology, porosity, thinly laminated beds, critical gas saturation, oil based mud, and hydrocarbon phase behaviour.

Invasion Most logging tools have a depth of investigation that does not extend beyond the "invaded zone". This region is where mud filtrate has entered the formation during the drilling process as a result of the mud column pressure overbalance in the borehole relative to the formation pressure. In the invasion process, the formation fluids (hydrocarbons and/or water) are flushed away by mud filtrate. Hydrocarbon differentiation using density/neutron logs is based on the difference in log resposes between a liquid and gas filled system. Therefore, if the formation is gas bearing and deep invasion has occured, most of the gas will have been flushed away by the mudfiltrate and the logging tools will not be able to detect the gas.

Borehole condition The density and neutron logs are designed to be logged while in contact with the borehole wall. The presence of mud and/or mudcake between the density's skid and the borehole wall influences the tool response such that the gas response may well be obscured. Similarly, an increase in stand-off of the neutron tool can obscure the gas response. While the built-in correction systems and subsequent environmental corrections applied to the raw log readings can correct the logs to some degree, their effective use is dependent on both the operating limitations of the correction algorithms and the accurate knowledge of the basic input parameters.

Invasion and borehole condition are considered to be the two most significant problems related to hydrocarbon differentiation based on log interpretation.

Shaliness In a sand/shale environment, a gas effect on the density/neutron separation has an opposite direction compared to the separation as a result of increased shaliness. In areas where the Gamma Ray is known to be a good shaliness indicator, this is not a major problem. However, in other areas and especially in the exploratory phase, the density/neutron separation is required together with the GR (spectral) in order to reliably determine the shaliness.

Lithology If the lithology is unknown or not accurately known, the same problem exists as with shaliness, in that there are more variables than can be uniquely resolved with the available data. The density / neutron response to dolomite is opposite to that of gas. Therefore, the gradation of limestone into dolomite would obscure any gas effect. In such instances, the Photo Electric Log (Pe) curve recorded with full spectral density tools can provide additional lithology information. However, barite in the mud has a major influence on the Pe curve and some heavy minerals have major influences on both the density and neutron logs. Sidewall sampling may reduce the magnitude of the problem by providing both lithology information and hydrocarbon shows.

Porosity The hydrocarbon responses are dependent upon the volume present in comparison with a water filled system. In low porosity rock, the total volume available to fluids is low and therfore any response to hydrocarbons is diminished.

Thinly laminated beds In thinly laminated sequences, the limited vertical resolution of the logging tools may result in a "smeared" log response which obscures any gas effect. High resolution sampling of the log data can improve the situatution in some cases.

Critical gas saturation The critical gas saturation is a commonly used term, but in the context of hydrocarbon differentiation, it refers to the minimum saturation that has to be present for gas to be detected. It is dependent upon all of the factors dealt with in this section and the type of tools plus detection technique being used.

Oil based mud The relatively low density of oil based mud filtrate has an influence on the density tool response when compared to the response in a water based mud environment. The bulk density values will be lower in an oil based mud environment leading to a gas like separation between the density and neutron logs. In such cases, the "character" of the separation is more indicative of gas rather than the absolute magnitude of the separation.

Hydrocarbon phase behaviour. Regardless of what properties a log evaluation may indicate, it remains an interpretation of indirect measurements which are ultimately tested by production at surface. In some instances, hydrocarbon phase behavior may result in the surface production stream being composed primarily of gas wheras the log indications are of a liquid filled system. For example, a reservoir that is close to bubble point and has a high solution gas content would produce with a high gas/oil ratio which could not be predicted by log evaluation methods. Deep, high pressure gas reservoirs may also appear to be liquid filled based on log response, as the in-situ gas density could well be very close to that of a light, liquid hydrocarbon. In such an environment, it is quite often the case that the nature of the hydrocarbons can only be conclusively defined by production testing.

Relation between log measurement and hydrocarbon type

Neutron Logs The neutron tool response is primarily dominated by the "Hydrogen Index". The replacement of liquid by gas reduces the hydrogen index. Therefore, gas bearing reservoirs have low, apparent neutron porosities. Modelling and experimentation has shown that the effect of gas on neutron logs is greater than would be expected by taking into account only hydrogen index considerations. The so called "Excavation Effect" is used to account for this discrepancy. Also, shale, lithology and neutron absorbing trace elements all have an influence on the neutron response. For these reasons, confident hyrocarbon differentation, lithology and porosity determination can only be made when neutron data is used in combination with other log information.

Density Logs In porous formations, the difference between the bulk density as measured by the tool in a water filled system compared to a water plus oil filled system is very small. However, if gas is present in the pore space, the measured bulk density can be significantly less than in a liquid filled system. This is the basis for hydrocarbon differentiation using the density tool and when used in combination with a neutron log usually provides reliable results.

Sonic Logs The gas effect on the acoustic velocities is a complex process, and surprisingly the most significant effects occur in the low gas saturation range. In general, gas in the pore space results in a decrease in compressional velocity i.e. longer transit time and attenuation of the compressional wave. This commonly leads to cycle skipping in compressional velocity tools. The modern array devices do not, in general, suffer from this problem as compressional velocities are derived from the wave form correlations rather than arrival picks. In theory, there should be no gas effect on shear velocities as fluids do not support shear wave propagation. Also as the Stonely wave is a borehole surface feature, it too should be free of gas effects.

Hydrocarbon Differentiation Methods

Neutron/Sonic Neutron/sonic crossplotting is the oldest method for hydrocarbon differentiation using open hole log data. It was used quite extensively in the early 60s. In principle, it is very similar to the neutron/density methods used today. Gas bearing zones are recognised by their anomalously low neutron porosities and the sonic may show a slightly higher porosity than would be expected for a liquid filled system. The first stage in applying this technique is to calibrate both logs in terms of porosity. A sonic to porosity transform can either be based on core data available in the well being evaluated, or through transforms determined in modern wells. In clastic environments, the sonic/porosity transform will invariably be non-linear due to compaction effects. Raymer-Hunt transforms are therefore prefered over Wyllie time averaged transforms. The neutron log should then be calibrated against the sonic derived porosities or core data. The calibration points should preferably be

limited to clean water bearing intervals as this will ensure that the logs are not influenced by hydrocarbon or shale effects. Once both logs have been satisfactoraly calibrated, a crossplot of neutron versus sonic porosity should be constructed for identifying gas zones. Some scatter will always be present and the interpreter should consider displaying confidence limit lines on the crossplot in addition to a regression line. Accurate depth matching is vital. Shaly zones are problematic in that the gas effect on the neuton porosity is supressed. Cavities behind the casing would also influence the neutron response. As with modern tools, some uncertainty will always be present and the interpreter should check other data sources such as sidewall samples.

Sonic/Resistivity Sonic/resistivity comparison is another old method that still can find modern application. It is best applied as an overlay technique and also provides a quick look identification of hydrocarbon bearing zones. In water bearing intervals, the lateral deflections due to porosity changes on a resistivity and sonic log are very similar in magnitude, when displayed on standard scaling. If the logs are adjusted to overlay in water bearing zones, hydrocarbon bearing zones will be evident by a rightwards deflection of the resistivity log. Gas bearing zones can be identified by a tendency for the sonic to shift to the left due to the slowing of the compressional wave. Thus in gas bearing intervals, the separation between the sonic and resistivity will be greater than in oil bearing intervals. The method is not as sensitive as other differentiation mehtods, but if a well has only been logged by an induction/sonic/gamma ray combination as is very common in top hole or non-objective sections in exploration wells, there is little option but to use this method. An example of the typical responses is shown in below.

Density/Gamma Ray In some older wells (pre 1975), it is not unusual to find that a neutron log was not run over hydrocarbon bearing intervals. The reasons are not always clear but range from tool failure to shows in sidewall samples being considered by the operator to be a more cost effective hydrocarbon differentiation method! In such wells, particularly in a deltaic clastic environment, the density and gamma ray log responses track each other very closely due to shale plugging of the pore space being the primary contributing factor to porosity degradation. The technique is best applied as an overlay technique by shifting the logs to overlay in water bearing sands. In oil bearing sands, the overlay will continue but in gas bearing sands, the density will shift to the left. An example is shown below. This technique gives fairly reliable results when used in combination with other data sources such as sidewall samples. However, it is not appropriate for use in clean carbonate environments.

Density/Neutron: preferred method !

The density/neutron differentiation method is based on the separation between the logs due to the hydrocarbon influence on the two measurement principles. The standard presentation for the logs when run in combination, are such that the magnitude of lateral deflection caused by porosity changes are similar for both

The density/neutron log combination remains the most widely used hydrocarbon differentiation method and in general gives quite reliable results.

logs. It is normal practice to present the logs on a "limestone scale" such that both curves would overlay each other in clean, water bearing limestones. If the logs are presented on a limestone scaling, in a clastic environment, due to lithology effects, the density curve will lie to the left of the neutron, whereas in dolomites, the response is opposite. In primarily clastic environments, some operators may elect to present the logs on a "sandstone scaling" such that both curves would overlay in clean liquid bearing sandstones. It is clearly essental that the petrophysical interpreter is aware of what scale presentation is being used when a quick look evaluation of log data on a print is being made as lithology separations could incorrectly be interpreted as being due to hydrocarbon effects. The presence of gas in the zone of investigation causes the density log to read a low bulk density and the neutron log a low neutron porosity. The standard scaling presentation results in the classic gas separation as shown below for a SE-Asia clastic sequence.

It should be noted that the gas separation is diminished in the shalier sands, as indicated from the gamma ray log. The shale effect can usually be accounted for by using a crossplot of density/neutron separation versus gamma ray readings. The crossplot for the log display above is shown below. Water or oil bearing points define a liquid filled porosity line and gas bearing zones are displaced from it.

In mixed lithology carbonate sequences, the interpretation problems are more pronounced, as the gamma ray log is no longer a reliable lithology indicator. The photo electric curve can provide lithology indications although the presence of barite has a strong influence on the log response. An M-N crossplot is another potential evalution method when the sonic is also included in the evaluation suite (The M-N crossplot is discussed in several standard reference books; M and N should not be confused with Archie's m and n factors !). However, the petrophysicist can often be faced with the problem that no crossplot method gives a clear interpretation indication and log character plus cuttings information may be the only differentiation method available. Gas bearing zones tend to have a distinctive gas character in addition to the separation previously mentioned. The density and neutron logs frequently exhibit an anti-correlation response due to the combination of the gas effect and the scaling presentation. It is this anti-correlation effect that frequently is the primary indicator of a gas filled zone as the use of oil based muds or other effects can produce a substantial separation between the neutron and density logs. An example of this anti-correlation effect is shown below.

Neutron Countrates The long and short spacing count rates acquired with any typical dual spaced neutron logging tool can be used to provide an additional indication of hydrocarbon type. The principle is based on the long spacing counts being more influenced by gas than the short spacing count rates. If the count rates are displayed in a depth plot and scaled such that they overlay in liquid filled zones, the curves should separate in gas bearing zones due to the long spacing detector count rates

increasing in response to the reduced hydrogen concentration. An example of such a depth plot display is shown below.

Crossplots of long versus short spacing count rates can also be used, as shown below. Liquid filled zones define a liquid bearing region on the crossplot and gas bearing zones plot outside of this region. As with other methods, the technique is not foolproof and count rate separation can be caused by other influences such as tight streaks and bedding effects.

Compressional/Shear Velocity Ratio There are various methods to predict/correct the compressional velocity for gas effects, the most commonly used being "Gassmann Substitution", which shows that the major effects occur at low gas saturations (<10%). As sonic tools are very shallow reading devices and flushed zone saturations are difficult to calculate with high confidence, it is not recommended to use the Gassmann equation to correct the gas effected sonic back to a liquid system. The more appropriate usage of the Gassmann equation is to correct liquid pore filled sonic velocities to a gas saturated system for the production of well synthetics for comparison with surface seismic. With the introduction of full waveform recording acoustic tools, wellsite recording of compressional and shear velocities is possible. The comparison of these velocities can be used as a hydrocarbon differentiation technique based on the slowing of the compressional velocity if free gas is present in the zone of investigation. The technique is best applied as an overlay or crossplot technique when gas bearing zones should be evident by lower compressional velocities. Operators have reported mixed success using this technique.

NMR logging The new technique of NMR (Nuclear Magnetic Resonance) logging has been successfully used to detect gas bearing zones, using the so called diffusion-gradient technique. Research on this topic is ongoing.

Relative Accuracies & Conclusion/Summary

All of the above methods are based on the interpretation of log responses as no logging device provides a direct measurement of hydrocarbon density. They are all subject to borehole influences which can mask the formation and hydrocarbon response such that no confident interpretation can be made.

Of the methods outlined, the density/neutron separation method is the most reliable as the tool response and presentation scaling work in opposite directions under the influence of gas. However, washouts and/or deep invasion will strongly influence the hydrocarbon response. As neutron logs are the deepest reading porosity devices, they are the least effected by borehole effects and therefore their use in isolation (count rates) or in combination with a sonic tool is probably the next most reliable technique. The comparison of density and gamma ray logs is restricted to clastic environments and the resistivity/sonic combination should only be used if no other log information is available.

Regardless of what technique is used, the interpretation will be the most robust if account is taken of other information such as shows in cuttings and/or sidewall samples.

9. Wireline Formation Testing

Summary

Wireline formation testing (WLFT) logging tools (such as the MDT - Schlumberger and the RCI – Baker Atlas) are used to measure formation pressures as a function of depth and to obtain formation fluid samples at various selected depths. Moreover pressure drawdown and build-up response tests can be obtained as a function of time, from which permeability can be derived. Plotting the pressures obtained versus depth will reveal the fluid pressure gradients for the various logged intervals. Such gradients reveal the type of fluid, as the pressure gradient is directly related to the fluid density. Hence, from such plots the fluid interfaces can be obtained. A pressure versus depth plot over an oil/water interface will reveal the so called "Free Water Level": FWL. This may lie a bit deeper than the Oil / Water Contact (OWC) revealed by the resistivity logs. The logs respond to the actual presence of the fluid interface. This interface is a bit higher than revealed by the pressure measurements because of capillary forces. Hence, the distance between OWC and FWL is directly related to the capillary entry pressure of the rock.

Wireline Formation Testing (WLFT)

WLFT tools can make a series of spot measurements of reservoir pressures in open hole. They can also retrieve one or several sample(s) of reservoir fluid each run.

Tool Principle A schematic drawing of a WLFT is shown in Fig. 1. A probe is pushed against the borehole wall at the selected depth. The probe must pass through the mudcake and make contact with the formation. A packer isolates the probe from the mud pressure (Pm) in the borehole. At the start of the measurement, the pressure gauge reads the mud pressure. After closing the equalising valve, a pressure drawdown is created by retracting cylinders 1 and 2. As a result the formation will start flowing through the probe. After both cylinders are fully retracted (total volume = 20 cm3) the formation is allowed time (build up period) to equalise the pressure in the tool to the formation fluid pressure (Pf). The speed with which the formation will equalise the pressure indicates its permeability. Anomalies - If the pressure returns to the (higher) mud pressure the packer failed to isolate

the probe (seal failure). - In tight (impermeable) formations the pressure of the invasion fluid may not be

disseminated completely (super charged formation). If this is the case the recorded pressure will be in between the formation and the mud pressure. In a

pressure/depth plot these (failed) measurements will clearly deviate from the prevailing formation gradient.

Pressures in the subsurface Except in oil and gas reservoirs, all pore space in the subsurface is filled with water. In most cases the pressure (P) in water bearing formation is hydrostatic and its gradient depends on the density (ρ) of the formation water. Pressures recorded in a water bearing interval will plot in a pressure/depth plot on a straight line. The slope of this line determines the water gradient and therefore its density: Fig. 2 (the water density is a function of its salinity).

Fluid gradient = dP/dD = ρ g (D = depth; g = gravitation constant) At the interface of the water and oil columns, the pressure in the oil will be equal to the pressure of the water. This level is called Free Water Level (FWL). The OWC is slightly above the FWL due to water pulled up by capillary forces. In the oil column the pressure will follow the (steeper) oil gradient. At the GOC the pressure in the gas is equal to the pressure in the oil. In the gas column the pressure will follow the (much steeper) gas gradient. As a result the pressure in the oil and the gas is higher than the hydrostatic pressure at the same depth. This overpressure is contained by the caprock at the top of the reservoir.

Evaluation Objective of the WLFT tool - Determination of reservoir pressures. - Confirmation of the fluid type, evaluated from other logs. - Calculation of the oil- and gas- densities at reservoir conditions. - Determination of the FWL's, GOC's and GWC's. - Indication of the reservoir permeability. Evaluation Technique - Plot all recorded pressures in a pressure/depth plot. - Draw straight lines through the points from a reservoir interval. - If the pressures of reservoir intervals with the same fluid type fall on one line, they are probably in pressure communication. - If the pressures of reservoir intervals with the same fluid type fall on different lines, they are part of different fluid columns. These columns may have different contacts. - The depth where the gradients of the water and the overlying oil column intersect, is the FWL. (~ equal to OWC, if capillary effects can be neglected). - The depth where the gradients of an oil column and the overlying gas column intersect, is the GOC. Remarks:

- Modern tools like Schlumberger's MDT,Baker-Atlas' RCI and Halliburton’s RDT have multiple chambers and many more possibilities. Depending on the porefill good quality PVT samples can be retrieved.

- Appendix 1 is a SPE paper on the risk assessment of differential sticking of wireline formation testing tools.

Figure 1 - RFT Pressure Measurements

Figure 2 - Fluid Distribution from a Pressure vs. Depth Plot

10. Nuclear Magnetic Resonance: NMR

Summary

NMR (Nuclear Magnetic Resonance) is a powerful new logging technique with the following features:

• It identifies how strongly hydrogen atoms are bound to their environment.

• Hence, it discriminates between: * free fluids in the pore space * water that is bound to pore walls or to clay.

• Therefrom, one can derive: * effective, lithology independent porosity (calibration free) * mobile fluid or Free Fluid Index (~ initial water saturation) versus bound fluid * permeability (and pore size distribution)

• More advanced applications are available with special(“gradient”) tools, which can follow diffusion of hydrogen atoms. This allows gas/oil differentiation.

Hence, the tool / technique offers the following main measurements and/or applications - lithology independent porosity - pore size distribution - permeability - free and bound fluids - fluid type (gas versus oil versus water) - fluid properties (e.g. viscosity)

References

- Oilfield Review, Autumn 1995, pp. 19-33 - The Log Analyst, Special Issue on NMR logging, Vol.37 No. 6, November-

December 1996

NMR principle

An NMR tool consists of a strong static magnet that can polarise hydrogen nuclei (which have nuclear spins acting like little magnets) into one direction, and a pulsable radio-frequency magnetic coil system which can flip the hydrogen nuclear spins temporarily into another direction, perpendicular to that of the static field (Fig. 1). Fig. 2 gives an outline of the basic steps involved, which are as follows: First, the randomly oriented hydrogen nuclei (protons) are polarised with the static magnetic field Bo. This will cause precession (just like a spinning top) of the nuclei

around an axis with the direction of the static field. The precession takes place with the so called Larmor frequency which is proportional to the static magnetic field strength. Subsequently a short radio-frequency electromagnetic signal is applied using a pulsed magnetic field B1. This causes the spins to rotate about the axis of the new field B1. The rotation angle depends on the duration of the RF signal. This duration is chosen such that the spins are flipped over 90 . The precession of the spins (with the Larmor frequency) now takes place in a new plane, perpendicular to the direction of the static magnetic field. Spins now rotate in xy plane (Larmor frequency). This precession gives rise to a detectable RF signal in the receiver coil (the coil is located in such a direction that it didn’t pick up the original precession around the Bo field).

After the B1 RF pulse has been swithched off the spins will not stay in the new direction (perpendicular to the Bo field), but will decay back to the original direction (precessing around the Bo field). Hence, the measured RF signal will decay as well. The decay is due to several effects, and a special pulse sequence has to be applied to measure the relevant decay curve(see further below, and Fig. 3). The decay curve (Fig. 4) can only be measured starting at a certain time after the pulse, such that the very rapid decay due to Clay Bound Water is not detectable. Hence, extrapolation of the decay curve to time zero yields the effective NMR porosity rather than the total porosity (measured by the density log). The late (slower) decay gives information on movable fluids: extrapolation of that part to time zero gives the Free Fluid Index FFI. The measured decay curve can be converted to a spectrum that is related to pore size. Herefrom permeability can be calculated (see further below).

Contractor tools Currently tools are available from Schlumberger (Fig. 5: the Combinable Magnetic Resonance tool, CMR) and Halliburton (prev.Numar) (Fig. 6: the Magnetic Resonance Imaging Log, MRIL). The latter is also available from Baker Atlas. Schlumberger’s CMR tool is a pad tool which means that it is only reliable in a very good (non-rugose) borehole. Halliburton’s MRIL tool is centralised, reads a little bit deeper into the formation, and hence is less influenced by borehole quality. Moreover, the MRIL tool makes use of a gradient magnetic field, such that special applications are available (see further below). Therefore, for fluid identification the MRIL normally is preferred over the CMR; for the standard application (BVI mode) both tools are perfectly suitable.

Relaxation mechanisms The relaxation of the nuclear spins back to the original static field direction is described by two relaxation times, T1 and T2.

T1 describes the longitudinal relaxation, i.e. the decay in the direction along Bo. This is a build-up time, because the spins are coming back (after switching off the RF pulse) from the perpendicular direction to this Bo direction. T1 is governed by the spin/lattice relaxation, which is the effect of averaging (randomising) the

direction by neighbouring spins and by magnetic impurities at the pore wall. T1 takes a long time to measure, hence it can only be assessed while the tool is stationary. T1 is not affected by magnetic gradients.

T2 describes the transversal relaxation, i.e. the decay in the direction perpendicular to Bo. This is a true decay time, because the amount of spins in that direction will become less and less as the spins are coming back to the Bo direction. T2 is governed by spin/spin relaxation, which is the effect of dephasing, mainly due to magnetic impurities. T2 is normally different from T1 because of small additional magnetic impurities (leading to localised magnetic gradients) that do not affect T1.T2 takes less time to measure, and hence can be measured while logging. T2 is affected by gradients via the dephasing mechanism.

Normally decay time T2 is of most interest. T2 is governed by the following relaxation mechanisms (Fig. 3): - Bulk relaxation, which is the relaxation taking place in the bulk fluid (e.g.

water). - Surface relaxation, which is the relaxation taking place at the pore wall. This is

due to paramagnetic impurities (Fe++). This mechanism is normally much faster than bulk relaxation, and is proportional to the surface to volume ratio of the pore, hence it is inversely proportional to the pore size. This is a basis for permeability measurement.

- Diffusion, taking place because hydrogen atoms may diffuse out of the measurement region, thus leading to (apparent) decrease of signal, i.e. decay. This only happens if a gradient field is available.

Pulse echo trains

T2 can be measured much faster than T1. However, T2 is influenced by small magnetic impurities (localised magnetic gradients), leading to dephasing (Fig. 7) such that T2 is much shorter than T1. We can exclude this effect (leading to a T2 which is about 2/3 of T1) by using the so called Carr-Purcell pulse echo technique (Fig. 8). In this technique a 180 degrees pulse is applied when the spins have been dephased, leading to a rephasing of the spins, thus counteracting the effect of those impurities. Applying many of these 180 degrees pulses, leads to a decay curve that is slower than it would be without applying this technique: Fig. 4 shows the thus resulting decay curve, the peaks under the curve are the 180 degrees pulse echo signals.

Pore size distribution The decay curve obtained from the pulse-echo technique (Fig. 4) gives the signal strength (intercept with the vertical axis), from which porosity and Free Fluid Index are derived, and the shape of the decay curve (decay times) from which the pore size distribution can be obtained. Small pores have a large surface to volume ratio and hence a short decay time (Fig. 3). Large pores have a small surface to volume ratio and hence a long decay time. A real rock consists of pores of many different sizes leading to many different

decay times. Each decay time gives rise to an exponential signal with a specific T2 (which is that decay time). Hence, the total (measured) NMR decay curve can be decomposed into many individual exponential decay curves, each with a specific T2. This means that if we make a plot of the amount of signal that has a specific decay time (vertical) versus that decay time (horizontal) we can see whether we have small or big pores or a combination of the two (Fig. 9). Such a plot is called an NMR spectrum and is obtained by means of inversion (Fig. 10). Hence, inversion of the NMR measured decay curve (Fig. 4) will give an NMR spectrum (Fig. 10) which can be related directly to a pore size distribution because of the mathematical relationship between pore size (related to surface to volume ratio) and T2 (Fig. 3).

A typical NMR log will display the decay curves and the spectra derived from these curves for several depths (Fig. 11).

Permeability Permeability can be derived from NMR measurements using one of the following two relationships:

1. k = (φNMR/10)4 (FFI/(φNMR – FFI))2

2. k = constant φNMR4 T1,2

2 (in this relationship either T1 or T2 can be used)

Advanced applications If hydrocarbon replaces water, the total water signal decreases, and the surface / volume ratio (for water) increases (because the water volume decreases), hence the water peak will move in the spectrum to a lower T2. The oil peak won’t move, because its signal is governed by the bulk relaxation (oil doesn’t contact the wall, and there is no relaxation at the oil/water interface. This leads to two techniques for hydrocarbon assessment: 1) Multi-wait time: using different wait times between the several full pulse-echo

trains, differences in T1 [build-up time] can be measured. This differentiates between water and oil.

2) Multi-interecho time [gradient is required !]: using different times between the individual pulse-echos in a Carr Purcell sequence, the effect of diffusion can be assessed. This differentiates between water and gas (because their diffusion constants are quite different).

Fig. 1 Generic NMR logging tool

N S

Pulse generator

Receiver

BoM

Bo Bo

Bo

M

At equilibrium After pulse

Borehole

Fig. 2 NMR: Nuclear Magnetic Resonance

Each H-atom has anuclear (proton) spin

1) No tool present:Nuclear spins notaligned

2) Tool present:Spins aligned by static magnet

3) Apply RF pulse:Spins swept to newdirection

4) Spins decay to old(static field) direction,giving off RF signal

5) Measure decay of RFsignal vs. time:gives info on amountof “binding” of H-atoms

6) Herefrom: calculatepore size distribution

new

new

time

pore size

signal

number of pores

old

pulse

signal old

Fig. 3 RELAXATION in ROCKS

1 cm 0.1 mm

T ≈ 1 - 3 sec2, bulk T 2 T 2, bulk

1 1= + ρ S / V

Bulk fluid Fluid in pores

Fe++

Surface wetting

Paramagneticimpurities

The Free Fluid Index concept

Clay bound water

Capillary bound water

Moveable fluids

Time (ms)0 2 30 60

Φtotal

ΦNMR

FFI

0

Determination of FFI from NMR echoes after t=30 msand of effective porosity ΦNMR from first echoes

Fig. 4 The Free Fluid Index (FFI) Concept

10 cm

Sensed volume

Eccentralised position ==> less sensitive to low Rm

Larmor frequency : 2 MHz Top view

Goodvertical resolutionbut very shallowreading

Borehole

Detector

15 cm

Fig. 5 Schlumberger CMR tool

Fig. 6 Numar NMR tool (MRIL- C++)

35/40/50 cm

Sensed volumes

Borehole

Centralised position ==> less sensitive to rugosity

Larmor frequency : 0.75 MHzTop view

N S

N S

Radius

BFieldgradient

60 cm

(24 inch)

Fig. 7 Basics of pulsed - NMR

Bo

B1

M

t = 0.1 ms t = 20 ms t = 100 ms

t = 0

90pulse

de-phasing

o

T

T

1

2

Signal

No signal

Fig. 8 How echoes are created

de-phasingB1

180pulse

o

re-phasing

NMRsignal

real time

NMRsignal

real time

NMRsignal

real time

+ =

NMRspectrum

decay time

Smallpores

Bigpores

Totalpore system

Smallpores

Bigpores

Totalpore systemNMR

spectrum

decay time

NMRspectrum

decay time

+ =

Fig. 9 Relation between signal decay and NMR spectrum

Fig. 10 Standard T2D inversion

M t AeitT

i

nDi( ) =

−

=∑ 2

1

02468

1012141618

0 100 200 300 400Time (ms)

M(t)

(PU

)

0

0.4

0.8

1.2

1.6

0.1 1 10 100 1000 10000T2D (ms)

Am

plitu

de (P

U)

A i

Fig. 11 NMR in a water bearing sandshowing poresize variations

GR

Neut

Dens Rt Echoes

BVI

MPHI Spectrum

10000.1

60 0

1.7 2.7 00

0

0200ms 0.1 10000ms100

f t

30

30

11. Wellbore seismic

Summary

Petrophysicists often work together with geophysicists / seismologists in the exploration phase for various purposes: - Generation of a time-to-depth conversion curve, to convert seismic horizons

from two-way travel time to depth (Z-T curves) and/or to convert logs (in depth) to time: this is normally done using checkshot data combined with sonic log data. Checkshots use surface acoustic sources and downhole geophones to measure integrated sound velocities at specific depth points. The sonic is used to interpolate between such discrete points.

- Generation of synthetic seismograms: using the sonic and the density logs a reflectivity curve can be generated. Filtering this curve down to seismic frequencies gives a log derived seismic display which can be compared to the real (surface) seismic, e.g. for modelling purposes, quality control, etc.

- The influence of the pore fluid type on the seismic can be modelled using the Gassmann equation.

These topics are dealt with in the current chapter.

Petrophysics and seismic

Petrophysical logs are acquired in the borehole and investigate typically an area of one to several feet away from the borehole. Hence, their depth of investigation is extremely limited compared to seismic (kilometers). On the other hand log resolution can range from metres (resistivity tools) down to centimetres (borehole imaging tools), which compares favourably to seismic resolution (typically 15 metres, at best 5 metres): see Figure 1. Typical petrophysical items related to seismic are: - Generation of a time-to-depth conversion curve, using checkshots. - Generation of synthetic seismograms.

- Assessing the influence of the pore fluid type on the seismic using the Gassmann equation.

Checkshots In a checkshot survey, a surface acoustic source (e.g. airgun) is used in combination with downhole geophones to measure integrated sound velocities at specific depth points. Hence, the one-way travel time is measured (from surface source to borehole geophone). This time has to be multiplied by a factor of two to compare it to the two-way travel time measured by seismic.

Apart from measuring the first arrival transit time only, the checkshot survey can also be used to analyse the full wave train. This is called Vertical Seismic Profiling (VSP): it can be analysed in terms of up and down going (acoustic) events and thus yield a seismic-like image. VSP will not be discussed here.

In order to compare checkshot data to sonic log and/or seismic data several factors have to be accounted for: - The difference between seismic reference datum (normally sea level), ground

level (from which the checkshot is measured) and the Derrick Floor Elevation (from which the logs are measured), as well as the difference between True Vertical Depth Sub Sea (seismic & checkshot) and Depth Along Hole Below Derrick Floor (logging depth). Moreover, if the well is deviated, the checkshot source should preferably be perpendicular above the downhole geophone, and hence the source has to move (“walk away”) when the geophone location is changed. Otherwise a correction has to be made for the non-verticality of the acoustic waves going from source to geophone.

- Both the sonic and the checkshot measurement should be checked and corrected for “cycle skipping” and “noise peaks” (see Figure 2), as well as for other obvious errors. This is normally done manually, and is therefore called “Mechanical Editing”. Typical things to be done are: depth matching, joining of curves, removal of casing shoes effects and removal of cycle skips & noise peaks. Other means of editing are “Interpretive editing” (using trend curves or inter-log relationships) or modelling (e.g. using Gassmann: see further below).

The Z-T (Depth-Time) relationship Once the checkshot and sonic log data have been edited and corrected satisfactorily, the semi-continuous sonic log (typically 2 samples per foot) can be used to interpolate the discrete checkshot data points (typically 1 sample per 200 metres): see Figure 3. However, the sonic data might differ from the checkshot data. The relative difference between the two way (seismic) time determined from the check shots and the sonic log is referred to as drift. Drift is often caused by alteration of the borehole wall during drilling and is normally most noticeable in shale sections. This alteration results in integrated sonic times being longer than the check shot times and hence is termed negative drift. Other reasons for negative drift may be cycle skipping & large borehole effects (Figure 4), or non-vertical alignment of the checkshot source/geophone system. Positive drift is mainly attributed to frequency effects i.e. higher frequency sonic waves (20 - 30 KHz) travel faster than the lower frequency seismic waves (60 Hz). In deviated wells, lateral velocity changes can also account for positive drift. The drift curve is mainly used to isolate anomalous checkshots, e.g. due to erroneous picking of first breaks (first arrival), reflections and multiples (multiple reflections) close to formation boundaries or checkshots having spacings less than 200 ft.Once all errors have been removed, the sonic can be force fitted through the checkshot points.

Synthetics

Application From sonic and density logs a synthetic seismogram can be constructed (see below) that can be used: - as a quality control on the actual surface seismic data - study the impact of seismic processing, e.g. use of zero phasing (see below),

justification of pick criteria, etc. - for modelling studies, e.g. calculating the senstivity of the seismic to changes

in fluid type, fluid content, etc.

Impedance and Reflection Coefficient Acoustic waves travelling through the sub-surface will be reflected by and/or transmitted through a lithological boundary depending on the difference in acoustic impedance of the adjacent layers.

Acoustic impedance (Z) is defined as:

Ln(density * velocity) 1)

It is standard practice to normalise the impedance w.r.t. water velocity (+/- 4921 ft/sec):

Ln((density * velocity)/4921)) 2)

If the sonic data is in μsec/m the water velocity is 1500 m/sec.

The reflection coefficient (R) between two layers is defined as:

R = (ρ2V2 - ρ1V1) / (ρ2V2 + ρ1V1) 3)

where ρ and V are the density and propagation velocity of a given layer. Subscript 1 denotes the top layer and subscript 2 the bottom layer. From the formula, it can be seen that in the case of an increase in impedance (ρ2V2 > ρ1V1) R is positive.

As (ρ2V2 - ρ1V1) is usually small compared with either ρ2V2 or ρ1V1, R can be closely approximated by:

R ≅ ΔρV ≅ ΔLn(ρV) = ΔZ 4)

2ρV 2 2

Conventionally, (and in many seismic applications) the computation of reflection coefficient (R) from log data is taken as half the difference in normalised acoustic impedance between successive intervals.

The reflection coefficient is subsequently used to compute filtered time synthetics for comparison with seismic data in a reflectivity section.

Seismic phase The seismic phase describes the shape of the seismic wavelet. In terms of what actually happens, seismic sources are minimum phase, i.e. the wavelet starts at time zero. However, seismic interpretation is much easier if the loops are identified by looking at the maximum amplitude. Taking the maximum amplitude (peak) position as time zero is called zero-phasing, and this is the normal procedure.

Polarity Conventions of Seismic and Well Synthetics When surface seismic traces are being compared with well synthetics, polarity can be a source of major confusion. It is essential that the convention used in the production of a well synthetic is fully understood by both the petrophysicist and the seismic interpreter.

As discussed in the previous section, an increase in acoustic impedance results in a positive reflection coefficient. A seismic wave reflected from a low to higher impedance interface (hard kick) will have the same polarity as the incident wave. If the seismic source is an explosive device (normal situation), the first detected motion will be a compression event. In both land and marine seismic, the Society of Exploration Geophysicists (SEG) have standardised on the SEG Acquisition Convention that an upward motion detected by a geophone or a pressure increase detected by a hydrophone will be recorded as a negative number. Such a motion or pressure increase is the direct result of a compressional event.

The SEG Acquisition Convention for plotting zero phase reflectivity seismic traces is for negative values to be displayed to the left and positive values to the right, with black shading between the zero line and the positive amplitude peak. Therefore, the reflectivity trace of a seismic wave reflected from a layer of increased impedance (hard kick) will be displayed on a zero phase reflectivity seismic trace as a white negative loop centred at the layer interface with adjacent pre- and post-cursors as black positive peaks. The reflectivity trace for reflection from a layer of decreased impedance (soft kick) will be the opposite. The acoustic impedance, reflection coefficient, recorded reflectivity and seismic trace display for both cases are shown in Figure 5.

Note that the above illustration is the SEG Acquisition Convention. For plotting seismic traces and well synthetics there is also in the industry a SEG Positive Polarity Plotting Convention which is totally opposite to that described above i.e. a hard kick on a zero phase reflectivity seismic trace is plotted as a black loop! The polarity convention used will normally be indicated on the seismic trace print.

Filtered Time Synthetics In order to compare the synthetics determined from log data with seismic data, the synthetic has to be convolved with a filter that mimicks the filtering effect that the earth layers have on seismic waves. The Butterworth -3 dB and Butterworth Trapezium (Figure 6) are the most commonly used. The required filters and filter parameters should be discussed with the seismic interpreter. Both filters are used to define a trapezium shaped boundary on an amplitude/frequency crossplot. Any data outside this boundary (low and high frequencies) will be excluded.

In the Butterworth -3 dB, the filter specifications are expressed as two anchor points at -3 dB (points B and C of the trapezium shape) with the slopes of the two sides of the trapezium being defined by slope order expressed in dB/octave divided by 6. The spectrum length will be usually either 1024 or 512 and zero phase with no amplitude attenuation should normally be selected.

In the Butterworth trapezium, the filter is specified by defining four corner points (points A, B, C and D). Filter length, phase and normalisation should be set as for the -3 dB filter.

A summary of the steps involved in synthetic generation is given in Figure 7.

Gassmann fluid replacement Gassmann's fluid replacement algorithm has been used since around 1970 to model the effect on seismic response of changes in porosity or fluid content in porous rock. By modelling the subsurface as a packing of rigid sphere's connected by springs and employing the parameters used to characterise elastic media, Gassmann related the compressional and shear velocities of sound in the rock to the bulk moduli of the rock grains, the empty matrix and the fluid in the pore space. The resultant equations contain a number of unknown quantities such as the bulk modulus and Poisson's ratio of the porous rock matrix, but if these parameters can be estimated in a rock of known pore fill then they can be used to predict the effect of changes in pore fill on the sonic velocity and thus ultimately on impedance and seismic response.

Application The Gassmann equations are used to:

- model changes in pore fill and thus predict seismic reponse away from the wellbore on the basis of sonic and density log data. The Figure below illustrates the effect of changes in the pore gas saturation on the compressional fluid velocity.

- remove the effects of mudfiltrate invasion on sonic & density logs during initial processing.

Principle The compressional velocity Vp depends on:

- porosity and density: these are obtained from the density log - Poisson’s ratio of the dry rock: this is normally obtained from correlation Tables - elastic moduli of the solid (obtained from correlation Tables), the fluid (obtained from

Tables and/or from Woods’ mixing law [inverse modulus is linear volumetric average of constituents]) and the dry rock (see below).

Here, the bulk modulus of the dry rock is the only real unknown. It is obtained by measuring Vp in the water zone and applying the Gassmann equation to yield this bulk modulus of the dry rock. Subsequently, all parameter now being known, Vp can be calculated for other values of the water saturation, i.e. in oil or gas bearing rock. The effect will be greatest if 100% water is replaced by 95% water and 5% gas: see Figure below.

The Gassmann equation Gassmann showed that the compressional velocity, Vp, of the rock could be defined as follows:

( )( )⎟⎟

⎠

⎞⎜⎜⎝

⎛

−+−

+=β

ββγρ 1

1 22

BKV s

p

where K = compressibility modulus ρ = density

γ = ( )

m

m

σσ

+−

113

σ = Poisson's ratio

B = ⎟⎠⎞

⎜⎝⎛ −1

f

s

kkφ

φ = porosity

β = kk

m

s

with subscripts s = solid grain material

m = empty matrix (grains + porosity)

f = fluid

Calculation of Matrix Bulk Modulus Many of the parameters in the Gassmann equation can be defined from logs or estimated from known correlations (see below) but the matrix bulk modulus, Km, is dependent on the individual rock and must be derived from a known formation prior to fluid replacement. Rearranging the Gassmann equation, Km can be calculated from the following equation:

( )γ

β−

−+±−==1

12

2 BBAAKK

s

m

where ( )

( )γ

γρ

−

−+=

12

12

BKV

A s

p

Note: Vp in cm/s !

The value of the bulk modulus derived from this step should be compared with the other moduli to check the consistency of the input data. In all cases the following should be true:

K K K Ks m f> > >

where K is the compressibility of the complete fluid filled rock.

Parameters The parameters required to evaluate the Gasmann equation are as follows:

Vp Compressional velocity read from the sonic log

φ Porosity is usually calculated from the density log, ρlog, using

φ ρ ρρ ρ

=−−

ma

ma fl

log

using standard values for, ρma, matrix density (e.g. 2.65 g/cc in sands, 2.85 g/c in dolomite, 2.71 g/cc in limestone). The fluid density, ρfl, is defined as follows:

ρ ρ ρfl w w w hcS S= + −( )1

where Sw is the water saturation and ρw is the brine density which is dependent on salinity and can be evaluated from chart books or RFT gradients. The hydrocarbon density, ρhc, can also be evaluated from RFT or from PVT information

σm Poisson's ratio for the matrix is best calculated from properly QC'd shear logs where these have been recorded

σ =−

−

V V

V V

s p

s p

2 12

2

2 2

but in the absence of shear logs, data can be estimated for sandstones from one of the following correlations:

σ φm = −0 267 0 65. . (consolidated sands) σm = 0 214. (unconsolidated sands)

In the absence of other data a value of 0.25 is normally taken, but in any case 0<σm<0.5.

Ks The grain bulk moduli are typically taken from standard references as follows:

Sandstone 38 GPa Limestone 82 GPa Dolomite 67 GPa

Kf The fluid bulk modulus depends on the fluid type. A typical value for water/brine is 3.1 GPa but this is strongly dependent on salinity, temperature and pressure and values should be derived from available references for all fluid moduli, including oil and gas (see References, especially Batzle & Wang). The PE application PVTPACK is also useful in predicting changes with temperature and pressure. Note that the Gassmann equation is theoretically only valid for single phase fluids and that mixed fluids are assumed to behave as homogenous fluids of the same density. Wood's formula is used to calculate the resultant bulk modulus e.g for gas:

1 1K

SK

SKf

w

w

w

g= +

−

Information on fluid compressibility may be also be available from PVT analysis (K=1/C)

Fluid Substitution

Once Km has been defined, the assumption is made that changing the fluid content has no effect on Km, Ks, σm orφ, and the original Gassmann equation is then used with revised values of Kf and ρ to calculate the new compressional velocity when the fluid content is varied.

Gassmann Fluid Replacement Step by Step

1) Determine values for the bulk moduli of the solid grain material, Ks, and the fluid, Kf, as indicated above.

2) Determine the porosity, φ, from the density log using the appropriate matrix density, ρma, and fluid density, ρfl, calculated from the known fluid make-up.

3) Evaluate the Gassmann parameters B and γ.

4) Evaluate A and β. Note that the selected root for �must be between 0 and 1 in order to ensure that Km < Ks.

5) Calculate a revised ρfl for the new fluid content and a new bulk modulus, Kf.

6) Calculate the new value of log density and B and substitute into the Gassmann equation assuming that none of β, σm or φ are dependent on fluid properties.

Units

In order for the Gassmann equation to be used properly the units used must be consistent. In manual calculation, problems are best avoided if the following units are employed:

Bulk modulus dynes/cm2 Density g/cc

Velocity cm/s Porosity fract

For convenience the following conversions can be used:

ft/s Þ m/s x 0.3048 x1010 dynes/cm2 Þ GPa x 1.0 g/cc Þ kg/m3 x 1000

Gassmann's Assumptions

In deriving his original equations, Gassmann made a number of assumptions which should be borne in mind when carrying out fluid replacement:

1) All pores are connected and the fluid in the pore space is non-viscous i.e. the fluid is in hydrostatic equilibrium at all times.

2) Hooke's law holds for all the components in the system (grain, matrix, fluid, fluid-filled rock):

Δ ΔVV

PK

= −

3) The rock is homogeneous and isotropic on a macroscopic scale.

4) The solid grain material is homogeneous and isotropic.

5) The shear modulus, μ, is independent of fluid content i.e. μ=μm It is also worth noting that fluid substitution is only valid into 100% lithologies. Accounting for mixed lithologies such as shaly sands would require a more detailed approach.

Graphically the effect of gas and oil on Vp and ρ is shown in Figure 8.

Related Equations

The theoretical work behind the Gassmann equation utililise a number of other relations some of which can be useful in determining input parameters for different applications.

Compressional velocity V M Kp = =

+ρ

μρ

43

M K= +43

μ

Shear velocity Vs =μρ

Poisson's ratio σ =−+

=−−

33

2 12

2

2 2K MK M

V VV Vs p

s p

Compressibilities ( )2

,131

spss

ss VK ρ

σσ

−+

=

K Vf f p f= ρ , 2

Copyright 2001 SIEP b v

Figure 1 - Logs and Seismic…a resolution issue

Cycle Skipping

Δt

Near

Far

Δt too long

Noise Triggering

Δt

Δt too short

Near

Far

140 90 40

Δt (μs/ft)

Figure 2 – Noise & Cycle Skipping

Time (sTWT bSRD)0 1 2 3

1000

3000

2000

Checkshots providemaster calibration

Sonic logs interpolatebetween checkshots

Figure 3 - Time / Depth Relationship

Drift (ms)

Interpreteddrift curve

- 0 +

Positive Drift

Zero Drift

Negative Driftsonic time too long(cycle skips, altered formation)

sonic time too short(frequency effects ?)

Tie point

Drift values at check shotsare interpreted with straightlines and knee points at known formation boundaries

Figure 4 - Drift Curves

HARDKICK

SOFTKICK

IMPEDANCE - RFC +RECORDED

REFLECTIVITY- +

SEISMICTRACE- +

WHITELOOP

BLACKLOOP

p y ppSEG Acquisition Convention for Seismic Traces

Figure 5 - Conventions for Polarity

Butterworth Filters

f1

f2 f3

f4

frequency (Hz)

Amp.(dB)

slopeorder f1 f2

frequency (Hz)

Amp.(dB)

slopeorder

-3dB points

Method 2 Slope Order and -3dB Points

Method 1 Trapezium Corner Frequencies

1 order = 6 dB/oct

Figure 6 - Filter definitions

sonic log density log checkshots

edit to match undisturbed formation response

QC with drift curve

generate impedance

⎟⎟⎠

⎞⎜⎜⎝

⎛=

ww

Zvvln

ρρ

generate Z(t) curve

convert impedance to time

generate reflectivity

1122

1122

vvvv

ρρρρ

+−

−=RC

filter to seismic frequencies

Figure 7 - The Synthetic Generation Process

Figure 8 - The Effect of Porefill on Vp and ρ

12. Uncertainty

The role of uncertainties related to petrophysical (and other) evaluations is often underestimated. In many cases it is wise to do a sensitivity study, i.e. to calculate what the impact is of variations of the input parameters (within their error bars) on the output results. Nowadays, with modern computer power sensitivity studies are often made using Monte Carlo methods, i.e. generating many possible models resulting from statistically probable combinations of variations of the input parameters. The output results together build a cumulative distribution function for the major output parameters. The hydrocarbon volume HCVOL of a reservoir is determined from:

HCVOL = A * h * (N/G) * φ * (1 - Sw) where: A = area of the reservoir h = thickness of the reservoir (gross) N/G = net over gross ratio φ = porosity (fraction) Sw = water saturation (fraction) Shc = 1- Sw = hydrocarbon saturation (fraction of pore volume) Below some general thoughts and considerations are given on the accuracy/uncertainty in each of those parameters. Assessment of uncertainties (and related accuracy/precision) and quality control is an essential task of each petrophysicist (petroleum engineer) and is often valued too low. Money can be made by addressing these issues more seriously.

A: reservoir area The reservoir area "A" is mainly determined from seismic, combined with geological knowledge, e.g. obtained in the region from other wells or outcrop. Well / production tests, combined with reservoir simulation also play an important role in determining the extent of a reservoir. Geological and reservoir engineering modelling tools can play an important role in addition to the seismic interpretation software. Seismic is constrained by a limited resolution and by various assumptions in the modelling (velocity model, migration, etc.). Geological models are based on empirical knowledge and are therefore statistical rather than deterministic. It is probably fair to say that in general the reservoir area is one of the most uncertain factors in the determination of the hydrocarbon volume.

h*(N/G): reservoir thickness and net-over-gross The reservoir thickness h and net-over-gross-ratio N/G are normally obtained from logs and cores. Seismic information does not have sufficient vertical resolution to play an important role in this. On the other hand, the extrapolation of reservoir thickness away from the wellbore can only be made on the basis of seismic ("lateral prediction"), because of the limited depth of investigation of logging tools (see further below). Hence, the net reservoir thickness is best known at and around the wellbore and becomes increasingly more uncertain away from the wellbore. Again, geological modelling has an important role to play here. Additional information can be obtained from capillary pressure curves and wireline formation tests (pressure versus depth graphs). The net-over-gross ratio (N/G) or net sand

thickness h*(N/G) are often obtained from the gamma-ray, using a simple cut-off criterion (e.g. all intervals with GR reading less than x API are sands). In general it is better not to work with cut-offs in this stage, but to only apply them at the final evaluation stage. Also, use of other logs in addition to the gamma-ray, in particular use of the density/neutron combination, often gives a much better discrimination between shales and sands. An important point to note is that even with wireline logs the net reservoir thickness determination may be inaccurate because of the limited vertical resolution of logging tools. Especially in laminated sand/shale sequences, e.g. turbidites, logs often fail to discriminate reservoir rock from non-reservoir rock (see discussion of "water saturation" below). Currently, this problem can only be solved by use of advanced logging tools (e.g. NMR, FMI) in addition to the standard tools, combined with logging tool response modelling.

φ: porosity (related properties: permeability / producibility) The reservoir porosity φ is most often determined from the density log, sometimes combined with neutron or sonic logs. The parameters required in the conversion from density to porosity are best determined from core calibration measurements in the laboratory (taking into account the effect of stress / compaction). An important parameter is the fluid density. Hence, it is important that the fluid type has been determined correctly (gas/oil differentiation) in order to arrive at a good porosity calculation. In order to get a good estimate for the matrix density the lithology has to be known properly. Density tools (especially LWD tools) are rather sensitive for borehole and mudcake conditions, and for lithology (e.g. shale). An alternative (lithology independent) porosity measurement is promised by the new NMR logging technique. NMR also promises to give information on permeability / producibility. Permeability so far has been traditionally determined in the laboratory from core measurements. The main problem here is how to relate these small size plug measurements to the large size grid blocks ("upscaling"). This problem relates to all core (and log) measurements: it is also related to the lateral prediction problem mentioned above. Another problem inherent to the use of core measurements is the question how representative the core is for the reservoir (core disturbance, biased sampling, laboratory versus reservoir conditions, etc.).

Sw: water saturation (related property: fluid type) The water (and hence hydrocarbon) saturation is mainly determined from resistivity logs, although it can be (and often is) determined independently from capillary pressure curves combined with wireline formation tests. Resistivity tools are heavily affected by environmental effects, i.e. effects of borehole, mud filtrate invasion, formation layering and borehole deviation / dip. This is so because resistivity tools have been designed to read relatively deep into the formation (a few metres which affects the vertical resolution, i.e. they are affected by layers several meters away. Hence a thin (few feet) oil bearing layer surrounded by low resistivity shoulder beds (e.g. water bearing sands or shales) it is very difficult to "see". A related problem is the response in laminated sand/shale sequences, e.g. turbidites: the response is dominated by the low resistivity shale laminae, obscuring the hydrocarbon effect in the sand laminae. Therefore, the resistivity response in laminated sequences is often (much) too low.

An additional problem is that saturation can only be determined from resistivity using a resistivity interpretation model, e.g. Archie, Waxman-Smits. The uncertainties there are: which model to use, and what parameters (m, n, Qv, etc.) to use in the model. For this purpose laboratory measurements are often required, leading to above mentioned (core measurement related) uncertainties. There are many uncertainties related to the determination of fluid type. The best method is plain testing, but that is often too expensive. Gas/oil determination from logs is often more an art than a science (e.g. the neutron / density separation is often obscured by shale). Again, NMR may have some promise in this area.

Some general remarks Some general factors, affecting most of the above determinations are the following ones: - tool failures / malfunctioning (especially of course if unnoticed). - depth matching problems. - statistics, especially with nuclear tools, where count-rate deteriorates with faster logging. - borehole irregularities / washouts. - influence of fractures, overpressures, anisotropies / inhomogeneities. Difference must be made between systematic and random errors. Systematic errors are those where the measurement is systematically off (shifted) with respect to the true value, e.g. the measurement is systematically too high (or too low). A random error is an error of which the influence diminishes when the measurement is repeated more often, because the average is close to the truth. Because of the many factors and uncertainties involved in the determination of hydrocarbon volume, random errors often cancel each other. Therefore, a systematic error is in most cases by far the most severe one. Such systematic errors can be the result of applying the wrong tool (measurement principle), tool malfunctioning, influence of disturbing factors not properly accounted for, etc.

Points to observe In general the accuracy / precision of the determinations can be improved if the following points are accounted for: - All tools should be properly calibrated. - All logs should be properly environmentally corrected if required; especially

mud additives (e.g. barytes, KCl) can heavily influence certain measurements. - Beware of contractor processing: they may have filtered some logs without

telling you. - Beware of possible plain errors (wrong data files, digitizing, wrong well header

etc.). - In thinly bedded reservoirs care has to be taken that the thin bed effect on the

resistivity is accounted for. Check with modelling wherever possible. - Tools and their responses are limited by their measurement principle

(physics): they can't measure more than they were designed for (do not believe all contractor claims on what their tools can measure: those claims are only valid for optimal cases).

- In general, more modern tools have more detectors (array tools, imaging tools) and therefore provide more information.

- Tool responses in hostile (HPHT) or non-standard (slim hole, horizontal hole) environments may be less reliable.

Always ask yourself: can I trust this data. Sometimes it is better to have no data (hence, using estimates, literature correlations, etc.) than using wrong data. Make a habit of checking/questioning: e.g. if the matrix density has been determined to be 2.3, ask yourself: can that be right ?? Make a habit of asking for error bars; make audits, compare contractors regularly, check repeat runs. Check log response in known lithologies. Contractors have Quality Control Reference Manuals which they should use.

Example uncertainty calculation Suppose we have a sandstone reservoir with the following properties:

- porosity φ= 0.20

- water saturation Sw = 0.30

- thickness h = 7.17 metres

This gives an equivalent hydrocarbon column = φ*(1-Sw)*h = 1.00 metre.

We will get the right evaluation if we use the true formation parameters given below:

- true formation resistivity Rt = 20.4 Ohmm

- n = 1.5 - m = 1.5

- formation water resistivity Rw = 0.30 Ohmm

- matrix density ρma = 2.68 g/cc

- fluid density ρfl = 0.74 g/cc

However, if in our calculations we erroneously take wrong values for these parameters, our evaluation will yield the following (it is a good exercise to check this yourself):

- Rt = 10 in stead of 20.4 gives EQHC = 0.74 metres

- n = 2 in stead of 1.5 gives EQHC = 0.85 metres - m = 2 in stead of 1.5 gives EQHC = 0.70 metres - Rw = 0.15 in stead of 0.30 gives EQHC = 1.16 metres - matrix density = 2.65 in stead of 2.68 gives EQHC = 0.91 metres - fluid density = 1.0 in stead of 0.74 gives EQHC = 1.23 metres - all of these errors in stead of all of the correct values gives EQHC = 0.68

metres

Taking a too low Rt yields a too low hydrocarbon saturation hence a too low EQHC. The same goes for a too high value of n. The other variations are equally indicative for the role of those parameters. Clearly, in this example, it is especially important to obtain correct values of Rt (hence the impact of e.g. resistivity

modelling / inversion!), m, and fluid density. In a Monte Carlo study one would do calculations with many combinations of above parameters in the band of uncertainty around their average values. This would give a good impression of the accuracy of the EQHC calculation from a petrophysical point of view.

Petrophysical UncertaintiesThe Process

Evaluate

Φ, Sw, K

Define Cut-offs

GeologyReservoir Engineering

• net sand• net reservoir

• (net pay)

sensitivities to

cut-offs

sensitivities to

wvaluation model

well averages well uncertainties

field averages & uncertainties

keep original curves (audit trail)

13. Calibration & Quality Control

References

- Ph. Theys, Log data acquisition and quality control, Editions Technip, 1991

Calibration

In order to ensure the correct working of a logging tool it has to be calibrated: see Fig. 1. Several calibration methods exist:

- Primary standards (Fig. 2): Used to establish the response of a new calss of logging tools. Normally done in a large test pit, possibly close to the manufacturer. Only one out of ten (say) tools is calibrated in this way.

- Secondary standards (Fig. 3): Used to confirm consistent tool response. Is available at the contractor base (e.g. shop calibration). Should be sufficiently recent, e.g. less than 3 months old.

- Tertiary standards (Fig. 4): Portable calibration equipment, used at the well-site, e.g. before and after the logging survey. The before survey calibration should be done within 24 hours of the job, after the tool has been transported. It transfers the shop calibration to the tool and checks the tool operation. The after survey calibration should be done immediately following the run. It verifies lack of drift during the survey.

- In situ calibrations: Using known tool responses in certain formations / lithologies (e.g. anhydrite, halite) and in casing. This has the advantage that the tool is calibrated downhole, i.e. at formation temperature.

A table of common calibration procedures is given in Fig. 5. The calibration results are displayed at the end of the log. They should be checked against contractor provided guidelines with respect to allowed tolerances (see e.g. Fig. 6: example of a calibration record, provided by Schlumberger).

Repeat sections

The objective of repeat sections is to verify survey consistency and/or highlight faulty electronics. The repeat section is often carried out before the actual survey, and is normally done over 100 metre of reservoir interval (normally the bottom interval) or over an area of known erroneous response. Radio-active tools may show statistical scatter (the more the faster they are run). The interval average should repeat though. Pad / sidewall tools may differ slightly due to different borehole trajectories. The other tools should repeat exactly. Figure 7 shows an example of a print of a repeat section.

Wellsite quality checks

- Check calibrations - Check depth measurement - Check readings in marker beds (anhydrite, salt, …) - Overlay repeat sections - Check consistency with mudlogs and other available information

Quality control by interpretation

- Check reservoir thickness on GR, density/neutron, SP and microlog - Compare lithologies obtained from mudlog, sidewall samples and density /

neutron (and/or sonic) logs - Calculate porosity from density, neutron and sonic - Ensure the consistency of fluid types obtained from resistivity, density /

neutron, cuttings, sidewall samples, gas chromatograph, wireline formation test samples and pressure tests.

Causes of poor logs

- At manufacure: inadequate design, inadequate testing. - At contractor base: inadequate maintenance, incorrect shop calibrations. - At wellsite: incorrect calibration, poor procedures, bad hole, abnormal

pressure / temperature, improper (ex)centering, shock / vibration, abnormal muds (gas, NaCl, KCl), abnormal lithologies (e.g. Groningen effect)

- After logging: poor editing may cause erroneous responses on the logs stored on the database (Figure 8)

Tool calibration principle

Tool Response

Calibrated reading

OffsetGain

Zero

Plus

Zero Plus

Calibrated reading = gain * tool response + offset

Figure 1- Tool Calibration Principle

Neutron calibration pit

Fresh Water

Carthage marble(1.9% porosity index)

Indiana Limestone(19% porosity index)

Austin Limestone(26% porosity index)

6’ Diameter

6’6’

6’

Figure 2- Neutron Calibration Pit

Neutron shop calibration

Aluminiumsleeve

Water filledtank

CNLtool

Ratio measurementwith sleeve down givesPLUS reference

Same measurementwith sleeve withdrawngives ZERO reference

Figure 3- The Neutron Shop Calibration

Neutron well-site calibration

Rig site calibration verifies shop calibration

Jig containingradioactive source

LoggingUnit

Figure 4- The wellsite calibration

Calibration procedures for common logging tools

Electronics check only: SPSonicDipmeter

Mechanical check: Caliper (using known diameter rings)

Laboratory calibration

Shop calibration

Field calibration(before and after survey)

Test pit

Al + Fe blocks

Internal source

Water filled tank

Jig with radioactivesource

Testpit

Jig with radioactivesource

Precisionconductivity loops

Internal resistors

Internalresistors

LithoDensity Neutron

(Spectral)GR Induction

Laterolog,SFL MSFL

Figure 5 – Calibration Procedures for Common Logging Tools

Calibrations

Figure 6- Calibration Summary, part of a log print

Figure 7- The Repeat Section, part of a log print

1725

1700

Edited GR from 3rd Party

Raw Gamma Ray

IncorrectEditing of GR(i.e. GR in csg.left in)

Figure 8- Example of poor editing

14. Cement Evaluation

Summary

A good cement bond is especially important for zonal isolation. The cement bond quality is detected using acoustic techniques, on the principle that a free (badly cemented) pipe will ring, hence give a strong acoustic signal when excited by a sound pulse, whereas a strongly cemented pipe will much attenuate the acoustic signal. Although quantitative measurement and interpretation techniques have been developed, in practice it turns out that in most cases these measurements will give qualitative indications only.

References

- James J. Smolen, Cased hole and Production log evaluation, PennWell Books, 1996

- Schlumberger, Cased Hole Log Interpretation Principles/Applications, 1989

Cement logging applications

Cement problems can arise during setting (Fig. 1), e.g. due to remaining mud (Fig. 2). Cement logging aims at: - assessment of cement quality and strength - location of the top of the cement - assessment of the effectiviness of cement repair jobs (using “squeeze”

techniques) - assessment of the effect of high pressure operations (injection / frac.

treatment)

The Cement Bond Logging tool (CBL)

The Cement Bond Logging tool (CBL) consists of one acoustic transmitter and two receivers, one at 3’ and one at 5’ spacing. The actual CBL signal is obtained from the 3’ receiver. The 5’ receiver yields the VDL signal (see further below). The principle of the CBL is that an acoustic wave travelling through the casing will hardly be attenuated if the casing is hanging free, thus giving high amplitude on the receiver. However, if the pipe is properly cemented, the signal will be much attenuated, giving rise to very low amplitude (Fig. 3). The transit time is also monitored, but this measurement is less inportant (Fig. 4). Hence, an ideal CBL log would look like Fig. 5. In practice one would see some artefacts e.g. due to the presence of the casing shoes.

Problems If the bond is very good the signal may become so weak that it is difficult to detect. Hence, one might miss the first arrival and accidentally pick up a stronger later arrival thus concluding that the bond is bad (higher amplitude). The solution to this problem is to measure the amplitude in a fixed time window, rather than picking the first arrival (fig. 6).

Another problem is tool eccentering. Even slight eccentering gives a decrease in amplitude, thus possibly erroneously indicating good bond. Hence, the tool has to be centered very well. A special version of the CBL exists, the CBT, which is centered with stong centralizers and which also has more detectors. It is nevertheless less popular than the CBL. Because of the eccentering problem, the CBL is less reliable in strongly deviated holes.

The CBL does evaluate the bond between cement and casing. It is not sensitive to the bond between cement and formation. Furthermore, the CBL amplitude is an average around the borehole (azimuthally) and does therefore not discriminate between a moderate bond over the whole circumference and for instance a good bond at one side and a bad bond at the opposite side. Finally, the amplitude is sensitive to small micro-fractures (“micro-annuli”) which show up as a bad bond but are harmless because they don’t destroy zonal isolation. The effect of micro-annuli can be tested by re-running the CBL after application of a certain well head pressure which expands the casing and hence squeezes the cement. If there are remaining zones with a still high amplitude, a cement squeeze repair job might be required, after which again a CBL run should be applied to assess its effectivity.

Quantitative evaluation From the CBL amplitude a Bond Index can be calculated (Fig. 7). To be sure of good zonal isolation the Bond Index should exceed 0.8 over a sufficiently long section of the casing, dependent on casing diameter. The attenuation required in Fig. 7 can be calculated from the measured amplitude in millivolts.

The Video Display Log (VDL)

The Video Display Log (VDL) is a way of displaying the full wavetrain, obtained by colouring all positive loops black (Fig. 8). The VDL signal is also sensitive to the bond between cement and formation (because one may see formation wave arrivals, indicating a good bond to the formation) and thus complements the information obtained from the CBL amplitude (Fig. 9).

Acoustic Reflection Techniques

One of the problems with the CBL is that it only gives an average over the circumference. Therefore, tools have been developed that scan the circumference by emitting high frequency sound pulses in different azimuthal directions and measure the impedance contrasts in all directions. Schlumberger’s current generation tool is the Ultra-Sonic Imager (USI): Fig. 10 & 11. Such tools give detailed colour scans of the cement distribution besides other properteries (e.g. casing thickness). Similar tools are available from other contractors.

Figure A3

Fig. 1 Pressure Drop in Cement Setting

Fig. 2 Poor Slurry Installation System

Fig. 3

Fig.4 Transit Time Measurement

0 CBL amplitude (mV) 100

Good bond

Bad bond:free pipe

Fig. 5 CBL response to bonded and free pipe

depth

Fig. 6 CBL: fixed vs. floating gate

Floating gateresponse:

start window ifexceeding thresholdMay erroneouslyindicate bad cement(cycle skip)

Fixed gate response:

fixed time window

ok if cycle skip

fixed window

Fig. 7 Bond index

attenuation (dB) in zone

attenuation (dB) in 100 % bonded zoneBI =

The BI should be greater than 0.8 for an interval with a certain minimum length (dependent on casing size)

first arrivalsfrom casing cementinterface

later arrivals fromcasing formationinterface

Fig. 8 The VDL is a Method of Displaying the Full Wave

Fig. 9 Interpreting Cement Bond – Variable Density Logs

VDL

TYPE OF BOND CBL CASING FORMATIONAMPLITUDE ARRIVAL ARRIVAL

Free Pipe High Large Very Weak or none

Good Casing -to - Cement - Low Weak Strong to - Formation

Good Casing BondPoor Formation Bond Low Weak Weak or none

Microannulus ChannellingThin Cement Sheath High Moderate Moderate

Fast Formation Arrivals High Absent Strong

Fig. 10 Travel of the Transducer Sound Impulse

Mud Casing Cement

Transducer

Copyright 2001 SIEP b.v.

UltraSonicImager

Fig. 11 Schlumberger’s Ultra Sonic Imager

15. Reservoir Monitoring

References

- James J. Smolen, Cased hole and Production log evaluation, PennWell Books, 1996

- Schlumberger, Cased Hole Log Interpretation Principles/Applications, 1989 - Oilfield Review, Winter 1996, pp. 44-64

Introduction

Reservoir monitoring is the determination and reporting of petrophysical parameters after initial conditions have been disturbed by production, e.g. to assess the effectiveness of the production (drive mechanisms). Hence, fluid distributions and phase saturations are measured as a function of time. These changes may be the result of pressure depletion, gas cap expansion, aquifer influx, water drive, etc. Hence, the monitoring of the movement of OWC and GOC fluid interfaces is an important aspect. As this is a dynamic process, many reservoir monitoring methods are time-lapse methods, i.e. they look at changes in petrophysical parameters over time. In addition, an aspect of reservoir monitoring is the determination of remaining and/or residual oil saturation (ROS).

Methods

The following methods exist for reservoir monitoring, each with its own advantages / disadvantages.

Conventional wireline logging If open holes are available (e.g. infill wells), or the holes are not cased with steel (but with plastic, fiber glass, etc.), conventional open hole logs can be run, i.e. gamma-ray, density/neutron, induction resistivity etc. In most cases, however, such holes will not be available.

Pulsed neutron capture logging This is the most commonly used method in steel cased holes. It is also known as "PNC-logging". It is best used when the formation water is rather saline. It can be run through tubing. This technique will be discussed below in more detail.

Pulsed Neutron Spectroscopy logging This method is used in steel cased holes when the formation water salinity is either low or unknown. It is also known as “PNS logging" or C/O logging. This technique will be discussed below in more detail.

Through-casing resistivity logging PNC logs were developed because standard wireline resistivity devices could not be run in steel cased holes, as almost all current will be caught by the casing. Nevertheless, through-casing resistivity tools were developed by both Schlumberger and Baker Atlas The tool works on the principle that some current will still leak into the formation, leading to a detectable voltage

difference over the casing. Trials showed that meaningfull resistivity profiles were measured and that monitoring with a cased hole resistivity curve is a viable option. Both contractors now offer the tool on a commercial basis.

Cross-well measurements Well-to-well acoustics can be used to delineate reservoire structure (faults etc.) between wells, and well-to-well electromagnetics can be used to detect fluid interfaces between wells. Timelapse well-to-well measurements have been used for monitoring of steam and CO2 floods. These techniques require the availability of two open holes and are therefore expensive. The electromagnetic technique has a very low resolution and is still in the research phase. A single well deep-reading resistivity tool which is sensitive to 50 metres away from the borehole is being developed.

Techniques for determining ROS include single and inter-well tracer tests, sponge coring and special core analysis.

In the following the focus will be on PNC and PNS logging, being the most commonly used techniques, despite of the fact that they read rather shallowly into the formation. The assumption is that most mud filtrate invasion will have been disappeared after several months of production, so that the shallow depth of investigation is not really problematic. This is not always the case though. Moreover, because of their shallow depth of investigation these nuclear techniques are rather sensitive to the borehole and its environment (casing, tubing, cement, well treatments, etc.).

Pulsed neutron capture logging (“PNC logging”)

Principle In open hole logging, the hydrocarbon saturation is determined from the resistivity log. This works because the formation resistivity is sensitive to the saline water only, hence knowing the water salinity (resistivity) and the porosity the amount of water can be calculated (Archie's law). In a steel cased hole a similar technique is used. The water is again discriminated from the oil by detecting its salinity. However, in stead of detecting the saline water by means of its electrical conductivity, it is detected by using the fact that the chlorine in the salt has a high thermal neutron capture cross-section sigma, or Σ ("chlorine loves to eat neutrons"). Because of that the sigma for brine is normally (unless the water is fresh) higher than the sigma of hydrocarbons: see Fig. 1. Hence, the PNC tool is primarily a chlorine-measurement. The principle behind the PNC measurement is that sigma is relatively high in water bearing zones (because of the high chlorine content of the brine) and low in hydrocarbon bearing rock (because hydrocarbon doesn’t contain chlorine). Obviously this principle only works if the formation water is sufficiently saline, i.e. if the contrast between sigma_water and sigma_hydrocarbon is sufficiently large (analogous to the fact that resistivity tools don’t do a good job if the formation water salinity is too low, because the resistivity contrast between brine and hydrocarbon then disappears). The tool has an accelerator source that can be switched on and off to create a short pulse of high energy neutrons. These will be moderated (slowed down) by collisions with mainly hydrogen nuclei until they have thermal energy (this slowing down process determines the amount of thermal neutrons measured by

conventional open hole neutron porosity logging tools). The thermalised neutrons are captured mainly by chlorine nuclei, giving rise to gamma-radiation. These capture-induced gammas are detected by the tool. When the formation contains little oil, hence much saline water, many neutrons will be rapidly captured and hence the induced gamma-radiation will decay quickly with time. This decay is more or less exponential (Figs. 2 and 4). The slope of this decay curve is indicative for the neutron capture cross-section, called sigma or Σ (Figs. 3 & 4), which is indicative again for the water salinity (Fig. 1). Many corrections are required, however, as outlined below.

Tools All major logging companies have PNC tools, all having an OD of 1 11/16". These tools all have dual detectors, the far detector being more sensitive to the formation, the near detector being used to correct for borehole influences. The differences are in the accelerators, detectors, pulse timing, measurement of the decay curve (sampling) and analysis / correction methods applied. As a further development the contractors have now tools available which combine PNS and PNC measurements. Tool OD, however, is still a limiting factor (> 1 11/16”) for some contractors.

Applications Pulsed neutron capture logs can be used in three different ways:

1) Single run (see also section on “evaluation” below), used to determine the absolute saturation directly from the measured sigma. The interpretation relies on a simple volumetric mixing law for the different components, being matrix, hydrocarbon, water and shale. The log measured sigma is hence a linear combination of the sigmas of the matrix, hydrocarbon, water and shale, where the coefficients are the volume fractions of these constituents (e.g. for shale it is the shale fraction): Figs. 5, 7 & 8. Hence, in order to derive the water saturation from the log one has to know the capture cross-sections (sigmas) of the matrix, hydrocarbon, water and shale. Charts and tables are available, but it is in general better to get them from the logs, e.g. by cross-plotting the log measured sigma versus porosity (Fig. 6) in clean water bearing, hydrocarbon bearing and shale intervals. The measured log (sigma) is normally displayed with the high value at the left, such that it resembles the open hole resistivity log.

2) Time-lapse logging, used to determine the change in saturation from two different runs, typically taken one year apart. This technique is much more accurate than the single run (absolute) one, and is very regularly applied. The principle is shown in Figure 9. Note that due to the time-lapse approach the only variable is the change in saturation. Uncertain parameters like sigma matrix and sigma shale have cancelled out. Figure 10 shows a time-lapse example where the rise in OWC is illustrated by an overlay of the various sigma curves acquired at different times.

3) Log-inject-log: a base log is run, next a different salinity brine is injected and the log is run again. This is used for ROS determination.

Additional information Apart from the capture cross-section sigma, the PNC tool also gives the following two curves:

1. The ratio of near to far detector count rates: this parameter is indicative for porosity.

2. The ratio of inelastic to capture count rates for the near detector (see also section on Induced Spectroscopy below): this curve is plotted such that it overlays the curve mentioned under point 1 for oil bearing zones. It will separate to the left of the curve of point 1 in a gas zone. Hence the separation between the two curves acts as a good gas indicator.

Problems - The pulsed neutron capture technique is statistical by nature. The logging

speed is hampered by the fact that a sufficiently high count-rate has to be obtained. This limits also the repeatability and the accuracy of the measurements.

- The formation water should be sufficiently saline, normally above 30,000 ppm, and the porosity above 10-15 %, to guarantee enough signal. The accuracy in the water saturation is 5 % at best (in single run applications). Note, however, that changes in OWC can be “picked-up” through time-lapse mode when the formation water salinity is less than 30,000 ppm (> 20,000 ppm).

- The technique relies on the fact that the neutron captures are due to chlorine. However, many other elements can capture neutrons as well, e.g. boron (which may be present in shales), potassium (in shales), iron (present in many minerals and cements). Hence, the measurement is problematic in shaly environments and in non-standard lithologies. It works best in clean sandstones and carbonates.

- Neutrons are captured also rather well by the steel of the casing and tubing. Moreover neutrons are captured by the salt water in the borehole. The borehole will therefore also act as a neutron sink leading to additional apparent decay due to diffusion of neutrons away from the formation into the borehole. Only in recent years was this diffusion effect recognised to be important. These disturbances due to borehole, casing, tubing and cement make substantial corrections necessary if the tool is used in the absolute (single run) mode. Associated problems are (Fig. 11): remnant mud filtrate invasion, remnants of acid washes (HCl: chlorine rich !), wash-outs partly filled with cement, gas accumulations just below the packer (between tubing and casing), etc.

- Because of its shallow depth of investigation the inferred fluid contacts can be misleading in cases of water or gas coning.

- Because of the above the tool is best used in the time-lapse mode. Even in this mode it is only accurate if the only change happening is the one in the formation due to the production. Changes in borehole fluid, borehole environment (sand production, acid treatment, etc.) and tool type should be avoided.

Pulsed Neutron Spectroscopy

Principle Another way to detect hydrocarbons is the measurement of the ratio of carbon to oxygen atoms, because this ratio will be high for hydrocarbons and low for water (Fig. 12). This ratio is measured by again using pulsed neutrons, but now looking not at the thermal decay, but at the inelastic scattering immediately after the burst. The neutrons then still have a high energy. Inelastic collisions with nuclei will generate gamma rays whose energies are specific to the element that is hit by the

neutron. Hence the measured energy spectrum of the thus induced gammas is a kind of fingerprint for the chemical composition (a different version of the tool is used for the determination of lithology). Special energy windows are used to separately measure the amount of carbon and the amount of oxygen. This technique basically measures the relative abundance of hydrocarbon with respect to water and is therefore salinity independent. Hence, it can be used in cases where pulsed neutron capture logging doesn't work, e.g. CO2 flooding where comingled salinities are present. Apart from inelastically scattered gamma-rays (which occur very soon after the neutron pulse), also gamma-rays from thermal neutron capture will be measured (these occur later in time). From all of this information not only information on Carbon and Oxygen is obtained, but also information on other elements such as Silicium, Iron, Calcium, Sulphur, Chlorine etc. Herefrom an indication of lithology can often be obtained.

Tools Most contractors offer combined PNS and PNC services. Note, however, that some contractors can not provide a 1 11/16” tool.

Applications PNS logging has been successfully used to identify formation fluid types in low salinity reservoirs. Even remaining oil “behind” tubing has been identified with PNS logging.

Fig. 1 Neutron capture cross-sectionsBoron 45,000 per g/ccChlorine 570Hydrogen 200Silicon 3Matrix 8 - 12 c.u.Oil 14 - 22Gas 8Pure water 22Saline water 22 - 140Shale 20 - 60Borax 9,000Rock salt (halite) 726Iron minerals (pyrite etc.) 50 - 100

Fig. 2 Neutron life time <---> ChlorineNeutron faces few capturers Neutron faces many capturers

neutronCl

Clneutron

Cl

Cl

Cl

Counts Counts

time time

slow decay:low Σ fast decay:

high Σ

Fig. 3 Formation capture cross-section Σ

Number of neutrons N versus time t:dN = N Σ v dtN = N0 exp(- Σvt) = N0 exp(- t / τ)

v = thermal neutron velocityΣ = formation capture cross-section

(slope of decay curve on log-log plot)

Σ = 4550 / ττ = decay time constant (μs)

Influence of pore fluid on decay curveInfluence of pore fluid on decay curve

Rel

ativ

e co

unt-r

ate

Time (μs) after neutron burst1

10

100

1000

0 1000 2000

Region of boreholeand casing decay

Region of formation decay

Background

GasSalinewater Oil

Fig. 4 Effect of Pore Fluid on the Decay

Fig. 5 TDT response in clean sand

Σ = (1 - φ) Σma + φSwΣw + φ(1-Sw)Σhc

Σma and Σw can be obtained from regression through water bearing points

Σhc (and possibly Σma and Σw) can be obtained from charts / lab. measurements

Σ

Porosity0.0 0.2 0.4 0.6 0.8 1.0

100

80

60

40

20

0

Sw

1.00

0.75

0.50

0.25

0.00

Water line

Hydrocarbon lineΣm

Σw

Σhc

Waterbearingzone

Oil bearing zone

Fig. 6 TDT response in clean reservoir

Fig. 7 TDT response in HC sand

log: matrix hydrocarbon water shale

Σlog = (1 - Vsh - φ)Σma + φ(1 - Sw)Σhc + φSwΣw + VshΣsh

= (1 - 0.1 - 0.3)*10 + 0.3*(1-0.2)*15 + 0.3*0.2*75 + 0.1*25

= 0.6 * 10 + 0.24 * 15 + 0.06 * 75 + 0.1*25

= 6 + 3.6 + 4.5 + 2.5

= 16.6

Fig. 8 TDT sigma interpretation

• Σ = (1 − φ)∗Σma +φ∗Σfl(macroscopic volumetrics)

• Σfl = Sw*Σw +(1 − Sw)∗Σhc

• Σma , Σw , Σhc from Σ vs. φ cross-plot, or from charts / lab.

• Additional curves:- near/far ratio: pseudo CNL porosity- near/far overlay: gas & shale discr.

Fig.9 Time-Lapse

Difference between a base run and subsequent runs is:

ΔΣlog = φ (Σw - Σhc) ΔSw

Hence: Σma and Σsh have dropped out of the equation.

Thus:

ΔSw =ΔΣlog

φ (Σw - Σhc)

Fig. 10 Far East Carbonates PNC data: Moving Contact & Change in Residual Gas Saturation

Paleo-residual gas zone(gas expanding w/ pressure decline)

Residual gas zone(swept by water front)

Water saturated zone

Fig.11 Influence of BH environment

cement

remaining invasion

HCl acid wash,washouts, ....

Use well sketch besides PNC logs

formation

Inelastic scatteringInelastic scattering

Fastneutron(14 MeV) Nucleus

Excitednucleus

Emittedgamma-ray

Neutronis

scattered

Fig. 12 Low Salinity Environment…….Pulsed Neutron Spectroscopy

Hydrocarbon CxH2x+2 carbon rich no oxygen

Water H2O no carbon oxygen rich

16. Production Logging

Summary

Production logging deals with the cased hole logging techniques available to measure / monitor the fluid production flow behaviour in tubing and/or casing during production. Typical methods / measurements of the conventional production Logging Tool (PLT) are: - flow velocity (e.g. using the spinner) - fluid density - flow noise - temperature The flow behaviour is very different for single and multiphase flow. The latter strongly depend on hole deviation. For such conditions, more modern tools exist, like the MCFM from Baker Atlas (jointly developed with Shell) and Schlumberger’s Flagship, which combine PNC/PNS measurements with PLT type measurements.

References

- James J. Smolen, Cased hole and Production log evaluation, PennWell Books, 1996

- Schlumberger, Cased Hole Log Interpretation Principles/Applications, 1989

- Oilfield Review, Winter 1996, pp. 44-64

Why Production Logging ? The primary goal of Production Logging is reconciliation of downhole inflow with surface rates and results from reservoir modelling. Differences may be reveal typical mechanical well problems as highlighted in Fig. 1.

Single phase flow Single phase flow can be laminar of turbulent (Fig. 2) dependent on the Reynolds number (Fig. 3: the fans of lines correspond from top to bottom to viscosities of 1, 10 and 100 centipoise respectively). The flow velocity can be measured with spinner tools (Figs. 4 & 5). Ideally the spinner rotation speed (rotations per second, rps) should correspond linearly to the flow velocity (Fig. 6). However, the actual response is more complicated because of effects due to viscosity (Fig. 7) and friction (Fig. 8). Therefore, standard practice is to make several runs with different tool velocities (several runs with the tool

moving up and several with the tool moving down): Figs. 9 and 10. If the fluid is moving up faster than the tool is moving up, the spinner response is positive, but if the tool is moving up faster the spinner response is negative (the spinner rotates in the other direction). Only the spinner absolute response (rps) is plotted though (regardless of the rotation direction) and one has to take this “spinner reversal” into account (Fig. 12: the bottom part should be plotted on a negative scale). One can combine an up and a down run and overlay them in the region of no fluid flow. A separation then is indicative of a flowing zone: Fig. 11. The actual flow velocity can be obtained from the displacement of a line through points obtained at various (up and down) tool velocities with respect to the line for zero flow: Fig. 10.

Slip velocity and hold-up If water and hydrocarbon are flowing simultaneously, there can be a difference in velocity between the two fluids. This is called slip velocity. This has to be differentiated from the hold-up which is the fraction of the total volume that is occupied by the fluid (hence, there is a water hold-up and a hydrocarbon hold-up): Figs. 13. The slip velocity is related to hold-up and density difference (Fig. 14) and hole deviation.

Multi-phase flow regimes If liquids and gas are flowing simultaneously, different flow regimes can result, depending on fluid velocities (Figs. 15) and borehole deviation. Because of that, conventional (spinner) flow meters may not work anymore in deviated wells (Figs. 16 & 17). As the hole deviation may change with depth the flow regime may change with (along hole) depth as well. The modern contractor tools (like the MCFM and the FlagShip) cope much better with these conditions (Fig. 18).

Fig. 1 Mechanical Well Problems

Fig. 2 Fluid Phases in the Wellbore

Laminar Flow Turbulent Flow

velocity = 0at pipe wall

Copyright 2001 SIEP b.v.

. .

Turbulent flow

transition zone

Laminar flow

Rey

nold

s nu

mbe

r

Flow rate in barrels/day10 100 1000

10

100

1000

10000

pipe od

34

56

8

Reynolds Number v Flow rate

for 1.0g/cm 3 fluid

Flowrate (bbl/day)

Rey

nold

s Num

ber

Nre

10 100010

10000

100

Pipe OD

1 centipoise

10 centipoise

100 centipoise

Transition zone

Turbulent flow

Laminar flow

Nre = ρvD/μ

This example: ρ = 1 g/cc

Fig. 3 Relationships of Re number to Flowrate

.

23.5

11.6

Fullbore Spinner Flowmeter

Centralizerblades canfold upto run thetool throughtubing

Fig. 4 The Fullbore Flowmeter

Basket flow meter

Spinner

Exit ports

Metal petals

DC motor

Fig. 5 The Basket Flow Meter

Fig. 6 Ideal Response of the Spinner with Fluid Velocity

Spinnerrps

Fluid VelocityUP

Fluid VelocityDOWN

Fig. 7 Effect of Viscosity Is to Change the Spinner Response away from the Ideal Line

Spinnerrps

Fluid VelocityUP

Fluid VelocityDOWN

increasingviscosity

increasingviscosity

Fig. 8 Mechanical Effects are seen at Very Low Flowrates

Spinnerrps

Fluid VelocityUP

Fluid VelocityDOWN

increasingviscosity

increasingviscosity

mechanicaleffects

Spinnerrps

Tool VelocityDOWN

Tool VelocityUP

increasingviscosity

increasingviscosity

mechanicaleffects

Fig. 9 Plot with Tool Velocity Substituted for Fluid Velocity

Fig. 10 Flowing Fluids add their Velocity to that of the Tool changing the Flow away from the Zero Calibration Line

Spinnerrps

Tool VelocityDOWN

Tool VelocityUP

Vf

Vf

VfMidpoint

Zero Flow

Zero Flow

UpRun

DownRun

Gradio

Temperature

Perf

orat

ions

800

700

600

Spinners

Overlay of “run up” and “run down” curves

Fig. 11 A Typical Production Log

Spinner, rps

tool movingfaster thanthe fluid(- rps)

tool movingslower thanthe fluid(+ rps)

SpinnerReversed

Spinner reversals

Fig. 12 Spinner Reversals

Fig. 13 Simplified Model Illustrating Slip Velocity

ρmix = YWρW + Yoρo = YWρW + (1 –YW) ρoρmix = YWρW + ρo – YWρo = YW (ρW – ρ ) + ρo

ρmix – ρoYW = ρW – ρo

VO = VW + VS

YW

VO VW

A

Fig. 14 Standard Chart for Slippage Velocity

Fig. 15 Fluid Phases in the Wellbore

1 10 102 103

1

10

102

10-1

BUBBLE FLOW

PLUG FLOWSLUG FLOW

MIST FLOW

REGION IIIREGION II

REGION I

GAS VELOCITY

TRAN

SITI

ON

LIQ

UID

VEL

OC

ITY

FLOW REGIMES

Fig. 16 Flowmeters may read Two Different Types of Flowin Deviated Wells

Trappedwater

Trappedgas

Flow restrictions in undulating boreholes

Fig. 17 Complexities in Horizontal Wells

Copyright 2001 SIEP b.v.

Flow Direction

MCFM MCFM -- Measurement Measurement ConceptConcept

– Level and holdup determined from sensors at 8 levels across wellbore (12 bit)

– Velocity determined from correlation of adjacent sensors on 4 rows (1 bit)

Fig. 18 The MCFM from Baker Atlas