Formation Evaloation C h r s c Xotcs

1. Reservoir Properties

In-place oil and gas volumes are computed from the following basic equatiob . ,/&L R

Hydrocarbon Volume = AREA * NET PAY THICKNESS * P O R ~ S ~ ~ Y * SATURATION - - -

In determining Net Pay Thicknesses and modelling reservoir production performance P-eabilgy is a fundamental reservoir property.

1.1 Area This is defined from depth structure maps based on seismic and/or geological data. Units would be commonly in sq. fi or sq. m.

Boreholes/wells provide _ t h e h i c h seismic times are tied to -1 Depth structure maps should therefore honour the available well data.

Key borehole data or interpretation techniques:

Well deviation surveys - enable the position of the borehole and the true vertical depth subsea at any measured depth to be defined. Well Correlation - the process by which equivalent horizons are identified between wells.

l' 1.2 Net Pay Thickness Defined from borehole log andlor core data. Units would be commonly ft or m.

8"da Net,pay thickness is the cumulative thickness oQ-eservoir quality rock in the.hydrocarbon &mn, Net pay thicknesses can be defined in each well but for mapping p~rposes~it is preferred to map Gross Thickness and Net/Gross Ratio and to exclude volumes below the Gas or Oil - Water* Contact:

where: 1 Gross Thickness 1 Total thickness of reservoir formation I I Net/Gross Ratio I Net Thickness / Gross Thickness I

Net Thickness I Cumulative thicknesEf reservoir quality rock in reservoir formation

Borehole data provide the primaxy d&acontrol,.~wh_ic_h_~n~~~-o_f_gr,o~.s~agd_ng~~e~~ and net/gross ratlo are Lased. Seismic data and attributes may be used to interpolate properties between wells. Due to boreholes being possibly highly deviated any thicknesses need qualification:

Drilled Thickness Measured interval thickness based on meas_ur_ed depJhs in borehole

Apparent true vertical thickness

True vertical thickness is used in mapping for volumetrics.

True vertical distance between top and base interval as encountered in the borehole. Basedpn.,TV-)_SS depths in borehole.

True Vertical Thickness

True Stratigraphic Thickness

, Key borehole data or interpretation techniques: ,, ',\ - Well deviation surveys - enable the true vertical depth subsea and borehole inclination and direction at any measured depth to be defined.

L ' Dipmeter surveys - enable the dip and azimuth of the reservoir beds to be determined.

/ :i \(*.I Borehole Imaging Logs - enable structural and textural formation properties to be

identified. . , , Core Data (Lithology, Porosity, Permeability) I_J Lithology and porosity sensitive wireline logs (Gamma Ray, Density, Neutron, Sonic etc) p, !

, Permeability and Saturation sensitive wireline logs (SP, Resistivity, Caliper, NMR) ! " ' Well Correlation - the process by which equivalent horizons are identified between wells.

( v f 1 ~ ) . Computed reservoir properties (Lithology, Porosity, saturation, Permeability) \

True vertical thickness of intervalbelgw_top_as encountered in the borehole. Based on TVDSS in borehole and dip of formation. True thickness of interval when measured perpendicular to the dip of the formation

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Formation Evalnatiwi Cosrsc Sores

(70=d c QT - MU?< 0- *A& /-- /I,,s-L-p flqd--- -

1.3 Porosity s ~ i i + ( mi - Y E A Wz Porosity is a measure of the prope~on~_o_f,t~e-~o_&ro.ckIs:_V&U,n!e that is p id /pgepa~~_and _I-. ---- - -- -- -__ _ _

filled wi-s. Porosity is a relative measurement and commonly expressed in decimal/fractional units or else as a percentage. etp ,,q+p

A range of pore types are recognised:

I Total Porosity I The total proportion of pore space in the rock. I

I 1 isolated fluids such as clay bound waters. I

Effective Porosity

Non-effective Porosity

Pores that are in communication such that fluids can pass through the pore system. Voids physically isolated such as by cementation or, through selective dissolution. Physio-chemically

distribution is not necessarily based on the original depositional porosity. Porosity may be developed by chemical processes (moldic, vuggy porosity) or ~hysically induced (fractures)

Matrix Porosity / Primary Porosity

@ ?;Lye' 2 4 ~

Secondary Porosity I

Relationships to note: Total Porosity = Effective Porosity + Non-effective Porosity Matrix Porosity is not necessarily Effective Porosity Secondary Porosity is not necessarily Non-effective Porosity Effective porosities may comprise components of matrix and secondary porosity. Effective porosity may be wholly secondary porosity.

Porosity associated with the fabric of atrix whose distribution is generall- depositional porosity. E..G. intergranular and intercrystalline porosity. Porosity developed subsequent to deposition whose

For assessing hydrocarbon volumetrics, total porosities or effective porosities might be used. Key borehole data or interpretation techniques:

Core Analysis Measurements (Porosity, Porosity at overburden conditions) Porosity sensitive wireline logs (Density, Sonic, Neutron) 1 Log to Core Calibration

I 1 Crossplotting

1.4 Saturation The fluid s a t u r a ~ n i ~ ~ t h e ~ ~ o p ~ i o ~ o f thte~ore %ace that is occupiedbythe.pa&ulaq fluid. For example water saturation is the proportion of the pore space occupied by water. - Saturation is a relative measurement and commonly expressed in decimal/fractional units or else as a percentage. For all saturations the type of fluid should be identified e.g. water saturation, gas saturation, oil saturation.

As saturations are relative to a pore space then they are commonly qualified in similar terms. Not all fluids in h e pore space are mobile,some are bound into the chemical framework of the minerals (e.g. clays) others might trapped by capillary forces or in pores with noeffective permeability. The most typically used classifications are:

-j$h%&- P C L ~ ,/ , , ., , - I Total Fluid Saturation ,/I Proportion of total pCe2- occupied by the fluid I Effective Fluid Saturation ' 1 Proportion of effective p o ~ ~ c e occupied by the fluid

Moveable Fluid Saturation

Residual Fluid Saturation

I I retained by capillary forces, below which saturations cannot I

Proportion o f p o r e g g e occupied by mobile fluid (e.g. moveable oil saturation) Proportion of p-p-a-w occupied by non-moveable fluid

Irreducible Fluid Saturation

I fall unless there is a change in wettability.

(e.g. residual oil saturation) That minimum level of fluid saturation (usually water)

Relationships to note: Effective water saturations are expected to be less than or equal to total water saturations Effective hydrocarbon saturations are expected to be greater than total hydrocarbon saturations Total saturations = Moveable + Residual Saturations In two fluid phase reservoirs (e.g. oil and water, gas and water) Hydrocarbon Saturation - - 1 - Water Saturation

Key borehole data or interpretation techniques: Core analysis data (Fluid saturations, shows, core electrical properties, capillary pressure measurements) i hny-& i kahkn, Mudlog data (Gas levels, shows) / I/

Hydrocarbon sensitive wireline logs (resistivity, density, neutron, EPT) /sd(

Crossplots (Pickett, Hingle)

Formation Evaluation Conrsc. Sows

1.5 Permeability Permeability (K) is the capacity of a reservoir rock to permit fluid flow. The units of permeability are commonly Darcies (D) or millidarcies (mD) where 1000 rnD = 1 D.

Darcy's Law states that: One Darcy is that permeability that will permit a fluid of one centipoise viscosity (p) to flow at a rate of one cubic centimetre per second through a cross- sectional area of 1 square centimetre when the pressure gradient is one atmosphere per centimetre.

Mathematically: K - - O * L * l l

@ * A where: K is permeability (Darcies) p is viscosity of fluid (centipoise) Q is flow rate (cclsec) AP is pressure differential (atmos.) L is length of sample (cm) A is surface area of sample (cm')

Darcy's Law is valid for the following conditions: One single fluid phase occupying 100% or pore space Laminar flow through the sample No reactions between rock and fluid

Because permeability is a function of viscosity, different fluid types will yield different permeabilities in the same rock. Whkn two fluid phases occupy the pore spaces their relative saturations will influence the permeability of each fluid phase. The following qualifying terminology are commonly used:

Specific or Absolute Fluid Permeability

Effective Fluid Permeability

1 Permeability I is dependent on the saturation characteristics of the rock. No units.

Relationships to note: L

Permeability with one fluid phase saturating 100% of the pore space, and as determined in Darcy's equation. E.G. Air permeability &a), water permeability (Kw). Units D or mD. PermeabiFty of a fluid phase when another fluid phasels are present in the pore space. The fluids interfere with each other and reduce the

Relative

Effective permeability < Specific Permeability Relative Permeability to a fluid increases as the saturation of that fluid increases.

specific fluid permeabilities of each phase. Units D or rnD. Ratio of Effective I Specific Permeability, varies with saturation and

Key borehole data or interpretation techniques: Core Data (Specific and relative permeabilities, permeabilities at overburden conditions) Wireline Log Data (SP, resistivities, caliper, NMR) Test data (Pressure build-up analysis)

b-

Formation Evaluation (:orrrsc Yorcs

2. Borehole Data Types

Formation Evaluation is a term often applied instead of "log analysis". It rightly places the emphasis on the object of the log interpretation which is to evaluate as fully possible the formations penetrated by the well bore. Such an interpretation should not restrict itself solely to the log data but should integrate the wide range of information that is usually available from in and around the borehole.

This would include: DRTLLINGDATA GEOLOGICAL DATA GEOPHYSICAL DATA PETROPHYSICAL DATA TESTPRODUCTION DATA

The principle sources of this information are:

1. WELLSITE RECORDS 2. CORES 3. WIRELINE LOGS 4. TESTDATA

Formation Evaluatio~~ C:oursc Notes

2.1 Wellsite Records A wide range of data are gathered and recorded during the drilling and testing of a borehole. They range from data reflecting how the formation drilled plus the physical properties of the mud system, to an analysis of the rock and hydrocarbon samples that may be recovered at the surface.mch of the-information is summa-scfiptive and q@uaLkg called a

The data can be categorised as follows:

BoREHOLE/DRLLING DATA

GEOLOGY

MUD PROPERTIES

HYDROCARBON INDICATIONS

0

Rate of Penetration Drilling Exponent oreh hole Problems Lost Circulation , Deviation .

Mechanical Problems (sanding)

Cuttings Descriptions Core, Sidewall Core Descriptions Sedimentology Biostratigraphy Geochemistry

Mud weight, Viscosity, Water Loss Mud chemistry (KC1, Oil based) Salinity

Cuttings shows (fluorescence, stain, cut) Mud Gas, Mud-cut Gas levels chromatograph gas analysis Mud Weight reductions. Kicks, Blow-outs

Additional records, logs and reports are produced that may provide supporthg or supplementary information. These include:-

* Wellsite Geological Log - Interpreted lithological log . Daily drilling report - Diary of all rig operations Mudreport - Record of mud prope&ei Deviation Survey Report - Record of borehole deviation Pressure log - Pore pressure prehction log

2.2 Core Data Due to the great expense of acquisition, cores are not cut as frequently as the geologist or petrophysicist would like. In exploration they may be cut only in the main reservox objectives and often only if hydrocarbons are detected m the mud or cuttings. A core is us~~y_theemog~@iab&pje.c_e of info,?-go,n. It enables d e t a ~ ~ ~ g e _ o ~ o g ~ _ c a l _and peir-ophysical aspects of the_f_oqQcn. It IS the benc_hrk aga~w~~hthe. interpr~eted~logs are checked and calibrated. Coring and cores yield a wide range of useful mformatlon that includes:

CORINGICORE CONDITION Percentage Recovery Physical condition (fiagrnented, whole)

GEOLOGY Lithology Descnption (wellsite &/lab) Sedimentology Petrology Diagenesis Biostratigraphy w.h$ Geochemistry . f i ..J..-Q>

HYDROCARBON WDICATIONS/Ps/~e -1 Bubblinghleeaing Gas or Oil Oil odour, stain, fluorescence, cut Fluid saturations fiorn retorts [ Lh-i&ta fr/'

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Formation Evah~atioii Colu-sc Notes

2.3 Wireline Log Data Wireline logs are now recorded on every well in the oil and gas exploration and development stages. Tools have been developed to record a wide range of information that reflect properties and changes in and around the borehole. They are the most reliable measurement of depth available. - There has been considerable investment, over the years, in research into new measurements, tools and interpretation techniques.

There are wireline logs that provide vital information on:

BOREHOLE CONDITIONS Caliper, Borehole Geometry Tools Deviation Surveys

Gamma Ray, Spectral Gamma Ray Density Neutron Sonic/Acoustic Photo-electric Factor Gamma ~ ~ e c t r o s c o ~ ~

PERMEABILITYELUID TYPES, HYDROCARBON

GEOLOGY

SP Resistivity Induction Electromagnetic Propagation Thermal Decay Time Nuclear Magnetic Resonance

Sidewall ~ o ~ e s l ~ l i c e s Dipmeter

Borehole Televiewer Sonic Wavetrain Variable Density Microscanner

FORMATION PRESSURE & SAMPLES

Repeat Formation Testers && 7 Formation Interval Testers f f 7

2.4 Test Data One of the principle objectives of formation evaluation is to identifjr and determine the properties of reservoir intervals. Predicting whether zones are going to produce hydrocarbons is one of the more subjective and interpretive aspects. The u l ~ e . 4 u a t i ~ e ~ ~ f a ~ r e s e r ~ o . u ~ ~ tg~,c-~)y,t^e_s,t.jtt~dP.ge-if hydrncarbonsare ~roduced a @ & L x h a t q ! ~ e ~ . ~p~r~na~e_1!~$,_te~~~..maxbe.y$eItake.n~sho~!y ,after-.lagshave .bea-n?p. Th~s leaves the analyst with little time for an initial interpretation. However in .

more detailed evaluations of the data at a later stage (post-mortems) the dormation gained f?om tests can be valuable to the formation evaluation.

1

PRESSURE BUILD-UPS Permeability .

Fractures Reservoir Continuity Faults

PRESSURE GRADIENTS Hydrocarbodfluid Density Fluid Contacts (GasIOiVWater) Permeability Barriers

FLUID ANALYSIS Hydrocarbon Properties (PVT) Water Chemistry, Salinity, Resistivity

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Formation Evaluatioa Cowsc !'iotcs /"

,/'

4. Overview Of Wireline Log Data

Wireline log data are recorded in virtually all petroleum exploration and development wells in the world plus a great many boreholes drilled for other natural resources. Whilst there is a large selection of tool types available, fiom a variety of manufacturers and acquisition companies, they do not all record uniquely different types of data. Many apparently different tools are recording the same fundamental measurements but are specially configured and designed to read the properties of a particular part of the formation. In addition different basic measurements are not always responding to the same attributes of the fonnation. A featureless character response fiom one tool may contrast with hlgh character across the same zone in another measurement. An understanding of the basic measurement principles and the formation attributes to which they are sensitive is important to evaluating and interpreting the data.

4.1 Measurement Principles The majority of commonly run logging tools can be categorised into three groups according to the technologies they apply in measuring formation responses. These comprise:

Radiogenic tools measure radioactive attniutes either as passive tools, monitoring the natural rahoactivity of the formation, or active tools, measuring the effects of the formation on radioactivity sourced fiom the tool. These are responses at the elemental level and involve all components of the formation.

Tools/measurements include: Gamma Ray, Spectral Gamma, Density, Neutron porosity, Photo-

Acoustic tools measure the effects of the formation on an acoustic signal sourced from the tool or some other controlled source. Acoustic properties reflect the physical/mechanical properties of the rock matrix and fluid, that can be described as the 'fabric' of the formation

Tools/measurements include: Sonic/Acoustic Transit Time, Acoustic Waveform, Borehole Scanner.

Electrical tools measure the capacity of the-formation to conduct an electrical current, either by measuring the effect on a current emitted by the tool (laterologs), or by measuring the strength of a current induced to flow in the formation by the tool (induction logs). Electrical properties are controlled by properties and distribution of conductive components in the formation. In porous rocks where pore water is the dominant conductor then pore geometry, a component of the overall 'fabric' of the formation, is a significant influence.

Tools include: LaterologdGuard Logs, Induction, Spherically-focused, Micro-spherically focused, Micrologs, Dipmeters, Electrical Micro-scanners, Induced Polarisation.

A range of other devices are also available that do not fall readily into the categories outlined above, such as;

Spontaneous Potential - measurea with a downhole electrical and present in the borehole against permeable formations where there is an electrical imbalance between the drilling fluid and formation water (ie salinity contrast).

Magnetic Susceptibility magnetic properties -

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Formation Evaloation Coursc Sorcs

Nuclear Magnetic Resonance measures formation response to an electro-magnetic field. Identifies presence of free hydrogen nuclei that would be associated with fieelmobile water or hydrocarbon, and indicate permeable formation.

Electro-magnetic propagation measures formation responses to high frequency electrical currents where electro-magnetic properties dominate the responses. Prime application is in distinguishing hydrocarbons from fresh water.

Gravimeter measures gravitational acceleration downhole that can be computed as a bulk zonal formation density. Applications in locating 'bodies' of density contrast away from the borehole such a salt diapirs. Also been used to compute bulk gas satkitions where borehole logs were inaccurate.

Caliper measures borehole diameter. Paired and oriented calipers can indicate directions of borehole breakout that are related to regional tectonic stresses and often associated with fractured formations.

Formation sampling tools are also available that retrieve rock samples (sidewall coring, core slicing) and formation fluid samples and pressures (formation testers).

4.2 Acquisition Of Wireline Log Data The first electric logs were recorded in 1928 and were fairly simple hand drawn curves based on stationary measurments. Their principle application was for correlation between wells. Todays logs, tools and logging units are by contrast very sophisticated and computerised and the data is evaluated quantitatively to define formation properties with considerable accuracy.

4.2.1 Logging Tools - the Hardware The sensors that record the various formation properties and responses are contained within cylindrical sondes usually of a diameter less than 4 inches (IOcm) and typically 3 318 inches (8.6 cm). Tools of this size can be used in holes 6 inches (15.24 cm) in diameter. In oil and gas exploitation, boreholes are rarely less than this minimum operating diameter. In the mining industry however smaller bit sizes and therfore narrower boreholes are common. Also there are occasions in oillgas wells where smaller bit sizes have been used, or the access of the tools to the borehole is restricted to narrow tubing or drillpipe. Slimhole tools with diameters of 1.5 inches (38 mrn) are available however the range of measurements that can be recorded is much more limited.

Qne of t h ~ e p ~ ~ i ~ l e e @ ~ f i ~ . ~ of the sonde is to protect the sensors from the hostile environment within the b n r e h ~ d ~ l a t m e a ~ . They have to be able to withstand and operate accurately at the high temperatures and pressures that may prevail. Most conventional logging tools are rated to withstand temperatures up to 350 degress F (180 deg.C) and pressures up to 20,000 psi.

onde will generally containteesen- to (eg gamma radiation, resisitivity). However it is comm~nto~attachseyeral sondestogether in a combination.o_o_l. This has the principle advantage of reducing the number of 'trips' down the hole and overall rig-time and cost of the logging operation. TJe nurtlber of sondes that can be combined forany.msunrey.is limited b d e ~ h y s i c d d i m e ~ 1 s i 0 1 1 s - o E t h e - r e s ~ of &able to t r a g s m

information backto-thesurface. The major technological advances of recent years have seen dramatic I_.. -_.- - improvments in the number of responses bemg measured in a single combination tool.

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( 3 9 0 - 3 % ) -

The tools are lowered down the hole on a special multi-core cable that not only supports the weight of the tool but incorporates wu-es to conduct the lnformation fiom the sensors to the recording unit at the surface. It ---- is by measuring the amount of c a b l e m s lzeaspc?_oled outt_% &e precise-depth of-the-tool and g ~ f & ~ ~ m e a s u r e m e n t s i s . l a , r m .

The data are recorded in the logging control unit on magnetic tape in a d@aLf&m The continuous

measurements are sampled and recorded at a uniform increment throughout the logged interval. The merit can vary between logging contractors but is most commonly imperially based at even 6 inches (1.5.20a). Many of the ultimately desired formation characteristics are not measured directly by the

. . sensors but ~ ~ d - i n - t h ~ ~ l ~ a a l s s x ~ s u r f ~ a ~ ~ ~ i p ~ e n t fiom a c-ediate .--- ~ e e a ~ m ~ & These are also usually recorded on tape such that the final data set will-contain a considerable nuinber of formation and tool responses. Unless used for the recomputation of formation characteristics or assessing tool functionality these are of little interpretive value.

4.2.2 Logging Procedures A general sequence of operations has evolved over the years that attempts to ensure that accurate and repeatable data is recorded and that the origin of the data is known. Accurate d e ~ t h registration 1s p@cularl~nt&wigIkel~gdeph-areacc~pted~ asbe ing-~mo-_s t~~cFte measure &,he borehole. They ultimately form the basis for the time-to-depth conversion of s t i s n a d a _---- %&c idedication of formation boundanes and conseauently tbereswair thdcne_sses that are a vital element in m a - and field sirnul-

4.2.3 Depth Registration Involves two basic elements:

4.2.3.1.1.1 Calibration against a known datunt. Thls is usually by establishing zero depth calibration points on the rig floor and the tool that can be easily and visually checked.

4.2.3.I.l.2 Compensation for distortion/stretclr of the cable This is achieved by e k e at uniform and accurately measured intervals (eg e , ~ v ~ ~ ~ ~ O . f t . ) . Knowing the specifications of the cable, weight of the tool and cable, and any compensating bouyancy effects of the borehole mud, corrections can be regulary made.

4.2.4 Data Quality and Repeatability Is demonstrated by:

4.2.4.1.1.1 Recording 'before' and 'afer' survey calibrations Standard tool and panel calibration checks are made before recording a survey and whilst the tool is still at or near the surface. This can be compared to calibration checks made on the equipment at the contractors base to ensure correct functi6nality before lowering the tool to the bottom of the hole. Once the survey has been completed the checks are repeated to ensure the sensors have not gone out of calibration during

logpmg.

4.2.4.1.1.2 Recording a short survey prior to the main run This 'repeat section' should be recorded over a zone with a wide range o 1 , og character but it is usually over the bottom section of the main survey. The object is to demonstrate the iool is functioning correctly in the borehole and that the data recorded is repeatable. Repeat sections usually cover som- (60 m) of the borehole.

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Formation Evaluatio~i Cowsc Sotes

4.2.5 Sequence of events in log data acquisition

Zero depth registration at rig floor (Kelly Bushmg KB, or Rotary Table RT) Lower tool into top of hole. Before Swey)Calibration Checks Tool lowered down hole Additional depth registration checks at seabedlcasing shoes. Tool lowered to bottom of hole to check total depth (TD). Record 'Repeat Section'. Tool lowered to bottom of holelswey interval. Record Main Survey. After Survey Calibration Check. Tool pulled out of hole.

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5. Litho-Typing from Logs, Core & Cuttings Data Lithology typing and zoning involves the integration of data fiom a variety of sourcs. Core gnd _ c u t t i n g s - d e s ~ ~ m s - p . r ~ ~ valuable st art in g po&~dgfin$gb~n~ic_c_J1tSI,~,lggg~. The logs can be assessed with regard to this geological data and often calibrated to reflect the same rock types. Often however the logs,_may,supp-le~nt_~_th~ geological,,dat~~an,d he1.p distinguish the presence of other or rock c-omj~ttha~es:elu&~ing~~b-&~r: o v e r l o o k e d ~ g p J + ~ ~ ~ ~ y ~ s .

Some basic procedures for defining litho-types and assessing log data quality are as follows:

Use cuttings and core descriptions to define principle lithologies. Plot alongside log data. 'Use petrology from cores and cuttings for detailed mineralogy. Plot alongside log data. Divide logs into electro-facies units, these are zones with similar and/or consistent log responses. Use crossplots to define log matridmineral responses. Assess compatibility of log and corelcuttings lithology indications. Determine any calibration adjustments to logs. Generate new crossplots incorporating any calibrated logs and re-assess compatibility of logs and cores/cuttings.

5.1 Lithology Information from Cores and Cuttings The primary informat~on sources from Cores (whole and sidewall cores) and Cuttings will be: - I

- 4 ' 7.

\, .. Mudlogs for detailed 0bls-e descriptions of drill cuttings Wellsite Geologist Lithology Logs for detailed subi,ective descriptions of drill cuttings Composite Logs for summary subiective descriptions of cuttings and core lithologies Core Descriptions for detailed descriptions of lithologies, textures, bedding etc in recovered cores Core Photographs pictures in natural and UV lighting of whole and/or slabbed cores Petrological Studies detailed analysis of minerological and geochemistry of cores and cuttings, including SEM, thin sections etc

Sedimentological Studies detailed descriptions of sedimentological features and depositional environments including thin sections etc

h addition to the descriptive data it is standard practise to record a core gamma ray log, which indicates variations in natural radioactivity along the core. This -- is used to both identify 1daLo.gxal-xariatio-ns in the core and to-enabk-th-a-ore_toOObbeedepth matched to" t h ~ wireline. lo_g_gma.ray.

Formation Eva111 atior~ Coursc 3otcs

5.2 Lithology Sensitive Wireline Logs Logs used for lithotyping are commonly those of radiogenic or acoustic categories of tools. Electrical and other categories of tools can however contribute and may be vital in the absence of other data. Such situations may occur when worlung with old data.

The commonly acquired and principle lithology logs are:

I Gamma Ray I Used as a shale I clay indicator or for

I I identification. Spectral Gamma Ray

Sonic I Acoustic Transit Time

identifying heavy mineral concentrations Used for clay typing and heavy mineral

Used for discriminating between rock s---z, matirx

When assessing any of these logs the Q l q ~ ~ c h o u l d also be assessed to identify borehole washouts and the potential for a n o t g a ~ m s : a s u r e m e n t s .

Density

Neutron

Photo-Electric Factor

The Log Data Sheets summarise the measurement and interpretation principles for each of these tools.

Used for discriminating between lithologies particularly when overlaid with Neutron Used for discriminating between lithologes when overlaid with Density Used for discriminating between rock matrix

types

Borehole imaging logs may also be acquired that provide an image of the borehole wall, based on either electrical or acoustic properties. These are directly comparable to core photographs and enable contrasts between different lithologies, bedding planes and often quite small scale features such as stylolites to be identified.

5.3 Interpreting Lithologies from Wireline Logs No one log measurement, in isolation, is diagnostic of a specific lithology or rock type. The measurement identifies a specific attribute or property of the rock that can be interpreted to indicate a specific rock type.

-#$5.3.1 Homgeneous Formations In homogeneous rocks the mineralogy may be understood and the specific properties '

associated with a range of log measurements known through laboratory experiments and I or published data.

e If a single log measurement records the response associated with a specific mineral than the log response should initially be seen as being consistent with that specific mineral; then

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Formation Evalliatio~~ ( ' o l~nc Yotc\

If reliable core or cuttings information are available then confirmation of the presence of that mineral is c&%?&ed and the log can be used perhaps to more precisely define the vertical extent of the bed and perhaps the homogeneity of the rock.

If reliable core and cuttings data are not available then the measurements from other logs should be examined to see if they are also consistent with that specific mineral. If they ar5 then greater confidence can be gained in the interpretation. If no$then an alternative interpretation needs to be investigated.

In al1,interpretations of lithology from log data then 'GEOLOGICAL COMMONSENSE' has to be applied. This commonsense comes from experience both in geology and in the geographical area and geological formations within which the data were acquired. If two rock types are interpreted in a sequence, does it make geological sense ?

As many of the wireline logs are also sensitive to porosity variat~ons in the formation then the term ~h_o6mdlgg~~~r&~~e_al1y~m,eans zerop_o_rg~i& .mono=rninm~r~a~~n~. Typical log responses in some such rock types include:

" .

; Dolomite / 43.5 2.87 1 2.60 1 3.142 I

f Anhvdrite / 5 1.8 2.97 i 0.00 1 5.055

/ Quartz I 1 Calcite

, - , I t

/ Halite 1 67.0 2.07 1 0.00 1 4.650

Homogeneous formations provide another valuable role in the interpretation of log data, that of a calibration check. Where core and / or cuttings data have established the presence of a known homogeneous formation then a comparison of the measured log responses against published or regionally establish properties can be used to determine:

If the tool is reading correctly The level of calibration adjustment required to ensure the tool is reading correctly

"55.5 2.65 47.5 : 2.71

Such calibration checks are a standard part of assessing and normalising log data prior to any interpretation.

5.3.2 Heterogeneous Formations

E e r e formations are not homogeneous then single diagnostic log responses cannot pxpectgd as the-formation response will be dependent on the relative.proportions of the rock g~aeL~nera1 constituents. However, by combining and comparing measurements from several logs it is possible to interpret the probable rock type and composition through a technique called crossulottig.

-1.50 0.00

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1.806 5.084

Formation Evaluatio~~ Corlrsc 5otcs

C r o s s p b ~ p h i c ~ ~ a E d P l f ~ i _ n . g g i ~ t e ~ r . e l a t i o n s h i p s b e b ~ e e n . ~ , _ ~ ? r ~ s k ~ ~ d ~ ~ . They can be interpreted both qualitatively and quantitatively. They are used to define -&x types, identify minerals and quantify porosity, clay and matrix vroportiog.

I X-Y PLOTS / define matrix types, quantify porosity, clay and matrix. Sigmficance of points and 1 I / trends not evident ffom plots. I

I Z-PLOTS ( indicate maptude of the average value of a third log within each cell. U J 1 I I FREQUENCY &play the number of occurrences per cell. Used to identify the significant

PLOTS clusters.

define clav trends. borehole effects. hvdrocarbon effects plus m e r I influ.

1

Notes on crossplotting: Depth-match the input log data * Boreholecorrect the input data .X

Crossplot in known homogeneous formations to calibrate logs. Crossplot in clean (clay free) formations to define matrix typeslparameters.

,

Use Z-plots to define borehole effects and confirm clay/shale/mineral trends.

1 Neutron v Density 1 Matndmineral definition I Quantifjmg total porosity [ Identifjmg gastlight hydrocarbon

Neutron v Sonic [ Matrudmineral deht ion I I (Unreliable in zones of wggy andlor hcture porosity)

Sonic v Density I Matrix/mineral definition 1 1 (Poor definition of common reservoir minerals and unreliable in zones of wggy I

I

I I andor fkacture porosity) 1

I M v N ! Matrix/mineral and secondary porosity definition I

Density v PEF

I M = 0.01 *(Dtf - Dt)/(Pb - Pf), N = ( G f - 0 ~)l(Pb - Pf) Mid-plot / Matrix definition

Matrix deht ion (Unreliable in barite muds)

From published data and regional knowledge,typical mineral or rock type responses can be defined on crossplots. The position of measured data, relative to known mineral or rock type locations, on the crossplots is used to aid interpretation of the intervals lithology. In simple two mineral lithologies, if data plot midway between the expected locations of the two discrete minerals then the composition can be interpreted as 50% of each mineral.

With experience it is possible to become familiar with the responses of a range of rock types by just examination of the log curves, rather than having to crossplot the data.

6. Correlation

The development of regional stratigraphic and reservoir models relies on the ability of the geoscientist to establish lateral associations within rock sequences. These may be mineralogically consistent and laterally continuous formations which are recognisable from their basic composition (evaporite beds, carbonate shelves, volcanic sheets). They may, however, be time equivalent deposits which laterally change in lithological composition and

. . character. In the petroleum industry. where c o r w d p r e d o m i n e i n t ~ ~

. . direct com-caxm&xkm -- e a prime input to correlating sequences- bety- - .les The wireline logs provide a continuous record of data and as such provide a readily useable vertical profile of the penetrated stratigraphic column.

6.1 Log Correlation Concepts

Chrono-Stratigraphy age-based correlations Litho-Stratigraphy lithogical-based correlations

At a single depth in a borehole the logs are responding to the properties of the formation at that depth and specifically the matrix composition and pore fluid type.

The nature in which the logs change between two depths of different formation composition reflects the nature of the boundary between the formations.

Log correlations can therefore be viewed as initially reflecting litho-stratigraphy, however, t i h a a h i r e of the f o w the vertical seauence dxxackr of the_iogs can re8es, IJd-.

These may be abrupt (unconformities) or transitional (regressions/transgressions) and can have chrono-stratigraphic significance. In addition there may be distinct lithologies which are in themselves time indicators (volcanic ash falls).

Correlatable events can take several forms:

Sharp Formation/Lithological Boundaries Unconformities * Facies boundaries GradationaVTransitional Boundaries Regressive/Transgressive Facies

Changes Sing!e Diagnostic Markers Mineral Concentrations

Volcanic Deposits Diagnostic Formation Responses Organic Rich Rocks /Character Thinly Interbedded Sequences *NB Sharp lithological boundaries in boreholes may also be due to faults. These will be

influential to the correlation but not necessarily correlatable events.

- SECTION 1 .DOC - A. E. Stocks - 0711 1/02 20

Formation Evalaatioa Colwsc >ores

6.2 Correlation Logs . . Ideal correlation logs are those that respond g. Logging tools

are available to measure a wide variety of formation properties however no one single tool is appropriate as a correlation log in every geological environment. A measure of n w

. . . . . formation radhcimtv may be an i j a u e n c e ~ , whereas in interbedded halites and anhydrites could be of little value. A- f o r m a t ~ . ~ ~ e d u ~ t i c a l &

b d e f i n e _ t h e d anhydrites. Consideration needs to be given to the geological sequence and to involving a suite of different wireline log measurements in the correlation. The following criteria for selecting correlation logs is worth consideration:

The logs ideally should: be or have been recorded in the majority of the boreholes, be continuous over much of the interval of interest, have good vertical resolution, be sensitive to the lithological changes expected in the sequence

and in dynamic fluid formations be sensitive to reservoir property changes, be sensitive to formation fluid changes.

An ideal and comprehensive correlation log suite might comprise:

The merits of such a correlation suite include: Good lithological definition in many formation types Enables borehole problems to be detected Good vertical resolution Sufficient alternative logs when oneltwo lack character

: Gamma Ray I Density ; Neutron

Sonic/Acoustic , PEF I Plus in porous and dynamic fluid reservoirs:- / Deep Resistivity I Micro-Resistivity ' SP I

As a data quality indicator:- \

Problems however include: Data not always available (particularly in older wells) Requires special playbacks of logs

Radioactive minerals, Shaliness Lithology, total porosity Lithology, total porosity Lithology, matrix porosity

Lithology Coccb.l--cc-4 /

Permeability, porosity, pore fluids Permeability, bed thickness Permeability, shaliness, fluid salinity

I Caliper I Borehole size, log quality

Large number of traces may be confusing to the inexperienced Overtraclung of multiple curves may obscure the correlation

Standardisation of display formats and scales has been partially achieved, almost by default, in the petroleum sector, but not universally adopted in other industries. Layouts for ' correlation log playbacks are very much personalised by corporate and individual preferences as well as by the nature and objectives of the study. Peoleum,s_tandard --...-. display .. formats . . are --.

targeted _--___. at highlighting -- - reservoir units with porosify, pe rmeab i l i ty~~hydrocarb~~ .~~ . _ _i. I . . __.___.̂ _lll_,._ .,. . _*.- -- .'---'--'

Designed into some of the standard scales, however, are lithological compatibilities such that, for example, d m t y and neutron curves will overlav in -tones at all levels of porosity. - For other applications in mineral exploitation, waste disposal site investigations, geothermal applications, then the target objectives may be best portrayed by customised formats. It&- imperative however that ---- for - correlation exercises. the-sanxformats and-scalesare used.f~a__al_l particip_a~ng_bor_&.o_les,_as correlation is.very muc-h a.visualmatching..of relative and .absoluje wb~~~d,&-.e_nds, Uncertainty in these, due to scale and format differences, unnecessarily complicates the task and increase the potential for misinterpretation.

6.3 Sedimentological Information from Logs

An understanding-of the depositional environments ~Ethesediments .in aresenroirr canaidin -- hecorrelation ofhoth large and small scale litho~gicalu_ni~s. Grain slze vanations are used in sedimentology as an indicator of depositional environments. &ciiinanfly coa_rse.grained sedimentis ass_ocaated with-a_lygh energy - - " - environment whilst fine grained sedimentssyggg>,& quieter condi_tlons, The interpretation can go further as follows:

Coarse Grains I

High energy environment

PyiCY 1 Proximal to sediment source

I If marine: Shallow water . .

I If fluvial: Intra-channel

Fine Grains I

Low energy Environment "

;.,, I Distal from sediment source ,/

I Deep water "'

I Inter-channel

e is lnferredfrnm the lop data bv it's res~onse to clay minerals. C~y-m_i_n_ne.raL~S_are fi_ng grainedand generally associated with quieter depositional cond!tjons. In high energy environments they are winnowed out leaving only the coarser fragments. Clay contents can be estimated from logs by a variety of techniques (see Shaly Formations), and some logs, like the gamma ray and SP can be used in certain formations as direct indicators of clay volume.

( Relatiye.-grain-sizua_n be inferred from the V c l w and used to define vertical changes i, .i~epPasational In selecting a computed clay volume or sin le log clay

$5 indicator the interpreter should be aware of the potential limitations of the, to the techniques. For example the possibility of non-clay radioactive minerals effecting the gamma ray, non-

- SECTION1.DOC - A. E. Stocks - 07/11/02 22

Formation Evaloation C~OUI'SC Sotcs

clay mineral cements effecting the neutron and density logs etc. (see Shaly Formations section).

Th-~rity-of-workonfacies analysis-from logs-hascentred on- the-use~of the-gaqgaxay,gr m a g a a d t k e f o t ~ g r a i n size d i c ~ t , o r ~ ~ The common profiles discussed reflect these logs responses and conventional displays. Q 8 _ c o w e n t i o n a ~ l _ o g p l a - ~ r . ~ - Aes-incmse-to-the_right.ae=track, ~herefxe"high.-clay contents-~d.fing..gaine_ske is ~edteth,e&&~sideeof~eetrtra.c_k. Coarse grained, low claylgamma values to the left.

Four basic patterns of grain size profile are recognised in facies analysis from wireline logs, their shapes are discussed in terms of clay content:

Cylindrical Shape

Bell Shape \

The shapes individually are not diagnostic of a specific facies or environment but can be a valuable aid to correlation in that they indicate changes in the energy of deposition that might be related to regional significant events. For example:

Low clay content bed between high clay content beds, sharp boundaries between the beds. Bed with sharp basal contact and gradationalltransitional upper contact. 'Fining upward sequence'.

+ x ~ e l Shape ,\,

Serrated/Sawtooth

k Upward Fining Sequences

Bed with gradationalltransitional basal contact and sharp upper contact. 'Coarsening upward sequence'. Thinly alternating low clay and high clay content beds, character of individual bed contacts beyond resolution of the data sampling. 'Thinly interbedded seauences'.

suggest Transgression

suggest Regression N-r,

Thergis a fractal aspect to grain size curve shapes, so they should be-examined at differrt S:&S.. Each bed will have its own grain size profile, however so will each stratigraphic unit or formation. Examining grain size curves on a bed by bed basis may only produce a confusing picture of the formation. Looking at the overall grain size profile of the formation may produce a profile of regional correlatable significance. A prime example are deltaic sequences. Th le ra l lgmin sizee~r_ofi!eeof~.pragrgrad~ngde1.taa~~,b,e.issof a c o a ~ e n i n g ~ p ~ tegresskxqumce.. Individual beds in the lobe sequence may display coarsening-up, fining- up, cylindrical or serrated profiles. These individual beds may have limited lateral consistency or continuity and be difficult to correlate. The delta lobe profile however will have a greater regional extent and may reflect eustatic or tectonic changes in the areas geological history.

Major transgressive -- -- events .arszlikely-t~-ha_v_e~regi~na~gi~@ca~e~ andtheir effects might be --.-.--.___ _ --.. expected $0 be seenin.xellswith perhapadiffe~ent~dxxitionnal_enyironmen@. The sediments deposited _- _ ___ at - the.periodpf maximum transgres~ion~gan-be viewed as representing a 'maximum flooding surface'. Within the confines of the flooded or transgressed basin it is a pkriod of deepest water for marine sediments. With perhaps the exception of the coastal

Formation Evaluatiort (:orrr-sc 3otes

margins it represents a point of lowest energy and the deposition of the finest grained sediments. Grain size profiles will be at peak (low grain size) at_this level however the magnitude -- - of the peak will vary across thebas& anddependent on the local depositional e d r o m n t . If such peaks can be recognised and correlated then they will be chronostratigraphic markers, but may cross lithostratigraphic events.

6.4 Additional Correlation Aids Confidence in any correlation can only be gained w m as much borehale _and re- as poswhle Log data may be the ideal base for correlations but should not

be considered the sole source of data. In addition to the preferred or basic log suite a range of supplementary data should be used.

GEOLOGICAL DATA ...

DRILLING DATA ...

Cuttings/Cores/Sidewalls Lithology- Biostratigraphy - Paleontology Mineralogy Sedimentology Hydrocarbon shows Geochemistry

Mudlogs, Drilling Reports Rate of Penetration Overpressure data Lost circulation

RESERVOIR/ROCK PROPERTIES ... Cores/Cuttings/Sidewalls

SEISMIC DATA ...

TEST DATA ...

LOG DATA ...

Porosity/Permeability SCAL data

Surveys, VSP'S Faults Unconfonnities Regional Thickness Trends

DST'S, RFT'S OilIGas properties Water Chemistry Formation Pressures Pressure Gradients

GST, Dipmeter, Scanners Radioactive minerals Clay Types Regional Dip

--

SECTION1 .DOC - A. E. Stocks - 0711 1/02 24

Formation Evaluatioa Course Notes

Stratigraphic dip - Structural features

Unconformities - Fractures - sedimentology

6.5 Correlation Guidelines

Plot data on true vertical depth scales to minirnise distortions in interval thicknesses that might appear with highly deviated wells Correlations should start fiom wells that have the most complete stratigraphic section and most comprehensive data. Large. scale "obvious" correlations should be established first. Correlations should proceed from deep to shallow, up a depositional sequence. Correlatable events should be confirmed from non-log data such as cores and mudlogs. Look for transitional events e.g. transgressive fining upwards sequences, as wells as boundary events. Beware of thickness inconsistencies or differences between wells. Look for lateral facies trends gradually changing the formation character across an area. Be aware for repeated sections or faulted out intervals. That is, take account of the structural and tectonic development.

- SECTION1.DOC - A. E. Stocks - 07111102 25

.)

Formation Evaluation

Course Notes

Section . 2

2 . QUANTITATIVE INTERPRETATION OF POROSITY AND LITHOLOGY ..................... 1

2.1 FORMATION ATTRIBUTES ............................................................................................................ 1 2.2 LOGGING MEASUREMENTS ......................................................................................................... 2

2.2.1 Radiogenic Logs ............................................................................................................... 2 ................................................................................................................... 2.2.2 Acoustic Logs 3

................................................................................................................. 2.2.3 Electrical tools 4 ............................................................................................................... 2.3 CORE MEASUREMENTS 5

...................................................................................................... 2.3.1 Routine Core Anahsis 5 ....................................................................................................... 2.3.2 Special Core Analysis 6

........................................................................................ 2.4 CALIBRATING LOGS WITH CORE DATA 7 .............................................................................................. 2.4.1 Depth Matching Core Data 7

2.4.2 Calibrating log data ......................................................................................................... 8 2.4.3 Establishing Parameters .................................................................................................. 8

2.5 SENSITIVITY OF LOGS TO PORE TYPES ...................................................................................... 10 ................................................ 2.6 QUANTITATIVE INTERPRETATION OF LITHOLOGY & POROSITY 1 2

2.6.1 Homogeneous Formations ............................................................................................. 12 ........................................................................................................... 2.6.2 Shaly Formations 14

2.6.3 Heterogeneous (Complex) Formations ........................................................................... 21 2.6.4 Dual and Complex P o r o s i ~ Formations ........................................................................ 22

2.7 HYDROCARBON EFFECTS ON LOGS ....................................................................... :. .................. 28 2.7.1 Correcting Logs for Hydrocarbon .................................................................................. 28

Formation Evaluation Coorsc Notes

2. Quantitative Interpretation of Porosity and Lithology Wireline logs and cores are commonly used to quantitatively determine the porosity and lithological I mineralogical composition of the formation. The v a r i o u w .

PfO-& m e a s u r e ~ ~ s ~ n n n b e n n r e l a t e d , t ~ i n e r a l o ~ nature of t.hedhds& the pore s p , a c e s ~ c a t - h . b 1 u t ~ r ~ ~ ~ ~ , @ ~ e .

2.1 Formation attributes The nature of the measurements and the formation attributes to which they are responding dictate the applications to which they can be applied. For example, many of the common rock forming minerals are electncally non-conductive so the electrical devices are not generally appropriate for malung a volumetnc mineralogical analysis. Similarly, there is not expected to be a definableldiscernible difference in natural radioactivity between oil and water in a reservoir, so a gamma ray would not be appropriate for defining water saturations.

Three attributes of the formation control the bulk of the logging tool responses and core measurements :

Mineralogy dictates the bulk properties of, such as density, acoustic transit time, radioactivity, and is most influential to the radiogenic lops.

Pore Fluid i n f l w e s the b-.f the formation and measurements _deDendent on the pore fluids as the cod&-. Has greatest influence on the electrical h, lihle or no effect on the gamma ray, and effects acoustic responses where porosities are high or fluids have low density (gas).

FabridTexture relates to the distributi-k folmat_l_szn components within the rock. This is most signifidanm porosity where the continuity and geometry of the pore space influences the electrical logs in particular but also the acoustic measurements. The distribution of other conductive minerals, such as clay and pyrite, will also influence such measurements.

No ane log or core measurement is capable of describing all attributes of the formation so to fully appraise a zone a suite of logs and core analysis measurements are required to enable a comprehensive assessment to be made.

Formation Evaluatio~l Course Notcs

2.2 Logging Measurements

In the majority of cases the fundamental measurement of the loggmg sonde involves some additional processing by the acquisition company to generate the final data. n e transforrnatiw Eocess generally involves the application of some calibration function to convert from the ~ t s t a t a n ~ U ~ ~ un ib In many situations an understanding of - the basic measurement principles is not essential to interpreting the resultant data, however, may be of significance in situations that are not adequately represented by the fundamental calibration data. T ' e u t r o n log presents data in porosity units but the tool is calibrated blocks so is onlu_a-. In other formations transformations or corrections are required to convert to actual formation porosities.

Wireline log data is typically uniformly incremented and statistically averaged to represent Q properties of a sampled interval. Because their is a strong along-borehole dimension to the

data acquisition (receiver and transmitted located on same tool axis), and transmitter-receiver spacings are usually greater than the required sampling increment, then the resultant data presented for one increment will not be uniquely from that increment. This causes a 'bed b ~ ~ ~ h ~ 1 u ~ ~ e ~ p s = ~ 1 . ~ e ~ b 1 ; c $ : m s i b a a l ~ , a ~ w e lopAafthrnhprlcnndlarmnatlonfmav_not- careful consideration is, required when interpreting the data to take into account both the scales of distribution of the economic component ( e.g. the oil sand bed thickness, or the ore body thickness) and the wireline log data.

Measurement principles are summarised for each of the common loggmg tools and discussed by category of tool below.

2.2.1 Radiogenic Logs Y**l

. . IC l n g s - a ~ : e w ~ g ch- -n at ~e

d a n t a l a&. The basic composition of minerals and fluids will contribute to the responses. The relative disposition of the minerals and fluids is largely not influential on the measurements.

Passive Tools

Measure the natural gamma radioactivity emitted by the formation. Two common tools are run:

Gamma Ray Total gamma levels. Sonde commonly attached to other sondes to act as a correlation or depth reference curve. < ww+

Spectral Gamma Examines the gamma ray emission spectra to yield proportions of potassium 40, #,

thorium and uranium in the formation. mt

Active Tools Measure the formations effect on a radioactive energy sourced from the tool.

Density Log Measures the reduction in energy of gamma rays as they pass through the' formation. E n ! loss is depenchm~lf:kc.tbon density but is converted to and reported as ahulk formation density.

Compensated Neutron Measures the reduction in thermal neutron energy of high energy

Log neutrons ermtted by the tool, as they pass through the formation. The energy reduction is attributed to hydrogen atoms in water and the tool reswnse t ransf~q~ed ma a hvdrogenir&ex to an gparent 1imes.ne

Po- Photo-Electric Factor Csntra lev-Me- and l-ends B-

~ s _ r t r m ~ h @ & o a L Differences are attributable to photo- electric absorption, a property dormnated by the *era& of the formation.

Thermal Decay Time ~ t h e r m a ~ m & ~ s ~ a ~ ~ e cross,se_c&nfiipma) b y s ~ n $ o ~ g t-ecayafdymnaL neutrons ermttedhy Ae~onl, C m n e is the strongest common neutron absorber, and o~urg-m_st-commonly,asa d1~~1ye4,gJJ in formation water. The TDT is interpreted to rap.md dormnantly to saline waters _k.thef~-ma_~~., however there are sigma vanations between rmnerals

2.2.2 Acoustic Logs . .

The a c o u ~ l n ~ n ~ r \ l r r l l n n ~ m e c h ~ of the rock that comm-ise its fabric. The acoustic properties of the constituent rmnerals will dictate the base matrix response however the relative form and textural disposition of the minerals will have a significant influence on the acoustic properties of the formation.

Sonic/Acoustic Log Measures --- the -formation- interval-transit .. time of _an-acwstic s ~ l B e d by t b - ~ l . Vanous configurations of tools are available with different source to receiver spacings. Records transit time in rmcroseconds/foot (or metre) of the compressional wave.

Acoustic Waveford Records sonic wavetrain resulting from an acoustic sipnal ernitt- Variable Density mL Enables analysis of compr~ional and s b r waves and has

applications in fracture detection and c w . Borehole Scanner/ S c a n s - t h e b o - r - a l L m L a - m t a h n g - u l t r a ~ ~ d ~ . The Televiewer patterns of acoustic reflectance p m a g % , Q t : - t h e - m

yariat10nsofthe,,har.&ole~al1. These can indicate -frac=s, however, the s!gnaLdetemxate -m--mgase-zr e l o ~ g z e bb~~hszleshszles

Formation Evalimtio~i Coursc %ores

2.2.3 Electrical tools . .

Measure t h e e ~ e g ~ r x x s i s t i u t g ~ i & transmitting-nt into the formation -&-flow in the f o r m a i . The conductivity of the rock will depend on the amount of conductive components present and the continuity of these components. The most common conductive component is water in the pore space. The measurements are consequently related to the physical volumes of the pore water and also the pore geometry, a textural attribute of the formation.

Focussed Resistivity These tools transmit an electrical current into the formation and measure Logs the strength of the current returning to another sensor on the tool. Tools

canke configu_edto_ me_a.u-e_cpmLu&vjities or resisjivities.at.armeaf -*~- Induction Logs Useaa~tr&m~grl~;.fi&&~~dy~ac~ntg~inffonnJa ion

around the b o r e h a l e . s u r e t h e T o o l s can be configured to measure conductivities or resistivities at medium and deep depths of investigation. ---

Dipmeter Tools Use multiple micro-resistivity measurements to d g f i e k n d a r i e s and use these with-~~oscopic . rr measurements of tool azimuth and inclination to d - p ! t & f i i Use multiple measurements of rnicro-resistivity to create a graphic image of the borehole wall. These can be interpreted to define bedding dips, fractures and other textural rock qualities.

Electrical Micro- scanners

2.3 Core Measurements Geolo!zical control data is ~ ~ m , a f e ~ ~ ~ u i r g d J p ~ h e ~ u ~ ~ e ~ ~ f u 1 ~ . e ~ 1 ~ i a ~ ~ 0 ~ ~ ~ -This may take the form of geochemical analysis of rock samples to determine the mineralogical composition or the laboratory determination of one or more key components or attributes that can be used to benchmark the results. The control data would normally focus on a key economically significant component, such as pmmity in the petroleum industry or ore grade in minerals exploitation. However in makmg comparisons between the data sets for validation of parameters and components it is important to recognise the scale differences between the data sets. Analyses of core or rock samples are typically on sm811, sometimes minute fragments. The sampling frequency can be extremely variable and range from uniformly incremental every 1 foot (30 cm) to highly selective clustered analysis.

In the petroleum industry core measurements are commonly referred to under two categories:

/

Routine Core Analysis (RCAL)

W A L ) Special Core Analysis

,DL+ . s - sV\ , 2.3.1 Routine Core Analysis - '

Thls covers thP.asurefa3~nts r o * & - . c a ~ e d m t t , ~ & g m e c o v - they are sometimes referred to as 'conventional core analvsis measurements'. The plugs are usually cu - L h , m . z l n t o t h e i d e of the core (perpendicular to the core axis), but in some circumstance be inclined to be cut parallel to the bedding of the cored sediments, if these are dipping relative to the core axis. Vertical vlum may also be cut and s a a F z ~ ~ m & s i s although commonly such plugs are less frequent. The orientation of any plug is usually ~ ~ - t ~ ~ s i ~ ~ . RCAL measurements are carried out under laboratory (that is surface / ambient / atmospheric) conditions of temperature and pressure and conventionally include:

Grain Denslty Bulk denslty of the rock rnamx (glcc) i Porosity / Porosity of the plug sample by either gas extraction or fluid summation

1 techniaues (frac or %) 1 / Permeability ; Permeability to air along the long axis of the plug (mD)

I Fluid 1 Saturations of water, oil or gas in the plug pore space (frac or %)

1 Saturations I

The core data information sheets summarise the processing techniques for each of these measurements.

Formation Evaloation Coarsc Norcs

Other measurements might be include in a RCAL program at the clients request. For example c m m a y be routinely undertaken in carbonate reservoirs.

2.3.2 Special Core Analysis These are specific specialised measurements requested by the operating oil company and usually undertaken some time after the well has been drilled. Due to the potential damage and deterioration of core sample~section~of core or selected core plugs may be preserved soon after acquisition of the core for later SCAL. processing. The selection of core plugs for SCAL ~ i n g & usually very subjective to focus or specific i n h a l s or racktyspzwf in te res m d commonly will a the range of rock or facies types that have been identified in the hmuhmbmK - a - g p m e l i n e log data. The range of typical SCAL. measurements include the following:

1 Porosity at overburden pressure I Porosities measured at a range of confining pressures. j Permeability at overburden pressure .i Permeability measured at a range of confining 1 i pressures. I Formation Resistivity Factor (FRF) i Electrical properties of wa&r saturated plugs to

I establish ore gecmetrv characteristics and the I I

f cementation factor parameter 'm' , I FRF at overburden pressure i FRF at a range of confining pressures. , ' Resistivity Index (RI) I , Electrical properties in plugs at varyinp: water I , j saturations to establish satugtion characteristics and 1 i j the saturation exponent 'n' I RI at overburden pressure I RI at a range of confining pressures I i Capillary Pressure I , To establish capillary effects on fluid saturations and 1

I , I can be undertaken with a range 6f saturating fluids I I

! / (brine, oil, mercury). Mercury injection used for I 1 j determining pore size distributions. ; Relative Permeability I Establishes relative permeability relationships

1 / between two fluid phases. 1 Cation Exchange Capacity (CEC) Used to define Qv-porosity relationships required for

1 specific water saturation models. I The core data sheets include descriptions of some of these measurements, others are referred to elsewhere in the notes.

2.4 Calibrating logs with Core Data The objectives of calibrating log and core data are to:-

CalibrateICorrect log data Establish Parameters for dtdifi~ngfonnatiop properties from the logs alone.

The information gained fkom cores comes as descriptive and numeric data. There are the summary or detailed descriptions of the lithological, sedimefalaglrul and petrographical properties of the rocks, plus the results of lab* analvsis on core plugs or whole core sections.

It is the rgutins core anam data that gixes_the--r nf the core to enable calibration with the-. Before calibration can be considered then accurate depth matching of cores to logs is required.

2.4.1 Depth Matching Core Data

Rules/Guides to Core Depth Registration The depths assigned to boxed cores are based on the driller's' measured depth of the hole prior to running in with the core barrel.

The total cored interval is calculated from the driller's measured depths before and after coring. The total core recovered is the total length of core measured at the rig floor. The percentage recovery equals 100 * total core recovered %

/

total cored interval. I%/ h e rt_tg%h '0

-7,fw (m c &&d4 Where the percentage recovery is less than 100% then the non-recovered core is assumed to be from the bottom of the cored interval.

These standard pmazdus_ta_c-depthxxgi stration enwe-g ,c_o_nsis3cnc~~fappf~~a~b. They do not necessarily provide a reliable guide to the origin of the cores and core fragments. It is probably unusual for whole cores to be recovered as a single piece of core. Frequently the cores are locally fragmented and in some cases reduced to rubble. Accurate measurements or estimates of total core f ~ e is consequently difficult. S~larlydnllerls-de.@- g.bwamlly with lo; de~ths . I ~ ~ . b ~ ~ t h a t ~ m ~ d - j u ~ h n e n . t s t o ~ t h s will be wpmdLamat&&e&ta+hPl~g-data.

Depth Matching Whilst the 1 1 1 overall mamagnitude of depth corrections to be made to the cares., it is the routine core analysis data that will highlight the :ubtle variations thaJ~-qy-~skr within a single cored interval. Data overlays to be considered: -

Formation Evalilation Coilrsc Notes

I Core Gamma Log: I Gamma Ray Log: I I Core porosity I Density/Sonic/Neutron logs 1 I Grain Density [ DensityISonic 1 1 Core Permeabilitv I ResistivitvISP I

Overlays should be at small scales such as 1 :200 or even 1 : 100 to highlight subtle changes in the depth adjustments. Important considerations:-

Core data should not be "lost" in making depth adjustments. Linearhlock shifting of the data on computers should be used to avoid changing the data values. Differential depth adjustments should be avoided in intervals where continuous whole core were recovered. Rubble zones or other discontinuities in the core should be used to account for any differential depth shifts between core and log.

2.4.2 Calibrating log data The quality of the logs in reliably measuring the formation properties can be achieved in an indirect manner, by observing responses against type lithologies (anhydrite, salt), or by numerical calibration against laboratory data.

Matrix Properties:- Core matrix densities (averaged) can be used to calibrate apparent ma&x densities and responses indicated from crossplots. A correct- tm-tate a bulk shift to all data va.lues.

Porosities:- Core porosities (a- plotted) can be visually or statistically compared to log derived porosities and an adjustment calculated. This may result in a buIJubu3 to all data v a l u ! .

2.4.3 Establishing Parameters In unitisation agreements it is common practise to establish statistical relationships between core data and logs to define porosity. These may take several forms:

Log v Porosity Regression analysis between log values (L) and core porosities ( 0 - fractional) to establish the matrix (Lma) and fluid (Lf) responses of a conventional linear porosity equation,

0= Lma-L Lma - Lf

This technique will produce the best statistical fit between the core and log data, however the apparent matrix and fluid responses may be unrealistic values. This may be most noticeable where only a small number of samples are available.

Formation Evaluation ( ' o ~ ~ r w \orc4

Grain density weighted Regression Analysis. V_sgx~£~gressuzn analysislreduced - m a ~ o r ~ x i S t ~ ~ q u ~ t t ~ ~ b 1 i s h a best& line p&sing t b v porositv and the average zone matrix &xuty. This line produces an apparent fluid response whichi can be used in the equation above. This process may be performed on an individual well basis or from samples from multiple wells.

Grain Density and Data centroid. Depth matched core porosity data are crossplotted against a log measurement (usually density). A line is defined through the average grain density, fiom RCAL data, and a point representing the centroid of the data.Ee centroid value is based on the average core porosity and average log response at those core data locations. The technique honours the grain density data and ensures that average log derived porosities match those of the cores. h e t e r a g e n e c l u ~ ~ n n a t i o n s - t h e - r e ~ u 1 ~ g J l n e m a y j l Q t - b ~ ~ i & ~ ~ ~ ~ - -

and the implied fluid density may not be compatible with the known pore fluids.

Formation Evaluatio~l Coursc Xotos

J 2.5 Sensitivity of Logs to Pore Types In the broad facets of geology pore spaces are categorised by different criteria. A petrologist recognises primary and secondary porosity according to their time of development. A carbonate specialist will classify porosity in terms of its relationship to the rock fabric and origmal constituents (intercrystalline, vuggy, moldic, fracture etc.). The wireline log data cannot distingksh such subtleties but is sensitive to the distribution of pore spaces in the rock. Log analysts tend to use the terms matrix and secondary porosity, which sometimes conflicts with the petrologists definitions.

/

In terms of evaluating hydrocarbon reservoirs then the petrological classification of porosity is not directly relevantuMore significant is whether the porosity is effective in having permeability, or non-effective, and malung no contribution to reservoir fluid production.

Petrological Considerations Matrix Porosity Intergranular, intercrystalline, growth framework. (Distribution generally

based on original depositional porosity, i.e. primary porosity). Secondary Porosity Moldic, vuggy (chemically induced). Fracture (Physically induced)

(Distribution not based on origmal depositional porosity)

Reservoir Quality Considerations Effective Porosity Void space linked by effective permeability. Non-Effective Porosity Physically isolated voids such as vugs, partially sealed fractures, pores

with blocked throats. Physio-chemically isolated voids such as bound clay water.

In log evaluation terms Total Porosity is the total void space in the formation.

Total Porosity = Effective porosity + Non-Effective Porosity

The wireline logs do not all respond compatibly with each other with regards porosity. This results from the specific formation property being measured and the measurement technique. I n ~ - t e n n s the ~ t a t i s ~ ~ ~ ~ . ~ l ~ radi ' ~ p t z d - ~ W d o r n a + i o n a ~ d ~ e e v h i p u o - ~ The specific measurem-es such as sonic and res- a ~ e m i t k z t a p a r i - t h e j i Q n - a n d are sensitive to only specific pore types.

i Formation Density Log Measures the bulk density of total rock. / Sensitive to Total Porosity i

; Neutron Log , Detects Hydrogen content of total rock. I Sensitive to Total Porosity i Sonic/Acoustic

2

I Records matrix transit times. Isolated 1 Sensitive to Matrix Porosity porosity in vugs or fractures may not 1 I

I

, intercept transit path. ! I I Resistivity I Measures resistance of total pore 1 Sensitive to Effective Porosity

I network to an electncal current. Pores , I j are required to be in communication. I E.P.T. ! Responds to water content of total

I / Sensitive to Total Porosity

j i formation. I

Formation Evaluation Coersc Kotes

1 2 . 6 Quantitative Interpretation of Lithology & Porosity

The interpretation principles for many of the tools also tend to be based on generalisations which may be adequate for the majority of cases but are not applicable in some specific circumstances. An understanding of the measurement principles plus the formation constituents is required to assess the validity of any interpretation technique.

The simplest interpretation techniques can be applied in simple homogeneous formations, however, as the rock becomes lithologically 1 mineralogically more complex and heterogeneous then so do the techniques required to evaluate them.

2.6.1 Homogeneous Formations

The radiogenic logs, gamma ray, density, neutron and photo-electric factor, a~exespon&g - . to bulkeiemental-propd~.s~f the formation. In homogeneous pure mineral deposits these properties can be unique enough to identify the mineral type, particularly when there is some geologcal expectation of the potential candidates. The prime example is evaporite sequences where density alone can

Lithology Tables of log responses to a wide range of rock forming minerals are published by the main logging contractor's and provide a basic reference for identifying homogeneous and none porous lithologies.

In petroleum basin -orous homogamms fo-ited to eapan t s and b ht tadmak~ In such intervals then cuttings and perhaps core data will be the primary indicator of lith~logies and the logs used to define more precisely the depth extent and thicknesses of the homogeneous units. Confi-& should be g u q & t f r d a ~ _ a i l a b l e lagsather than just one. an&s;rcassphts used as an interpretative &al. Cuttlngs descriptions a c e - n a t a l w a y s a c a d y e to contamin&-1~s of sa-s, and in such cases the logs provide the verification and detail. For example:

Halite intervals, drilled with low salinity water based muds, may not produce any cuttings at surface. Uncompacted formations and coals may contaminate samples for many hundreds of feet beneath. Soft clays in clastic intervals may become easily washed out of cuttings samples prior to examination and intervals reported as clean sand.

Porosity Homogeneous formations have consistent and uniform lithological properties throughout their thickness. In log interpretation they can be confused with "clean" formations.

The term " c l e a a o r n & g ~ & ~ o ~ ~ a l y ~sed~tsz,d~s,c~ri be formationsthat have l i w x n ~ - clay-or shale c w By this definition though a "clean" formation may not be homogeneous.

. . Dolomitic limestones may show c o o but h a v w .

&.rdarly b ~ ~ g g ~ g ~ ~ ~ t ~ ~ ~ ~ e ~ o t be c m r i s e d of o-e such as DW p r t z sands or calcite lime-s-. If a sandstone has a consistent 10% content of calcite as a cement throughout its whole thickness it can be described as homogeneous.

In 1 o g analysis, @ ~ ~ g g ~ g ~ ~ ~ ~ ~ u o , i ; ~ - ~ , a n ~ _ b ~ o , c ~ ~ ~ e _ & L % l a t i ~ ~ - o ~ ~ L ~ ~ i ~ g l $ : & g s are required to cornp_ute_J2aras1S1%.~. Standard equations based on tool response equations are used.

--- - -- -

Log Pore Type Equation 4 Density (P) Log Total Porosity = (Pma - Pbl)/(Pma - Pf) 9 Neutron (N) Log Total Porosity = (N1 - Nma)/(Nf - Nma)

Sonic @T) Log (Wyllie Method) Matrix Porosity = (Dtf - Dtl)/(DTf - DTma)

(Raymer-Hunt Method) Porosity = - a - [a2 + Dtma/Dtl - 1] 05 where a = (Dtma/(2*Dtf)) -1

EPT (TPL) (Tpo method) Total Porosity = (tpo - tpma)/( tpf - tpma)

where tpo' = tp12 - A C ~ 13604, Ac = attenuation E 6 c ~ ~ m ~ ~ ' ~ :

k Resistivity (Rt) Effective Porosity = ( a * ~ w / ~ t ) l / ~ f'(0 jy? a b-v.

where m = cementation factor /-

a = Archie constant 1 ,-4. Rw = Formation water resistivity

- -- --

The suffixes f - indicates response to pore fluid (water) ma - indicates response to matnx 1 - indicates measured log value

All these relationships can be expressed graphicdly and most (density, neutron, sonic-Wyllie, EPT) by simple linear scaled plots.

i0.q e Before the days of computer, log analysis and calculators,porosity estimates from logs were undertaken using simple graphs and charts, either as published by the logging contractors or constructed manually.

4 ~ 1 1 ., - log methods, with the exception of the resistivity logs, requireCmam and f l l d properties be d h e d p ~ - 1 ~ b t a m a h . g t h e - p m a s i ~ ~ T h e following sources of these

parameters can be used: Published standard parameters Measured in samples from the specific borehole or field Interpreted from borehole data

Formation Evalaation Course Notes

Published Standard Parameters Should only be u s e d well d & ~ n d only where other data does not c-. Derived from logging contractor chart books or other publications. Can b where there is little uncertainty of the matrix tvoe and uor-

-+ . Matrix type wilLindicated by geological data, the fluid type may be assumed from regional knowledge or expectation. From a fluid point of view the key issues are:

- is the formation water bearing ? - is the water likely to be fresh, intermediate salinity or salt saturated ? - is the formation hydrocarbon bearing ? - is the hydrocarbon likely to be oil, condensate or gas ?

Measured in samples from the specific borehole or field These are the preferred source as they are specific to the well or formation interval

. . .lkkQ&

properties might be defined from c o r e a e t r o g r a u h i D e -,

measured -prns. ..- Fluid samples of water and hydrocarbons might have been recovered and actual properties of specific gravity measured. If the data are from another borehole in the field or prospect then only that from the equivalent formation or zone, to the borehole being analysed, should be considered relevant. If data are available from a number of boreholes in the field or prospect area then consideration should be given to adopting mean values, or interpolating values if regional trends are evident.

Interpreted from borehole data 1 data. core,

. . d a f a m u h ~ s i - - Options include: - crossplotting neutron v density, neutron v sonic and density v PEF data to determine whether the logs are compatible with the mineralogy/rock type indicated by cuttings or core. If so standard published parameters for the minerallrock type can be justified to be used. - ca1ibyatingAa.g. d a t a - t e ~ _ m e a s u r _ e d e s - ~ s i Q ~ ~ ~

These define a function relating the two data types from which the log response at zero porosity (apparent matrix resp~nse) and 100% porosity (apparent fluid response) can be computed. If these apparent parameters are geologically reasonable based on cuttings or core information and expected formation fluids, then they can be used (see Calibrating logs to Core Data).

L/ 2.6.2 Sbaly Formations /I_$ Petmleum reservoirs are li-ttologicallv homogeneous. Shales or clays are a common constituent are usually the second most significant component after the quartz or carbonate matrix. Shale or clay beds are not good reservoir rocks, lacking both effective porosity and permeability. Th%iaac.kusion of shale par_ticles and clay_minerals-Wi.thin~san4~0;1e or carbonate m a w d to redur.etk g u a I i _ s f t h e f o m a ~ b s a s . . s ~ r e s t ~ ~ r ~ ~

Clay minerals require special attention because of their specific effects on the reservoir and the log data. Fro-ma reservoir ~ u a l ~ p m n t of view, t w to reduce porosity and pemabili-d can act as barriers to the lateral and vertical flow cdilwds. -h

. . . . . m c i a t e d w a t e r e r ~ ~ ~ ~ g g w e y . e ~ p ~ a ~ ~ h s . Their properties can vary dramatically between and within wells so they cannot be treated universally as many other minerals are.

Claylshale beds however are the anchor points of many geological correlations, and often the source o -bans. T h e l r _ p r e ~ i s ~ c k ~ o s i t i o n a l envito id vertica 1 w i a t i o ~ t r i b u t e t r i ~ ~ ~ ~ d ~ u & n g & e sedimentologigl and,

. . P s f a - t b m o n .

The evaluation of shaly formations and in particular shaly sands has been a long standing problem and the topic of many technical papers and books.

. . i'

A . 6 . 2 . 1 Distribution of Shales In the petrophysical evaluation of reservoirs and formations we classify their disposition relative to the matrix and pore spaces. Three clayhhale distribution models are recognised:

Laminated 1 discrete layers of clay that divide the non-clay matrix (e.g. sandstone) into discrete / layers. The clay layers contain only clay and are laterally continuous. The clays are

I I syn-depositional with the non-clay matrix. The layer thicknesses may range from less than 1 cm (laminations) to over a metre, where they are clay beds rather than laminations. The key distinctive characteristic is that 100% clay only bedsflaminae separate 0% clay bedsflaminae. Typical examples are distal deltaic and turbidite sequences.

/ structural I discrete particles, fragments or pieces of claylshale that form part of the matrix I

i 1 alongsidefie non-clay matrix grains. Effective porosity mav exist between clav and i C.: - b - I .-- / non-clay particles. The clays are syn-depositional with the non-clay matrix and reflect

G3' L e ( . a mixed sediment supply. An extreme example is a conglomerate . --- containing auartz and

To summarise thk disposition of the clays relative to the matrix and pore space: Laminated Clavs replace matrix and porosity Structural Clavsreplace matrix only Dispersed Clavs . replace porosity only

I

Dispersed ffc hi.--.

G,F MA>'< jfl

These classifications help us to understand how clays will effect the logs responses and reservoir properties. Unfortunately in reality they rarely occur in isolation. What is generally

apebbles/clasts. clays that occupy the pore spaces of the formation. These clays are dominantly a- depositional -'c in origin. The matnx mav be non-clay or also contain clav -. The maxlmum amount of dispersed clay in a formation is limited to the w r K

9'3 volume. Dispersed clays are present in a wide vanety of rock types, however prime

1 Formation Evalnation Coursc Sotes

described as a shaly formation will probably contain combinations of two or all the clay types.

J 2.6.2.2 Effects of Clay on Logs The clav describes -1e is commonlv used to

m. Shales are rarely if ever composed of only one clay mineral. They are frequently a mixture of clays and coarser grained (fine) silts and sands. The amount of associated or b & ~ w i l l vary depending on burial depth and tectonic histghy. It is impossible therefore to define global or even regional parameters for shale properties and shale log responses. Each formation and well has to be treated on its own merits until a regional value has been substantiated.

Whilst it is usually easy to recognise clay and shales on the logs it is not easy or possible to define consistent log responses. For a start they rarely if ever occur as pure single clay minerals, they are usually a mixture of clays plus other none clay components. Th-n

both that are not so evident in other lithologies. As a general rule c- m h their radioacticty. neutron p ~ s _ i ~ , I ~ & e ~ e ~ h i 1 i ~ ~ a w d l o w ~ r ~ s _ e p u a r s ~ -resistivities. A log used in isolation however can be misleading in its indications of clay so use of all available logs is essential to be confident of the interpretation.

Density

Neutron r

The majority of clay minerals contain Potassium (K) so will contribute to an increased gamma ray level. If the NGT log is run then the high Potassium and low Uranium and Thorium,contents will help distinguish clays from other radioactive minerals. The amountlof potassium varies with clay mineral types such that the illitic clays (muscovite, biotite, illite) will produce a higher gamma contribution than montmorillonite, whilst bothkaolinite and chlorite have only low percentages ( 4 % ) of Potassium. Thorium however also contributes to the gamma response and can be ratioed against the Potassium content to help distinguish clay types and glauconite. The density of the clay is primarily dominated bv the bound water content and as such can be extremely variable. There may be little differences between non-clays and clays in-situ, alternatively in well compacted s e c b m a k h ~ M e n s i t ~ c- clav beds. ~e-baunhuter-~ontentofc1ap - w i ~ L a ~ ~ a . y s . b b e ~ e _ ~ ~ t h e n ~ ~ g as an iappmpaxmtg. It's level compared to the non-clay formations will depend on the porosity and mineral type of the non-clay part of the formation. commonly in shaly

neutron moves to higher apparent porosities in Th~ac_o~~ccpropP~~CLE-C1a~areed~minateddbyYtheebound -water-c,ont-ent. In undercompacted sediments transit times well in excess of 100 mslft are recorded. In compacted sediments there may be no clear distinction between clays and non-clays. The varying bound water content should be largely to the PEF curve, enabling distinction between some clay mineral types. Unfo-y in &&um& the co- -s yerv close to n-easily. Only chlorite, biotite and nlauconite have significantly different vroverties to be definable from auartz.

Resistivity ' addit' T 5 -t in the formatio_p. The resistivity of the clays will d=end.gn&texolg- res- As clays are supposed to be non-permeable then a.lJ r e s i w t y measurements are expected to overlay in clay beds. Clay minerals have a negative charge due to substitutions of atoms within the lattice. These charges are partially balanced by the adsorption of counter-ions on the clay surface. These counter-ions can be easily exchanged for other cations in the pore fluid. The amount of exchangeable ions is called the cation exchange capacity (CEC meq1100 gms of dry clay) and is larger in clays with a high surface area. This high concentration of counter-ions at ~ ~ ~ ~ S U r f a c e e ~ s I ~ s ~ I ! ~ b ~ e e f o x I t h ~ ~ c t i ~ i ~ s f i a l Y sands. Th.e~effect_t_of~l,aysssgn, r ~ e s k t i ~ . t y - i d e p e n d e n ~ ~ t h e s e ~ ~ . ( ; ~ b h s t h ~ t ~ a f day and the clay type The SP requires permeability to bring the borehole and formation fluids into contact. The particular presence of hni&ged.a_nd dispersed clayseduces theme&$& and the mamitude of the SP,accordingIy. In shalelclay beds the SP is characteristicallv featureless and flat with a +ve drift down the borehole.

J - 2.6.2.3 Quantification of Shale Proportions . .

T P t e c h n l a u e s . k determine the c l a ~ ~ m l i ~ n . All the techniques have their limitations so none should be ----- used in isolation. These techniques should be considered as total shale determinators rather than clay analysers. That is they yield a total shale estimate rather than an analysis of the clay faction. They are generally adequate for assessing reservoir rock quality and vertical clay distribution trends in facies analysis.

The most commonly used techniques are as follows:

Gamma Ray (GR) (Measurements of Potassium, Thorium, Uranium can used in the same way)

Vclay = (-) (GRmx- GR,")

'"--- where: GR GR of formation GR,, GR in clay free zone I

Gr,, GR in 100% clay zone 0 1

V GR 4 Limitations:

Presence of other radioactive minerals could produce high apparent clay contents, e.g. feldspar, zircon, uranium salts, mica, glauconite. Invasion of filtrate from KC1 mud systems can increase gamma ray levels in permeable zones.

Spontaneous Potential (SP)

Formation Evaluatioo C:oursc Sotes

where: SSP deflection from shale baseline SSP, maximum SSP from clay free zone

Limitations: Reductions in SSP may be due to mineral cementation reducing permeability. If Rrnf=Rw then there will be no SSP. Not accurate in thin beds due to poor vertical resolution of SP.

Density - Neutron Crossplot (D,@ N)

where: 0 D apparent porosity from density log 0 N apparent porosity from neutron log 0Dcly apparent porosity i n d y from density log 0Ncly apparent porosity in clay from neutron log

Limitations: Not adequate in zones of varied mineralogy such as dolomitic sands or dolomitic limestones. Not applicable in zones with high gas saturations.

Neutron - Sonic Crowplot (Dt,@rn)

vciaY = PN -0 Dt

P N c l y - P Dtciy

where: 0Dt apparent porosity from sonic/acoustic log 0 N apparent porosity from neutron log 0Dtcly apparent porosity in* from sonic/acoustic log 0Ncly apparent porosity i 9 a y from neutron log

Limitations: Not adequate in zones of varied mineralogy such as dolomitic sands or dolomitic limestones. Not adequate in reservoirs with significant s e c o n w porosities. - Not applicable in zones with high gas saturations.

2.6.2.4 Selecting Clay Indicators

The main clay indicators all have limitations to their application and so will often produce different results over the same formation. With a howledge of the litholow from cores or

tion of t k w t e or relevant clay indicatorls is possible.

In automated analysis, such as C a , then a u n m m clav volume ap- is often adopted. The rninimu111~;~111puted vo-e of Vclav i n d i w n ~ & r u . t i c i n t e g r t a . In some circumstances such as a shaly sandstone with dolomite cement then the use of a minimum clay content from the neutron-

density crossplot and - gamma ray will produce ______+-- the-a-reasonable-estimate_c!f_th~robable .-_ __^ clay contat . In gas beanng formations then any technique involving the neutron or density will /

underestimate clay content and would not be appropriate for a minimum clay approach.

2.6.2.5 Calculating Porosity in Shaly Formations Porosity calculations in shaly formations have to account for the p r e s ~ n f and i$

. . effect on the ~ ~ ~ s . Varylng techniques can be employed with the main constraints being the calculating capacity of the user and the complexity of the reservoir.

Common techniques include: Single log, shale corrected. Crossplot method Shale corrected crossplot (CORBAND) Complex lithology

Sirtgle log shale corrected. The method is valid for lithologies where claylshale and a homogeneous matrix are the only two significant mineral components.

Clay content is determined independently from techniques described above. Porosity, corrected for shale, is then computed using the general relationship:

where: L, matrix response of the log L formation response of the log V,,, clay volume (decimal format)

LC,, clay response of the log

Lf fluid response of the log

Crossplot Method

The method is valid for lithologies where claylshale and a homogeneous matrix are the only two significant mineral components.

A clay corrected porosity is determined simultaneously with clay content using crossplot techniques. The clay corrected porosity can be computed using the same equation as for the 'single log' model above, using either of the logs from the crossplot.

Shale corrected crossplot (CORIBAND) The method is applicable to shaly formations where the matrix comprises two other dominant and variable mineral components, such as a dolomitic sandstone, dolomitic limestone, calcareous limestone, arkosic sandstones or formations with heavy minerals.

Clay content (usually the minimum clay volume) is determined independently through the techniques described above. The crossplot logs are corrected for the clay content and the clay corrected log values entered into the crossplot to determine an apparent density of the non- clay matrix and porosity. The technique is generally applied to the neutron-density - crossplot, using a minimum Vu value.

Clay corrected crossplot logs can be computed as follows:

- t LclY.corr - L-V,&,I, i I - -

II- 1 - Vdy - ~ 2 , ~ 7 , where: L measured log response

LCly log response to claylshale VCIy clay volume (usually minimum clay)

I . I , The non-clay matrix density is read directly from the neutron-density crossplot by - - -- -- - inte@oTation between the established mineral matrix-porosity lines. Porosity of the non-clay

'*matrix can also be read directly from the crossplot by the interpolation of iso-oorositv l i rq , ,or can be c o m v u t e $ ~ ~ e c t e d density as;

To obtain porosity as a proportion of the whole formation (that is including the clay) then the matrix porosity is adjusted as follows:

Standard C c - . .

a . . a - w dolo&.

Complex Lithology A complex lithology model treats claylshale as another mineral in a multicomponent model. The volumetic determination of the mineral components, including the clay, is through the

Formation E l alnarioe ('out-sc \otcs . A /. TLC*,., b I I ' I *

resolution of the linear tool response equations. Section on Heterogeneous Formations, below, details the form of the equations. Other clay types and silts can be resolved for in a complex lithology model.

2.6.3 Heterogeneous (Complex) Formations More commonly though lithologies are a rmxture of mineral components, be them in crystalline or granular form. One measurement aloneca~ptreJiabLy-define-the~r~k =e__n_qr the mineral compo~tipr!,~n,~s_uchm~k types.

w b i n e d used of two or more measurements however offers the potentiaLfixbi& . .

mck/mineral M i n ~ and a u a ~ t a t i v e ) ~ ~ . The radiogenic suite of logs can also be supplemented with additional logs such as the acoustic and electromagnetic tools which are also effected by mineral composition. quantitative evaluatian of formatbn can be undertaken from the logs the lithological

. . h-- c o m ~ o ~ m c ~ r - n d cuttings data and verified

with logdata.

2.6.3.1 Crossplotting for Rock Typing

The c r o s s - r e k r ~ ~ ~ ~ g r n ~ a s u x e m ~ p ~ ~ ~ ~ ~ f ~ c ~ o s ~ l ~ & Separate log measurements form the X and Y axes of the plots and the data is typically presented as discrete points or as a frequency representation (usually numerically coded) of points falling within a defined cell area on the plot.

-ts can be used -e 2 - d 1 m l n e r a l t h a W m p r i s e 3 ~ p a n e n t s , d i ~ ~ ~ l ~ a n a l ~ g a ~ 1 s _ t ~ ~ diamam. The compatibility of any data from the borehole can be assessed against a postulated mineral model by displaying in a crossplot format. Where data is consistent with the model then the relative proportions of the components can be interpolated from the comparative position of the points.

The inclusion of data from a third log variable can add an extra dimension to the crossplot and an extra component to the mineral model. Presentations are in the form of 2-plots where numerical annotations to cells within the plot represent the average value of the third variable. This enables distinction between l i t h o l o ~ s with similar X and Y respaus- differing 2 l_ogcJharactenstics.

Crossplotting is not constrained to primary log measurements but may involve secondary log derivatives (M-N - plot fd-, computed shalelclay volumes (see above) and laboratory measured properties.

TkAsplay of data on X-Y platslsalsathe best wsual technique for investi- . ~ ~ a t i m m m d d c q x n d e n t r e l a ~ ( p a s . + s ~ ~ e r m e a b & - ~ ~ v porosiW,TOC_v gamma --- ray etc.) between formation ~ ~ ~ ~ d a l s ~ ~ b m e h ~ l e - e f f e ~ ~ & a l ~ ~ e ~ ~ ~ .

2.6.3.2 Quantitative Determination

Formation Evahatioi~ Coursc Notes

. . The v o l u m P t n r - m -. Essentially to uniquely solve for 'n' unknowns you require 'n' equations. In our mineralogical analysis the h o w n s are the volumes of the mineral constituents, and the equations are formulated from the logging tool responses in the form:

where: L is the log response to the formation

Vminhl is the volumetric proportion of mineral/component h'

Lnh' is the expected log response to mineraVcomponent 'n'

an additional controlling equation is required to maintain volumetric integrity in the form of a unity equation:

In porous media then componentls of the equation should be included to represent the pore fluid element.

Z'Lk S u c c e s s f u l r e s o l u t l o n e c t i o n d thesmectcompanentsand - their expect lo--. For the majority of minerals expected log responses are known and have been published. This is particularly true for the physical measurements of density and transit time, however, the responses are more variable for the statistical measurements of radioactivity (gamma ray) and may require interpretation or interpolation from the dataset.

In situations where the number of equations directly matches the unknowns a unique solution can be obtained from this 'determined system'. Stochastic models for volumetric determination have been developed that require 'over-determined systems', that is, the number of equations exceeds the unknowns. Stochastic models attempt to account for uncertainties in the input data and often enable the rejection or clipping of solutions where component volumes lie outside expected ranges.

2.6.4 Dual and Complex Porosity Formations l x i i c l d Qudgmm@ formations in engineering t m

~ @ a n c t g ~ a ~ ! The open fractures act as high permeability conduits for fluids and can generate large production rates. lly accugy only a s m w o r t i o n of the rock, typically less than 1% and consequently may not contribute much to the overall hydrocarbon volumes. gatrix porosity however can be well in excess _o.f

. . J y u u -

for hv*. Where both occur together then l a r g m c a p a c i t y and high p r o d u c t l o n h d a e d . It is therefore important to be able to identify where

Formation Evaiaatio~r <'otrrse %ores

fractures occur and to d g e m e contribution to starage ca~asaty such t h a t w e determined.

Additional pore w s mg-sitv. m x i s t , ~articularly in carbonaB ~leservoirs, that mav o ~ ~ n ~ n s t , o ~ g e s _ a p a ~ ; i t y a n ~ & c k o _ n . These void spaces may or may not be in communication with other pore networks in the rock. One - specific example is in oolitic carbonates where it is possible to have an intergranular pore network between the ooliths that is in good communication, and isolated void spaces within the ooliths caused by dissolution, that are entirely or partially isolated.

In the context of log derived porosities the term secondary fn mggy andfracture m. This type of porosity is not widely distributed through the matrix of the rock. From the sections above it can be seen that the majority of logs respond to total

d+ P E F --I-

porosity. Only the acoustic/sonic and resistivity logs will potentially respond to a portion of - l - 1 ~ ~

this pore system. ,+Ll\h -'t - Ffy'<<:sc

( . .

The varied origins and f o r m s ~ f k a ~ ~ n a ~ e s . p l u s their potentially cample - x D o s t - d _ e P n n l t l a n a l h-ives rise W f vorosity types and classificatians. A genetic classification of porosity types identifies six basic pore types:

I Intergranular

I void space between grgins, as found in lime and dolomite grainstones i 1 and oolites

I Intercrystalline / void space between crystals, as found in sucrosic dolomites / Moldic 1 void space created by the solution of matrix textural features, such as 1 1 oolite rims, found in moldic oolitic limestone and dolomite grainstones. I i Matrix or Chalky I primary matrix porosity as found in fine grained carbonates, such as I I mudstones and chalks

Moldic or Vuggy void spzce created by solution ofskeletal f r a w I that is additional to I the matrix porosity, such as in vuggy packstones and wackestones

Fracture 1 void space created in stress associated fractures or solution fissures, can I I I be found in all rock twes

In a classification by Choquette and Pray (1970) pore types are classified in terms of their relationship to the original formation fabric.

'Fabric selective' pore types are those associated with original depositional elements, and include:

/ Internarticle I void mace between articles or mains 1 Intraparticle 1 void space within particles or grains, such as ooliths. Intercrystalline I void space between crystals

Formation Eval i~at io~i Course Notes

I Moldic 1 void space created by solution of skeletal fragments. I Fenestral I void space created by solution along planes or lineaments- I 1 Shelter 1 void space remaining under larger fragments such as shells I

'Non-Fabric selective1 porosity is that associated with post-depositional solution along lines of weakness that are often stress related:

Growth Framework

void space in the skeletal framework of corals, originally occupied by the organisms

/ Channel ) void space created by solution along lines of weakness such as fractures I I Fracture

/ or joints. Often associated with sub-aerial erosion.

Vugg~ i isolated voids created by solution. I Caverns I large scale voids associated with the percolation of surface water down

stress related fractures caused by tectonic deformation of the compactedllithified rock.

1 / to the water table and the subsequent dissipation of the ground waters to I I I springs or acquifers I I

Some additional pore types are recognised that do not fall easily into either the fabric selective or non-fabric selective category. These include:

/ Breccia / porosity between brecciated rock fragments, such as may be associated I 1 I with fault olanes. I Boring I void space associated with boring organisms. Burrow 1 void space associated with the activities of burrowing organisms. Shrinkage I void space created by contraction of the sediment and commonly

1 / associated with dessication cracks I

.k Whilst a wide range of pore origins and types have been recognised through the study of c a m s in thm section and at the outcr~p, the recognition .----------- of these --- as -.---. distincBsm._eein th- if not impossiblek.- ow ever in combination with the c- an overall indication of dominant pore types and their distribution can be achieved from the wireline data.

. . Quantitatively it is not possible to define -w The density and neutron logs, however, are sensitive to talf-gg.&grp~&ty. Positive increases in the level of total porosity over matrix porosity, as estimated from the sonic/acoustic logs, can indicate the presence and amount of secondary porosity.

The calculation of total porosity can be by s i n w g , c r m t or -sis t e w e s . The heterogeneity of the reservoir will tend to dictate the type of model required.

It should be noted however that any c r o s s p l ~ sonic/acoustic logs as theparody indicated is not CQ-orositv logs.

Distinction between vuggy and fracture porosity is less obvious but may become evident with more detailed study of the log data.

2.6.4.1 Matrix Porosity

In_te~n_s.eflcrgs~.iti4rdq matrix porosity is the ~orosity t k w h t r i b u t e d , with some uniformity, throughout the baSlSZfaSthercack. In terms of the pore c l a s s i f i cam d m b o v c i t \araulbusurilly be intergranular. -porosity. However it would also include well distributed moldic or intraparticle porosity as might be found in oolites.

The acoustic -e is the only l o w d parameter that is controlled ~rimarilv by maax continuity. The presence of more random and sparsely distributed vugs or fractures have no significant effect on the transit time, however, variations in well distributed matrix porosity will length the transit path and increase the sonic transit times. Earas-

tLLl.Q- s- arily matrix vorosit&.

The Wyllie time average porosity-transit time transform assumes - a line- between porosity, and matrix and pore fluid transit times, in the form:

OM, = Dt - Dt, - Dt, - Dt,

where: Dt sonic log response Dt, sonic matrix response Dtf sonic fluid response

Work by R a p e r , Hunt and Gardner (1980), based on field observations, suggests that the . .

relationship between porosity and transit time is not line= and t @ m x u L c a e u - l a . The Raper-Hunt relationship can be defined by the following:

- @ ~ v l , - -a - [ a2 + ~t,- - 1 1"'

Dt

where: a - - Dt, - 1

2*Dtf

The sonic Jggahn_e.camm r e s o l x e m a ~ - p a r 0 s ~ ~ ~ ~ g ~ n e o u s f o r m a m . Models . .

- p h PEF and G v . &uhem&ive and often more p r a c _ t u l ~ ~ a c h is effect a rr&g?ac-anal~ si s s f l k M x h g y ~ ~ ~ n $ J l r : . u ~ -tin9 additional curves (PEF* GR. WT3-E_P*) as required. A composite sonic matrix response can then be established from:

Formation Evaluatioa Course Yotes

and the single sonic - porosity equation resolved incorporating a variable matrix response.

2.6.4.2 Vuggy Porosity Vuggy porosity may be suspected where:

Sonic/acoustic porosities Resistivities

I I

I I ! I sparsely distributed wgs are open and connected to the matrix I

are persistently lower than densitylneutron porosities. are anomalously high for the levels of total porosity. This may be indicated by high Rwa values, or low Sw's being computed. This

, Log derived cementation factors

pore system. I

is only evident where the wgs are isolated from the general pore system. are persistently lower than core measured values. Evident where ,

I Vugs can occur at a wide range of scales. At a micro level they may be well distributed through the matrix and even start to effect the sonic to some degree. Alternatively they may be large and sparse with diameters of several centimetres and not always within the sphere of resolution of the density log.

2.6.4.3 Fracture Porosity There are no reliable fracture indicator logs. Confidence in recggnising f r a c - ~ ~ y & b o u t cores is ~ b f r ~ r n t h e ~ e x a n n a t b n ~ o f a&3exanse2~f.data. Whilst open fractures can

. . . . do . + to pore volume may

of-.

[ Mudlogs / Increases in mud losses - lost circulation. I

I Ray I High gamma spikes associated withbuild-up of uranium salts on fracture ulanes. More easily identified on NGT uranium curve.

Cali~ers v.

I - Density J I Low density readings across large open fractures.

Rapid increases in drill rate in heavily fractures zones. Breakouts in borehole along direction of stress.

Density Correction

I w I Barite has exceptionally high PEF response, 279 b/e compared to 2 - 7 for I

High spiky borehole corrections across zones where caliper indicates smooth borehole.

Sonic J P.E.F. ,I

Cycle skipping in zones with open fractures. High PEF spikes across open fractures where holes drilled with barite muds.

I - - . Micro-resistivity I Anomalously low Rxo values, spiky across single large open fractures, or I Deep Resistivity d

I I persistently across well fractured zones.

most matrix types. Anomalies between deep induction and d e e ~ laterolog readings (ILD<LLD)

Formation Evalnation Coursc l'otes

[ E.P.T. f Increased attenuation spikes across open fractures. Dipmeter I Significant resistivity anomalies between curves caused by fractures only

1 Resistivity Curves I being intersected by one or two arms. ] Microscanner j Significant resistivity contrast across open fractures and to some extent

1 sealed fractures. I 1 Borehole Televiewer ) Acoustic images of the borehole wall pick up marked acoustic difference

i I between open fractures and matrix.

N.B. No one log can be depended on to pick up all fractures in all situations. To be confident of fractures without core support then many logs should be consulted to get a consensus.

Formation Evaluation Co~trsc Notes

2.7 Hydrocarbon Effects on Logs The presence of hydrocarbon in the pore space effects virtually all the logs. The effects are most noticeable in the presence of gas whose properties differ most from w a t e r . - ~ ~ ~ i c a l properties may range:

/ Density 1 1.2-1.0 1 1.0-0.7 1 0.2-0.0 1 dcc I I Neutron / l o o . 1100-60 130-0 ~ P U I I PEF j 0.358 1 0.12 1 ? I b/e I

1 EPT (prop. time) 1 25-30 1 4.7-5.2 1 3.3 / ns/m I

U 1 0.4 Sonic j 189

I Resistivity [ 0.005+

The overall hydrocarbon effect is dependent also on the amount of hydrocarbon in the formation. Hydrocarbon contents are normally expressed in terms of saturation, as a proportion of the pore space. Whilst this is important it is the volume of hydrocarbon in proportion to the total formation that is more significant.

2.7.1 Correcting Logs for Hydrocarbon

Hydrocarbon corrections are required to the porosity logs (density and neutron specifically) if accurate estimates of formation porosity are to be made. Affects on the sonic and PEF properties are not significant, and in the case of the sonic cannot be corrected for.

0.11 ? Infinite

The contribution of the hydrocarbon to the porosity logs response can be expressed generally as :

0* S h * Lh

where:

? ? . Infinite

0 porosity Sh hydrocarbon saturation Lh Log response to hydrocarbon

ms/ft ohmm

To correct a log for the effects of hydrocarbon then a computation that replaces the hydrocarbon with formation water is required, this will take the general form:

where: L,,, Log response to formation water such that:

T

I Lcwr.hyd = L+(O*sh*&v-Lh))

I I where: L Formation log response

Formation Evaltlarion Course Notes

where: 0 N Neutron porosity from log 0Nmf Neutron response to mud filtrate 0Nh Neutron response to hydrocarbon

It has been found however that a correction v r the difference in hydrogen @dex of the pas is inadequate in reconstitutinp thu-hvdrocarbon influenced neutron. The affects of the matrix on the neutron response are ignored and need to be accounted for by a correction known as the -ection. Failure to correct for this e r - e s t i m a t i o n of vorosity. The corrections for excavation effect can be estimated using the following formula:

0 ~ c r m r r =

where:

fiom

SWH

and

lithology dependent constant, 1.0 in sandstone 1.046 in limestone

1.173 in dolomite

hydrogen index of the formation fluid calculated

hydrogen index of pore water hydrogen index of hydrocarbon

Formation Evaluation

Course Notes

Section . 3

............................................................................ 1 CONCEPTS OF RESISTIVITY INTERPRETATION 1

.................................................................................................... 1.1 FORMATION RESISTIVITY FACTOR (FRF) 3 .............................................................................................................................. 1.2 RESIST~VITY INDEX (RI) 4

2 SATURATIONS IN CLEAN FORMATIONS . ARCHIE EQ ................................................................. 5

2.1 FORMATION WATER RESISTIVITY (Rw) DETERMINATION ........................................................................... 6 2.1.1 Pickett Plot ........................................................................................................................................ 6

.............................................................................................................................. 2.1.2 Rwa Calculations 7 2.1.3 -' Rwfi-om the Spontaneous Potential .................................................................................................. 8 2.1.4 ' Rw from Fluid Samples .................................................................................................................... 8

................................................................................................. .................... 2.1.5 /AssessingRwresults .. 9 ...................................................................................................................... 2.2 CEMENTATION FACTOR 'M' 11

...................................................................................................................................... 2.21 dPicke t tPlo t I1 ................................................................................................. 2.2.2 Electromagnetic Propagation Tool I2

...................................................................................... 2.2.3 SCAL da fa - Formation Resistivity Factor 12 2.2.4 d ~ s s e s s i n ~ Cementation Factor 'm ' values ....................................................................................... 13

.............................................................................................................................. 2.3 ARCHIE CONSTANT 'A' 14 ..................................................................................................................................... 2.3.1 d Pickett Plot 1 4

...................................................................................... 2.3.2 J SCAL data - Formation Resistivity Factor 14 ...................................................................................................................... 2.3.3 J Assessing 'a' values -14

2.4 SATURATION EXPONENT 'N' ..................................................................................................................... 15 .......................................................................................................... 2.4.1 u/ SCAL data - Resistivity Index I5

2.4.2 J Assessing Saturation Exponent values ........................................................................................... 1 6 2.5 FORMATION TEMPERATURE ...................................................................................................................... 17

2.5.1 Horner Plots .................................................................................................................................... 17 2.5.2 Assessing Formarion Temperatures ............................................................................................... 18 2.5.3 Surface Temperatures ...................................................................................................................... 18

2.6 CALCULATING WATER SATURATION - N 4 N U A L METHODS ...................................................................... 19

3 SATURATIONS IN SHALY FORMATIONS ......................................................................................... 21

3.1 WATER SATURATION MODELS .................................................................................................................. 22 3.1.1 Total Shale Models .......................................................................................................................... 22 3.1.2 Laminated Shales ............................................................................................................................ 23 3.1.3 Dispersed Clays ............................................................................................................................... 23 3.1.4 Dual Water Models ......................................................................................................................... -23

Formation Evali~atio~i C:oarse Notes

1 Concepts of Resistivity Interpretation Resistivity logs are one of the most essential tools for the log analyst. The lithology and porosity logs permit quantification of the pore space and lithologxal components. The resistivity logs allow the evaluation of the pore fluids.

Resistivity is a measure of the ability of a substance to resist the flow of an electric current. The reciprocal of resistivity is conductivity, and is the measure of the ability of a substance to conduct an electric current. Resistivity and conductivity are related in the form:

Resistivity = - 1000 Conductivity

or alternatively Conductivity = - 1000

Resistivity

The units of resistivity are ohm-meterlmeter, usually abbreviated to ohm-meters, ohmndm or just ohms. The units of conductivity are millimhos/meter often abbreviated to millimhos or Mos.

In rock formations,the majority of matrix minerals, such as quartz, calcite and dolomite, are non-conductive. Any current that flows through the formation is conducted through the water in the pore spaces. I t i m p L ~ c r l m m a r i s e d that the £am&

. . M u - d

~ d ~ n f ~ ~ ~ ~ d the v o l d d i s t t r i b u t ~ A - O f t h a t ~ .

The conductivitv of water is controlled by the amount of dissolved s- Conductivity increases with both salinity and temperature such that a hot salty water is more conductive than a cold fresh water.

Charts relating salinity, temperature and resistivity are available to enable the determination of any one property fiom the other two. The change in conductivity or resistivity with temperature can also be com~uted using the formula (Aarps formula):-

where R, Resistivity @ temperature 1 R2 Resistivity @ temperature 2 T1 Temperature 1 T2 Temperature 2

The volume of the pore water is equatable with the porosity of the formation. In clean water bearing formations the two are directly equivalent. WJere hydrocarbons are present in the pore s~~&~~f.~~waterM!_1._b~bs,thaILthe~zorosltvo~.W~mak~

- SECTlOh3.DOC: - A.E.Stocks - 07 1 1102 1

The distribution of the Dore water relates to the degree of continuity of the water through the rock fabric. It is equatable with the geomehy of the pore sytem. If the conductive pore waters zre restricted to isolated (perhaps vuggy) voids or pores, then the formation as a whole will have no conductivity.

To understand and be able to interpret resistivity data than we need to establish and und-nd the relationships_,b,etwee.nfl,~1id.~on~~.~~v~D,-g.o~:~~~.e~~~~-ge,0_m~ saturation. The relationships are fundamental to log interpretation and primarily stem from -.- -I.--.-

work done by Archie.

The interpretation of resistivity is based on the Archie equation that relates resistivity to porosity and saturation. The _ Archie._eguatioy -- is the . basis - for-all .saturati_on~gwti~dl~~ls~~ j n

J ~ g a a l y s i s . In its basic form it is only valid in "clean" formations, that is those without claw or other conduc; t iu%~als . e

The Archie equation is based on two components:-

The Formation Factor (or Formation Resistivity Factor) The Resistivity Index

Formation Evaluatioo Coorsc Uotes

1.1 Formation Resistivity Factor (FRF) . .

The Formation Resistivity Factor (FRF) r e f l e c t s v i t y and pore

FRF =Ro/Rw .. 1) where Ro Resistivity of formation 100% saturated with water

Rw Resistivity of the saturating water

FRF ranges from 1 to infinity anbis influenced solely by the physical characteristics of porosity and pore geometry such that:-

!

FRF =a/(@") , . -2) where 'a' constant related t o n a n d is the valu; of F at '100% porosity.

'0' total porosity of the formation - fractional 'm' cementation factor, a unitless parameter that defines the change in

r m k t i x i ~ t k p a ~ o ~ ~

This is a log-log relationship that can be defined by plotting FRF against 0 on log-log graph paper. It defines a straight line in log-log domain of which the gradient is the cementation factor 'm' and the constant 'a' is the value of FRF where the line intercepts 100% porosity (0 = 1.0).

The Archie 'a' constant has typically recommended values of= (with a or Q$L in sandstones and 1 .OO in carbonates.

The Cementation Factor 'm' u- 1 5 to 3 5 . . t-m-wm

ge~=Q. In particular it is .?gnsitive to the q u a . of n e . .

s w . High- 'm's reflect poor c o m m ~ m l c a t m n & ~ d - communication (low tortuosity). Values of 2.15 in sandstones (with a=0.62) and 2.0 in carbonates (with a=1.00) are frequently recommended and used. In carbonates 'm's may vary dramatically. The ideal pore geometry is that of a straight open fracture in which m will equal 1 .oo.

Combining equations 1) and 2) above we get:-

The Formation Resistivity Factor can be measured by special core analysis techniques 1- n v m w

. . . A sample is dried to remove all fluids, then resaturated with a solution of known resistivity (Rw) and the resistivity of the sample measured (Ro). The saturating solution is mixed in the laboratory and should be similar to the true formation water (see Appendix 11).

2 : P

Formation E\aluatiol~ ('ourso l'otcs

1.2 Resistivity Index (RI) Hydrocarbons (oil and gas) are nonconductive. If part of the conductive pore water is replaced with hydrocarbon then the formation resistivity will increase, even though the total porosity and pore geometry remain the same.

The Resistivity Index (R.I.) relates the effect on resistivitv of hydrocarbon or anv non- conductive fluid in the pore space. -

where R.I. = Rt/Ro ..4) Rt True resistivity of the formation. Ro Resistivity of the formation 100% saturated with water.

R.I. varies only with the composition of the fluid in the pore space, as the porosity and pore geometry will be the same for the two measurements. It ranges from 1 to infinity. R.I. is related to water saturation in a l o g - 1 ~ relationship that can be defined by plot tin^ R.I. v S a t u r a t m ~ J o g - s c a k & p & p-r. This takes the form:-

Swn = 11R.I. ..5) where:

Sw Water saturation (decimal format), that is the proportion of the pore space occupied by water.

n Saturation Exponent, and is the gradient of the line defined on the plot.

The Saturation exponent 'n' is controlled by the r e l a t i v e w e w a t e r and &droc&mn in thepOrespace There is evidence that 'n' is affected by the texture of the

around the pore space. Rough surfaces have a stronger capillary hold and retain a much thicker layer of water around the grains. 11- to a resistivity increases with hydrocarbon saturation. In water-wet r w o i r s n ' 3

b-1.7_&.2hmint-m-. . c ,

By combining equations 4) and 5) we get:-

TkResistivitv Index can be measured by s~cc~.e-~~1~~i~en~ *-

merhwden-ptessur~m~dstians. A sample is dried to remove all fluids and slowly resaturated with a conductive fluid, usually brine or mercury. Resistivity measurements are made of the sample at various stages of resaturation. The R.I.'s are reported at different saturation levels (see Appendix 11).

Formation Er.aloatiua Chtrsc Notes

2 Saturations in Clean Formations - Archie Eq. In equation 6) Ro cannot be measured in the borehole. It has been related to porosity and pore geometry through the Formation Resistivity Factor FRF, (equation 3). By combining these two equations we get the Archie equation for water saturation.

Sw' = a * R w -3 0" * Rt

where Sw Water Saturation (fractional) n saturation exponent a Archie exponent m cementation factor 0 porosity (fractional) Rw formation water resistivity at formation temperature Rt true resistivity of the formation

The equation is used for calculating water saturations in "clean" formations, that is where no clay or other such conductive minerals are present.

Numerical solution of the Archie equation requires input of the variables 0 (porosity) and Rt and the constants a, m, Rw and n

The variables come from the log data, that is, porosity, as calculated from the porosity logs and Rt, thgmetsuredd~e~~esisti4lity.a. 9 s .

The constants are properties of the formation that need to be established. This may be from the log data alone or from laboratory analysis of core samples and tested fluids. Ideally both log and laboratory methods should yield similar results. There are both analytical and

t h e c m & a n & , T h e a n a wlmethads- lvtical metho-- m e a s ~ ~ c o r e s - i u o - . The numerical methods involve the investigation of relationships and trends between the log derived porosities and resistivities. Graphical presentations are the most diagnostic way of recognising and defining these relationships and establishing the constants.

2.1 Formation Water Resistivity (Rw) Determination

The ideal source of measuremen..good.-rep-tative s a m ~ ~ l ~ s _ ~ 4 & g ~ stem or production m. There is commonly good regional consistency in formation water properties within a single field or unit, however genuine variations do occur. In most cases it is necessary to determine Rw information from the log data alone. A variety of techniques and methods are available all of which involve some electncal measurment of sorts.

2.1.1 PickettPlot The Pickett plot is named after its originator Dick Pickett. It-is..a-gaph-i~aLssbut- b s i c Archie princ;lDles. Given the appropriate reservoir properties it can be used to establish values for a, m, and Sw in addition to Rw, assumptions are only required for 'n'. The Pickett plot Is,aLo.ghg scaled crossplot of Rt ve-.

Procedures for use of the Pickett Plot to determine Rw:

Establish porosity and Rt values over a known water zone. Average values can be used however a detailed breakdown will be required to establish a porosity-Rt relationship. The technique is only valid in clean, that is shalelclay free formations. Plot points from clean water zone on log-log graph paper. A wide range of porosity variation is required.

NB Vertical Axis - Porosity from 0.0 1 - 1 .OO (fractional) Horizontal Axis - Rt from 0.0 1 - 1000 (ohmms) (Rt scales may need adjustment to suit local conditions)

EstablisWdraw the 100% water line passing through the points, and extrapolated t~

intercept the 100% porosiw line. If it is t h o u g h t g t h e zone may contain some genuine residual hydrocarbon saturations then the line should be drawn on the lower margin of the points, that is the side of lower resistivity and porosity. The value of Rt at the intercept of the water line with 100% porosity is the product value 'a*Rw'.

Where there is a reasonable porosity range (5%+) then a definable trend and line should be evident. If not then the logs should be examined carefully to identify any additional zones of low or high porosity to include in the plot. Be carefill to u-ints so that

. . . 1s Iq&, Two or three points in isolation may well define a line but may

also be non-representative and lead to an erroneous interpretation.

If the points only form a cluster with no definable water trend then a water line can be projected through them on the basis of a known or assumed 'm' (cementation factor) value (see section below). The gradient of any water line is the value 'm', and the Pickett plots' other principle application is determining 'm'. If 'm' is not known then an assumed value of 2.0 can be used to establish an initial water line. On a log-log scaled plot then a line with a gradient ('m') of 2.0 will cross two log cycles on the resistivity axis for every one cycle on

Formation Evaluatioti C:oursc Notes

the porosity axis. For example a line through the following two points will define a line with gradient 2.0:

I I

/ Resistivity I Porosity I

Point - 2 1 100 1-00

See section 2.3 for establishing 'm' lines of other gradients.

Points to note: . .

The method is onlv v a l m T h a t is formations or zones with little or no clay or other conductive minerals. The method is only valid in water bearing zones. If residual or mobile hydrocarbons are present then the line will spread to higher resistivities and be hard to define. If a water line is well defined it is probably a good indication that a zone is water bearing, particularly if the zone is reasonably extensive (50ft/l5m or more). The intercept value of resistivity with 100% porosity is the value a*Rw and not Rw alone. Differences- this and other Rw values may be a result of an 'a' not equal to 1.0 (see section 2.2).

0 In some formations, particularly carbonates, the line may show some curvature as pore geometry changes with porosity (see section 2.3). a . 3 , C

T . - P d = $5 c f - 2.1.2 Rwa Calculations r ~ - 1

Apparent values of Rw (Rwa) can be made from the log data by two techniques:

Archie A computation based on the Archie equation and therfore comparable to the Pickett plot technique and where:

Rwa =[Om) * Rt a

It is only valid in water zones and requires a value for 'm' and'a'.

Ratio A computation based on the formation factor - resistivity relationship and involving resistivity measurements only where: , r q? ~ t t 3 by ri -.-l s-.?'

c Rwa = Rmf * Rt

Rxo ' where Rmf mud filtrate resistivity

Rxo flushed zone resistivity

It is valid in water zones only, requires no knowledge of "a" or "m", nor porosity. It also assumes that the reported Rmf measurements represent the fluid in the pore space within the "flushed zone" read by the Rxo tools.

Kclean" water bearing: zones b o t h l c l . - SECI 10\3.1)0C - A.C Stocks - 07 11 02 7

2.1.3 Rw from the ontaneous Potential P' The magnitude of the SSP deflection reflects the contrast in s a b t y between the mud fdtrate and the f o r m a m a t e r (see Appendix I, sheet 2). If the resistivity of the borehole fluid is known then the resistivity of the formation water can be estimated through the formula:

SSP = -(61 + 0.133*T)*log(Rmf/Rw) where: SSP Static SP, the relative change of SP from the non-permeable baseline.

T Formation temperature in OF Rrnf Resistivity of mud filtrate at temperature T°F Rw Resistivity of formation water at temperature T°F

this can be broken down into two calculations to derive Rw:

and Rw = Rmf 1 O(SSP/K~)

Charts are p r o w b y the 1 0 g g ~ k c a l ~ a t i o n of RwIfrom, the SP.

Points to Note: The SSP is only developed a c r o s s p where the two fluids can

come into contact. Tight formations may show some limited SSP that would not be representative of the true formation water resistivity. The method is only valid in clean+formgtions with little or no clay minerals. The clays will reduce permeability and reduce SSP magnitude in the same manner as point 1) above.

The SSP may be reduced in zones with high h y b r b m s a t u r : m s . The amount of formation water in the formation is reduced and there is a reduced interface area between the two waters to generate the electncal potential. The vertical resolution of the SP is p w . If the permeable bed thickness jsJext_h_ann2,0 feet it is unlikely that a maximumm SSP has been attained. Caution should be used in thin bedded formations. Ch_arts are p r ~ v i d e d _ ~ ~ g g i n g ~ c n n t r a c t a x s _ f f o ~ ~ SSP in thin be&. -

2.1.4 Rw from Fluid Samples . . . .

Formation watermtlultr.arrkPmPnrllrPnb frfjnrn water w p l e s produced from drill stem or wirehnzksh. The drill stem/production tests are likelv to r a c e a t wresentative samples of formation water. A number of samples may be taken to monitor the cleaning-up of the samples. Contamination by filtrate or perforation fluids can lead to misleading Rw values. A full chemical analysis of the water can identify contaminated water samples as well as reveal something of the nature of the original depositional waters or post- depositional history of the formation and aquifer.

Formation Evaluatiou (hursc Sotcs

Measured water resistivities are r e ~ d at laboratory t-tures and usuallgat a U d V F . It is important to understand that a resistivity measurement without an associated temperature is meaningless. All resistivity measurments must be accompanied by a temperature.

2.1.5 Assessing Rw results Rw is a verv important parameter in evaluating the hydrocarbon saturation levels values can create or lose an oilfield. It is important therefore to be as confident as possible in the Rw used. As many techniques should be used as possible to support and confirm the final

1

value. The sort of questions that should addressed include: m

Is the produced water sample contaminated with borehole fluids? Is the size of water sample enough to be representative of the formation water? Were there any indications of hydrocarbon during drilling or testing in the zone? Is the zone permeable? Is the zone free from significant clay minerals? Is the Rw consistent with that in nearby wells? Is the Rw consistent with regional expectations and the original depositional environment of the sediments? Is the Rw consistent or compatible with the overlying and underlying formations? Is the Rw compatible with the cementation factor 'm' and saturation exponent 'n'? Will the Rw produce 100% water saturations in known water zones? Is the Rw changing within the reservoir or between reservoir beds?

In geological terms it is often useful to consider the formation water in terms of its salinity & than resistudy. This is a unique parameter that is indep~ndent of m a t u r e and

. . . . related.toJmtL&e o-r~nrn- -1 histery,

If the sediments-g~e~azsin e.in...ad.gi n, with no subsequent major hydro-dynamic activity, then salinitie~-in..the-~n~-2~Q~~J5,0,.0&p~Cl equivalent should be expected, with geochemical analysis confirming um) and C1 (Chloride) as the dominant salts. If the ~d imen t s result b or tn e x a w & s then salt saturated waters ~ O O o + ~ z p ~ m NaCl- ecxr*e~q would be expected.

L ~ ~ s ~ ~ e s m - y - b e - . p ~ ~ ~ ~ c u s trine d e p ~ s ~ ~ s e r v o i r s w ~ ~ & ~ c ~ m m U g _ i C 1 _ a ~ ~ ~ ~ t h ~ ~ ~ f a ~ e ~ g r , 0 ~ n L ~ a t ~ . In the latter situation dramatic changes in water salinity may be encountered within and between reservoir beds and caution is required when considering a single Rw value.

. . Regional variations in salinity c d e c t ~enuine facies vwt ions of the s-. Deltaic - . . . . . *es will m a s e aw d o ~ t s b - t k ~ x d s t a l m a n n u h i n a t e d areas, Salinity maps can indicate the regional extent and shape of the original delta.

Formation Fvaluatioe Coarw Sote4

The message is that the Rw must make geological sense as well as matching the numerical log data.

Formation Eraluatioa Col~rsc \ores

2.2 Cementation Factor 'm' Cement- he mlnhnratrvv nf F o r m u Resistivity Pac-hr (see Appendix 11). These ~pecial core analysis measurments however are not made as often as log analysts would like and commonly are only made when commercial hydrocarbon has been established. Given the existence of a clay free water bearing zone then cementation factors can be estimated from the log data. L4g derived 'm's should be in close

. . agnxmmta-measuents however suatmm may o c c u r h e to b e different scales and resolutions of the two data. Comparisons between the two sources are always valuable in confirming each other or highlighting potential problems in either technique. In the absence n f n the u- re~ional knowledge or _ ~ e a -.

2.2.1 Pickett Plot = e m scaled crossplot of Resistivitv versus porosity. It has applications in determining the value a*Rw as well as 'my and water saturation. It is a graphical renr%sentaturnof_the.

In a clean ( c l a c n - i c t s should define ea_-skai&tJne,. p r ~ ~ ~ @ - ~ d ~ q ~ t ~ p ~ s i Q - ~ ~ g g - ~ x i g s . This b is known w & e . It's intercept with the 100% porosity line is the value a*Rw (see D.2.1 above). The gradient of the line is the cementation factor 'm' and quantifies the degree to which resistivity changes with porosity.

Once a water line has been established (see section 2.1) the gradient or 'm' value can be computed from the following equation:

m - - loe(a*Rw/Rtd)

Log (0) where: a*Rw the value of Rt at the intercept of the water line and 100% porosity

RtQ the value of Rt at the intercept of the water line and porosity0

0 porosity (fractional)

Where there is a reasonable porosity range (5%+) then a definable trend and line should be ' evident. If not then the logs should be examined carefully to identify any additional zones of low or high porosity to include in the plot. Be careful to use sufficient points so that confidence in the line is high. Two or three points in isolation may well define a line but may also be non-representative and lead to an erroneous interpretation.

If ints d e f i v v l t h n o d then a water line can be proiected t h o u - n f ( f i n water resistivity) value (see section 2.1).

4 Formation Evaluation C h r w \otcs

If cementation factors have been de---ye(see above) then 'm' lines-id to assess c s t e n c y with the lop d a . The apparent resistivity of a formation can be computed from a given porosity and cementation factor by the formula:

The following table provides an easy guide to defining lines of specific cementation factor on a Pickett plot. The table indicates the multiple to be applied to the established or assumed product value 'a*Rw' to determine the true formation resistivity (Rt) at a porosity of 0.10 (10%). A line drawn through this point to the value Rt = 'a*Rwl at porosity of 1.00 (100%) will have a gradient equivalent to the selected cementation factor 'm'. Intermediate 'm' values should be interpolated visually or through the above equation.

1); 2.2.2 Electromagnetic Propagation Tool

'm' 1.4

The EPT logsan-he .used.to-compute f l ~ s h _ e . d ~ z ~ f ~ ~ ~ a b d r a . ~ n s , Sxo (see Appendix I). These can be integrated into an Archie equation using the Rxo data to compute a value for "m" as follows:

From the EPT log: S X O ~ = D P T 0

Porosity 0.10

From the Archie eq.: Sxo" = a*Rmf 0"*RXo

Rt @ Porosity 0.10 , 25 *a*Rw I

I

Combining the two: m = Lo~l(a*Rmf)/(Sxo~"*RX0)1

Log101

J'he technique is only ap.pIir;&k.-free*~ it canproduce continuous 'm' values throughout the interval. The prime application was considered to be in carbonates w~ is notoriouslv v-unnredictable, The technique however depends on having good Rxo (micro-resistivity) data. In carbonates, and particularly fractured zones the the Rxo can become very unreliable.

2.2.3 SCAL data - Formation Resistivity Factor

Formation Evaluation Coursc Notes

Values for the cementation factor "m" can be measured in special core analysis. 'I& . . .

laboratory measures Formation Resistivity Factor (see Appendix II). for a number of samples . The FRF values for all samples are plotted against

porosity on log-log scaled graph paper, and should define a straight line with the following properties : dL

The value of FRF at the intercept of the line with 100% porosity is the value "a". The gradient of line is the cementation factor "m", where

m - - lop (a/FRF)

log (0)

Whilst "m" values can be computed for all samples (assuming a value for "a") it is normal to identify a single value for a layer or formation type.

FRF measurements at net confining pressures equivalent to in-situ pressure conditions should . .

be used, if available, to determine 'm'. Ceme-t m-sltu conditions are expected . .

- 0 0

2.2.4 Assessing Cementation Factor 'm' values

Computed or measured 'm' values are expected to lie within the range 1.5 - 2.5, It is common practise to adopt standard parameters in new areas or formations until the data proves otherwise. Values of- (with a=1.00), and w c sandstones (with a=0.62) are commonly encountered and based on previous published research. However in many clastic resgzmus. m v w . 6 ' below 2.00 (1.80 - 2.005 are indicated fi-om laboratory measurements. The presence of clay in the samples is likely to reduce a ~ ~ a r e n t m L ' values.

. . The cementation f a c t o r i s a n ~ n r t u o s i t v of the pore system or the pore -. This is a consequence of the original depositional pore fabric and any subsequent diagnetic alteration or modification. In sandstone reservoirs the o-nular fabric tends ,to dominate the pore-seometry and-the,u~ of standard v a b u or 2.0) is generally xezswalk However post depositional cementation and pore filling can radically alter the pore geometry. Analysis for cemen-_should -undertaken to confirm Qr otherwise the .-&-.

-&onate formations t h g . p c m q e ~ . n x ~ - .r- ted-by-pwtcde.m- These can change rapidly in magnitude and type and cause large variations in pore geometry. The dolomitisation of limestones is a particular example where porosity is created. The pore voids may be relatively large however the pore throats can be small causing high tortuosity and therefore high 'm' values.

The computed range of 'm's should be small +/-0.2 in clastics and generally around the L9 - w. In carbonates the range may be fi-om a however with some possible other associated lithological control such as dolomitisation.

2.3 Archie constant 'a' . . .

The Archie 'a' c a n s t a n ~ q m x e n a atian. It is hard to define the key formation property that controls it but it is probably textural. It cannot be determined or measured directly, but inferred from other data and trends. It is commonly assumed to be 1.0 in carbonates and sometimes 0.62 in sandstones unless evidence to the contrary exists.

2.3.1 Pickett Plot The Pickett plot (see sections D.2.1 and D.2.2 above) can be used to infer a value for 'a'. The intercept of the water line with the 100% porosity line is the product a*Rw. In all saturation equations 'a' always is multiplied by Rw and so the need to distinguish between them is not of prime importance. Where Rw is known from other sources (see section D.2.1) then 'a' can be computed. I

FQL / 2.3.2 SCAL data - Formation Resistivity Factor L..

!% _Measured F , R E - J l a l u e ~ ~ ~ e s ~ a n be u l o ~ s t s t ~ - ~ - o n 10- crossplot_Spto v i ~ u a 1 1 y , ~ s t a b l . i s h - w h c t h e r . , _ t h e ~ p o ~ , e _ ~ g ~ ~ ~ ~ ~ ~ ~ ~ n ~ b ~ ~ ~ ~ ~ h , ~ s ~ m ~ , g . Individual 'm' values can be computed for each sample assuming FIZF = 1.0 when 0 = 100% (a = 1.0). A best fit line through all the samples will produce a composite gradient or 'm' however the line may not pass through the origin value FRF = 1 .O, 0 = 100. The intercept of the line with the 100% porosity line is the constant 'a' and can be computed by:

2.3.3 Assessing 'a' values In carbonates 'a's equal to&Lqre expected. In sandstones values less than 1.0 are expected. This implies an additional conductivity associated with the matrix, A value o f s b a s e d -.. on research by Hingle, is widely applied. Values greater than 1.0 should be viewed with caution as they imply an additional resistance associated with the matrix.

Formation Evali~atiol~ Cool-sc Kotcs - 2.4 Saturation Exponent 'n' p e saturation exponent 'n' cannot be deterrmned from log data. Itcan however be calculated . . from special core analysis measurements nf -dex (see Appendix Q. Unfortunately the SCAL measments are not made on a regular basis and uallslllv_nalYafter commercial hvdrocarbons have u n . In the absence of the SCAL data then standard- - used or in certain situations_tn' may be - the cementati~ls factor 'd.

2.4.1 SCAL data - Resistivity Index Values for the saturation exponent 'n' can be calculated from the Resistivity Index measured in core plugs (see Appendix ll). The R.I. v- nt d i f f k m t levelsaf saturatipn and D- on log-log: w s . A straight line is normally defined with its origin at R.I.=1.0 and Sw=l.O. The gradient of the line is the saturation exponent 'n' and computed by:

n - - Log(l/R.I.1

Log(Sw) where: Sw water saturation (decimal format)

RI. Resistivity Index

In high porosity and permeabilimnles_thena w d u m g e of Sw's should be p r a ~ t . In low permeability formations the Sw range may be limited, and confidence in a line will be reduced.

. . . "1'~ Ideally ~~Gs&u@ Index -- -e qondit- be used 'to dete- 'n' Saturation exponent 'n' values at in-situ- conditions are expected to be higher than those measured at atmospheric conditions.

. . T h I ' h i s h e d cases where laboratory n IS not c ' 7 . onstant across the range of s a t u r a ~ d - i ~ a m p l e r . Such affects have been apibuted to ~omvlexities in the Dore texture v. In one cas~experiments were undertaken on artifjcial samples prepared from spherical glass beads. Where the beads had a smooth polished surface a constant 'n' was indicated, where the beads had been etched to give a rough surface texture 'n' was found to vary with saturation. Th-re - wall texture may be influential on the mstancy of 'a'. In other cases samples with non- >

constant 'n' values have been demonstrtaed to have complex pore systems typically comprising a mixture of small more isolated pore spaces and larger more open systems. In this case the 'n' v saturation relationship can often appear as a 'dog-leg' type relationship where an initial constant 'n trend at high water saturations is representative of the larger pore spaces and a switch to a different constant 'n' at lower water saturations the smaller more isolated pore spaces.

Formation Evaluatioe (:ot~rl;c Uotcs

/3

2.4.2 Assessing Saturation Exponent values Y s2

The saturation expo -s the way in which resistivitv increases as water saturatioqs . .

decrease. In the situation- replacing the w a t e r o n of the oil pr ES in thepore svace- the conductive ne twcujdxakr . The size of the pore spaces and pore throats, the tortuosity of the system will all influence this distribution. The hydrocarbon will naturally invade the more open pore space initially, and some pore elements may remain beyond the pervasion of the hydrocarbon yet still be part of the conductive network.

. . _At irreducible water saturation l e v e k j & z A d u c t i v e network in wat- m c t e d to the film of w a t e r s u m m h g the mains and any associated dia-etic uore f w . If t m i r is oil wet. then this grain coating film is replaced bv o i l a the restricted to the c-. The conductive network is seriously disrupted and very high resitivities and 'n' values will result.

Saturation exponent values normallv ranpe b--2.J with 7 0 u ~ i r i c a l l y denved -ta. In clastic reservoirs 'n' typically remains fairly constant over the range of porosities. In carbonates, with more complex pore geometries, 'n' may vary significantly and often in sympathy with the cementation factor 'm'. In the absence of SCAI, data 'n' may be taken equal to 'm' in such carbonat-

Formation Eval~~ario~i Course Notcs

2.5 Formation Temperature Values of Rw measured at surface conditions need to be corrected to formation temperature. Temperature data is recorded on each logging tool. At least two maximum reading thermometers are attached to each tool before logging. The maximum temperatures recorded are assumed to originate from the lowest depths reached by the tool. It is recognised that the borehole takes time reach a temperature equilibrium with the formation. It is observed that temperatures gradually increase with time. The rate of increase can be interpreted to extrapolate a true formation temperature using Homer build-up plots. Flowing temperatures from production tests will provide a closer guide to true formation temperatures.

2.5.1 Homer Plots The Homer plot is commonly used to display and analyse pressure build-up data from well tests. In this application, temperature, as recorded from the thermometers on the logging tools, is substituted for pressure. The plot is a log-linear crossplot of a time function (log axis) versus bottomhole temperature (linear axis).

The time function, Tf is calculated as follows:

where: dT Elapsed time since circulation of mud in the hole stopped

and the temperature measurment was taken, in hours. Tc duration of the last circulation period, in hours.

The elapsed time. dT. is the t w r a t u r e s in the borehole fluid k e w w . . .

tion. 'l$e circulation veriod. Tc. is usuallv taken as the -1 d

. . rill in^ and pull in^ It is a

time when mud is still circulated in the hole to clean out any cuttings, cavings and debris prior to logging.

T h ~ ~ u n l t l c n . ~ , i s 1 0 amhxmmses with elavsed time. It will reach 1.0 after an infinite elapsed time period.

The temperature data, recorded on different tools, must be from the same depth, and is plotted linearly in either Fahrenheit or Centigrade.

On the Homer plot points of temperature and Tf will generally fall on an approximate straight line with temperatures increasing with Tf. Extrapolation of this lineltrend to intercept the TI of 1.0 will indicate the probable true formation temperature.

Formation Evaluation Coat-\c botcs

2.5.2 Assessing Formation Temperatures The Homer plot will produce estimates of true formation temperature at the depths of major logging surveys. To assess their quality temperatures should be interpreted in terms of a temperature - depth gradient.

Within a field or even basin, temperature gradients are expected to show some consistency. They will reflect the historical or current tectonic character of the area. Temperature

. . m f l u e n c e d bv the t h e r m a l w t y nf t-c w u e n c e Zones with low thermal conductivity my divide shallow formations with a low temperature gradient from underlying zones with high temperatures and gradients. Whilst it is common practise to assume a linear gradient between surface and bottomhole temperatures, there is no geological or physical reason why it should be more linear than not. The combining of temperatures from several boreholes in an area may produce a more coherent understanding of the regional temperaturelgeothermal profiles.

4 Typical temperature gradients may range from less than 1°F to over 1S0F per 100 ft (1.8OC to 2.8OC per 100 m).

The tempaWjs+eqW1~ed 40-~onect -the.. .and-~-values.S~~~_e~.f_~mzatian~tempe~:atur:~ b ~ ~ & g g h e _ A r c C h i d c d a t i o n Where several temperatures are available down the borehole, then those straddling the zone of interest should used to interpolate and temperature.

Where o n l y s e downhole temperature measurment is available then either i t d d g d w t h m n e ne to surface is asume arbv wells.

2.5.3 Surface Temperatures

A surface temverature may be required to establish a linear madienf. It is common~ractise to use ,_---------- a m b i e n t ~ a ~ ~ s _ p h . e r i _ c - S _ e m p ~ t u ~ e s a s a s u ~ f a c ~ e . - This is unrealistic, they can vary dramatically on a daily basis and also seasonally, this sort of change can in no way effect the geothermal gradient. A temperature compatible with a shallow underground position is more relevant. Temperatures in caves only a few metres below surface will remain remakably constant throughout the seasons. These will obviously vary from tropical locations to arctic permafrost environments.

In offshore locations a mean w a t & , c m p e r a . f l .

Formation Evaluatiou Coursc Notcs

2.6 Calculating Water Saturation - Manpal Methods

Saturations are accurately computed using the Archie equation direct. The input data must be compatible for the particular zone being evaluated. In particular water resistivities must be at formation temperature.

To compute saturations in the uninvaded zone (Sw), that is the true or virgin water saturations then the Archie equation is as defined above:

To compute saturations in the flushed zone (Sxo) then the resistivity inputs are modified to:

where:

Sxon = a * R d 0" * Rxo

Rrnf resistivity of the mud filtrate Rxo flushed zone resistivity fkom micro-resistivity tool

Both Rw and Rmf should be at formation temperature.

Graphical Solutions of Archie Equation A graphical solutions of the equation can be used to produce approximate saturations. These are based on the Pickett Plot, the lo?-lo? scaled plot of resistivity v ~ o r o w that is used to define 'm' and Rw (see above) or from nomograms published in contractors chart books.

Pickett Plot Technique The establishment of a 100% water line is described in sections 2.1 and 2.2 as a technique for establishing Rw and 'm' values. This line can be considered an iso-saturation line. Increasing hydrocarbon saturations will cause a shift of the points to the right, to higher resistivity. Other iso-saturation lines representing saturations less than 100% water can be established to the right of the water line.

The gradient of the lines will be the same as the water line as pore geometry is not changing. The position of the lines can be determined by calculating the intercept at 100% porosity (0.10) for a particular saturation value. This intercept is calculated as the equivalent resistivity and computed using the following equation based on Archie:

Rt @0=100% = a*Rw Sw"

If n is assumed to be equal to 2 then Rt intercepts @ 100% porosity are computed as follows:

Formation Evaluatioil (:our-cc Uotcs

I Water Saturation (Sw) Rt @0 =loo% 1

Iso-saturation lines can be drawn through these intercepts and parallel to the water line to establish a saturation grid.

The water saturations at specific depths can now be easily read from the graph by plotting calculated porosities and measured resistivities and interpolating the saturation on the basis of the saturation gnd.

Chart Book Nomograms The main logging contractor's chart books usually include nomograms for determineing water saturations from the Archie equation principles. They are reasonably self explanatory but often require the input of F or FRF as parameter rather than separate porosity, 'a' and 'my values:

Note:

Formation Evalaation Coarse Notes

3 Saturations in Shaly Formations

Clay bound water is a conductive medium that is additional to the formation water that fills the pore voids. It therefore effects the resistivity readings of the formation and consequently the levels of water saturation computed.

A wide range of saturation models h a v e l v sands. in

The way in which the clays affect the resistivities depends largely on the distribution of the clays.

Laminated thin discrete laterally continuous layers and may be separated by virtually shale free units. The laminae are on a micro-scale and generally much thinner than the verticaI resolution of the tools. &cross the l a m i 4

eendda- b&- Lwre-. Structural clay fiagrnents forming part of the matrix between which there may be conventional

porosity. They provide a conductance that is in addition to the pore fluid. Dispersed clays that occupy parts of the conventional pore system and are commonly of an

authigenic nature. Where they occur their conductance replaces that of the pore fluid.

In summary: Conductive laminated clays replace non-conductive matrix and conductive . %

pore fluids Conductive structural clays replace non-conductive matrix Conductive dispersed clays replace conductive pore fluids

3.1 Water Saturation Models

A range of shaly formation saturation models have been established to reflect the varied distributions of the shale.

All water saturation models are constructed around the Archie equation such that at zero clay(/m% $d', volume the results are the same as Archie saturations. The contributiand&@o&e

. . formatian c o n d u c t i v i ~ ~ c t i o n of the clav volume and thedas-.

3.1.1 Total Shale Models These can be considered ~.eneral_p~q.osgmocl~~for shaly formations whgxe the shale --- distributio~comprise elemeat of both lamina~e_&_~~~sctural and dispersad. They are

-.-

commonly applied.

Simandoux Equation One of the earliest established shaly-sand saturation models. It assumesthe shales are hamage~~ee.owsinbath~physuA and electncal seEe and hvdrocarbotJ_im-ociated W&I-

the clay or shale component+ - - v . + 0 " * S W " A + p': 5 3 "

Kl, a * R w i. 6i.g.J &6'

It assumes the shales are homogeneous in both a physical and electrical sense and that some hydrocarbon may exist within some ~ k ~ . t s . ,. - -- --.----.- * --..- - ---- " --- - - - -. . -

,- - -1

where 'c' is a constant usually assumed = 1.00, but may be modified to match local saturation conditions.

Indonesia Equation A derivation from the Modified Simandoux equation based on data from Indonesia. C&ed more reliable athlgher Also commonly used around the world for shaly sands.

-----I

Formation Evaluation Coursc Notes

3.1.2 Laminated Shales

Poupon Equation A model designed for laminated clays. Assumes shales are homogeneous like the Simandoux and the lan nations include no hyd

where V,,, is the volume of the sh2

3.1.3 Dispersed Clays

De Witte Equation

Irc

ile : laminations.

A model designed for formations with dispersed clays.

3.1.4 Dual Water Models

Warman Smits Based on research into clay electrical properties from sands in the North sea. Clay bound water is chemically different to the pore water and there is an electrical imbalance between the clays and the pore fluid. The effect of the clays on the resistivity is dependant on the m e of bound water, and this is dependant on both t h e o f the clav and the surface area of the clays. Surface areas vary between clay types. The original equation relies on cation e x c h a n g e e m e n t s bei- conrc sanqdq. A normalised approach developed by Juhasz does not need the core data input.

where: Qv cation exchange capacity per unit volume

and Qv = CEC * (1 -0 ) * P,, 0

CEC Cation exchange capacity, measured in core samples B equivalent conductance of the ma+) exchange cations

and B = - 0.6* e"wm"13) ) * 0.046

Cw Conductivity of formation water, rnrnho/cm

Dual Water Model Two kmds of water recognised in the shaly formation

a) Bound water in the vicinity of the clay platelets. b) Interstitial water

where: Swb Bound water saturation Rwb Resitivity of bound water

Formation Evaluation Course Sotcs

Formation Evaluation

Course Notes

Section - 4

DEFINING RESERVOIR AM) HYDROCARBON LIMITS

1 SUMMARISING RESERVOIR PROPERTIES ........................................................................................ 1

2 NET/GROSS RATIOS, NET THICKNESSES .......................................................................................... 2

3 IDENTIFYING PERMEABLE ZONES ..................................................................................................... 4

............................. .......................................................................................... 3.1 PERMEABILITY INDICATORS i 5 ........................................................................................................................... 3.1.1 Direct Indicators:-. .5 ......................................................................................................................... 3.1.2 Indirect Indicators:- .5

4 CUT-OFFS .................................................................................................................................................... 6

..................................................... 5 DEFINING HYDROCARBON TYPES, LIMlTS AND CONTACTS 9

5.1 CAPILLARY PRESSURE ................................................................................................................................. 9 5.1.1 Calculating Capillary Pressure ..................................................................................................... 1 0 5.1.2 Capillary Pressure Measurements on Cores .............................................................................. I I 5.1.3 Capillaly Pressure and Saturation - Height Curves ....................................................................... I I

5.2 CONTACTS, FREE FLUID LEVELS AND TRANS~TION ZONES ........................................................................ 12 5.2.2 Identification of Contacts ............................................................................................................... . I2 5.2.3 Identtjkation of Free-Fluid levels ................................................................................................... 13 5.2.4 Assessing Contacts & Free Fluid Levels ......................................................................................... 14

1 Summarising Reservoir Properties

Reservoir properties are typically sumrnarised on a zonal or layer basis for use in mapping, volumetncs calculations or simulation studies. The average properties are thicknks weighted to account for varying intervals that may be represented by each computed value.

Volumetrics calculations require weighted average values of porosity and saturation, these /Jf'" can be combined with net thicknesses to produce pore column and hydrocarbon column thicknesses. , k Qr ', Average Porosity Thickness weighted average porosities are computed from:

/'

Ave.0 = 2-1 e- PC Ch ,

C---C- -

where h thickness 0 porosity

Average Water Saturation Thickness and porosity weighted water saturations computed from:

Ave. Sw = *0 * Sw) 5- pfT-

a h *0)

where Sw water saturation

Equivalent Pore Column Thickness - EPC The equivalent pore column thickness is the total thickness of pore fluid that would result if the matrix was removed.

Maps of EPC can be integrated to produce gross pore volumes for a structure or prospect.

Equivalent Hydrocarbon Column Thickness - EHC The equivalent hydrocarbon column thickness represents the total thickness of hydrocarbon that would result if the matrix and pore water was removed.

EHC = C(h * 0 * (1 - SW))

Maps of EHC can be integrated to produce hvdrocarb- - - volu mes for a field.

The thickness (h) in the above calculations are-likely to be net thicknesses, that is the total thicknesses that are considered to be potential reservoir zones.

Formation Evaiuation C'ourw hutes

2 NetIGross Ratios, Net Thicknesses

N m e most commonly used in v o l u ~ ~ interval t h a t . The ratio is unitless and reflects the overall quality of a zone irrespective of its thickness. I; is usuallv a mapgable parame-

. . h n e t h ? u % a d s _ t h e e r v o m- ir rock thickness,

By careful selection of the criteria for defining net thi~knesses~the ratio concept can be used to aid both geological and reservoir interpretation.

A number of important definitions need to be established. However one should be aware of differing definitions between individuals and organisations. For these discussions we will establish the following:

Gross Total intervalhone thickness (Base depth - Top depth) Interval Net Sand Total (accumulated) thickness of all sandstones in the Gross interval (irrespective

of the reservoir quality of the sand). Net Reservoir Total (accumulated) thickness of all sandstones of reservoir quality in the Gross

interval. Net Pay Total (accumulated) thickness of all sandstones of reservoir quality with movegble

hydrocarbon. -

All net thicknesses will be subject to some criterialproperty of the formation being satisfied.

Net Sand The criteria (for cut-offs) will be based on 1itholo~ic;al properties such as shale or clay content or anhydrite. -

Net Reservoir The criteria (cut-offs) will include the litholog~cal criteria used for net sand definition and also include criteria based on reserv-roverties. such as porosity and p e r m e a m .

Net Pay In addition to all the criteria for defining net reservoir additional cut-offs related to hydrocarbon content will be included, such a s w a t e r .

By adopting such definitions various ratios may assist in understanding a formation and its lateral variations.

Net SandIGross Interval Indicates areas where sand deposition is concentrated. This should complement facies mapping, and help define sand body orientation, and sediment source directions.

Net ReservoirIGross Indicates areas where better reservoir quality is to be found. This - Interval should aid exploration, appraisal and develapmentplaanmg. Maps

should be reviewed with other considerations in mind, such as depth, facies variations, diagenetic changes to establish the major controls on reservoir quality.

Net ReservoirINet Sand Indicates variations in sand quality. Should help define controls on reservoir quality such as depth, cementation, diagenesis, and facies.

In attempting to distinguish net reservoir and pay intervals it is important to recognise one reservoir characteristic, permeability. All net reservoir and pay zones must be permeable if -- fluid is to flow through them. Permeability is difficult if not impossible to quantify from logs. so is available to be used as a cut-off. The reservoir urop-ty and shale cnntent

. . are f r e q u e d u U l y control D- However the limits belowlabove which formations are not permeable will vary between and

where zonTs are permeable. / - / - 'c - 1 :

Formlation Evaluation Course S o w

3 Identifying Permeable Zones 5- #fi3-

Permeabilitv is a measure of the ability of a I

A permeable formation must therefore have porosity of some form that is in communication. . .

The degree a 0 system. The quality of the communication may also vary in the formation and independently of the porosity.

There is a likely link between permeability, porosity and pore geometry.

In clastic rocks (sandstones, silts) theie is often an obvious relationship between permeability and porosity that takes the form:

where K permeability md 0 porosity

a,b constants defined from regression analysis

This type of relationship i sa l icable to a single pore geometrv m e . Separate parameters ( c J a & b) may be required to be defined for separate layers where different pore geometries

exist. . -. Irreducible water saturations ( S W ~ ) vary a ?henome-

m' c a ~ i l l a q q m s s u ~ a s m m m & o ~ e ~ a m ~ A relationship was defined by Wyllie & I

Rose that includes Swirr as a pore geometry component. It takes the form: Pal

K = (C "0 '1 ~wirr)*

where C constant related to hydrocarbon type (C=250 Oil, C=79 Gas)

Timur proposed the empirical relationship:

Other researchers have identified relationships between permeability and resistivity (Tixier - Gradient method) and acoustic attenuation (Lebreton).

T h e ~ u c l e a r M a n n e t l c R e s o n a n c e e e t

free fluid, which w i l l ~ n - "- qu-- . . . gmcadmxthdicatar of n ~ r p r a n u l a ~ y s k m . In carbonates, where vug& porosity may exist, the NMR log- not be a reliable permeability indicator. / -. I

Formation 1- valuation ( ourw \ore\ Cm t 7 ~ c / p C

Permeability is notoriously difficult to estimate from logs, particularly in carbonates where rapid pore geometry changes can take place in a short interval. There are, however, a number of logs that can indicate the presence, to a lesser or greater degree, of permeability.

3.1 Permeability Indicators

Permeability can be measured in core s a m w limited extent. cores cannot be relied qa to dea l lT l - s i~eags . Reliance is placed on the w3tline 109 data which can in- pre w e of fluid invaninnb--. This may be by direct measurements of fluids in the formation or by indirect measurements that infer filtrate invasion or probable permeability

3.1.1 Direct Indicators:- d~ q h b ;

k L /

SP SSP deflections on SP log to the left or right across zones of appropriate reservoir lithology. NB the lack of SSP may result where there is no salinity contrast between mud and formation water, so may not be reliable

Caliper presence of mudcake (caliper < bit size). NB lack 6 presence of net reservoir 4 ; ~ ~ . rL

Microlog presence of mudcake (micro-normal > micro-in'verse) - (@t

Resistivities shallow and micro-resistivity. ..

\. '

Gamma Ray low GR mdicates low clay content Density, Neutron, high porosity may indicate high permeability Sonic/Acoustic Interpreted low clay and high porosity may indicate high Porosity, permeability Clay Content P I ,, ;..ells NMR free fluid levels may directly equate to permeability

Fonmtion Evaluation Cour4e Soles

4 Cut-Offs

4.1 Selecting Cut-offs

Cut-o - ffs are used to defithP_llmits of the permeable and hy- Permeability data is not usually present throughout the reservoir sequence nor in all wells, so I I

cut-offs have to be based on the other more extensive log data. i

The logs or data- chosen h e . . .

c m n g p e m l . These will help define those zones considered to be net reservoir.

Additional cut-offs will be required to define the hydrocarbon zones, these will used to define net pay. *is

Single cut-offs may be adequate in some reservoirs, other more complex formations may require multiple cut-offs. an

mu

Potential Cut-off Net Lithology Gamma Ray J

(Sand) Clay Content PEF J- )'k@ wc Density *e. I Y ~

Acoustic Net Reservoir I

.M ,

la

mD

.I*

Microlog II

Saturation Moveable Hydrocarbon Resistivity

Net Pay

4.2 Defining Cut-off Values

Cut-off values define the limits at whi- permeable. Cut-off values are selected by direct comparison with permeability or a direct or indirect permeability indicator by use of crossplotting or statistical analysis. For example:

i ;) Porosity v Permeability Permeability is often related to porosity, this is particularly evident in clastics. but often less

gredictable in carbonates. Crossplotting core porosity v permeability on lin-log scaled graph paper will highlight the relationships discussed in E.3.l.. The relationships may change between facies types within a reservoir sequence and necessit.te/justify different cut-offs.

I' Clay Content v Permeability 0 Decreases in permeability may be solely due to increasing clay content. Variations in clay type or distribution may lead to changes in cut-offs between reservoir units.

@) ~inera logv v Pernteability Mineralogical changes, such as cem clastics or dolomitisatio~in carbonates, can change the pore geometry and permeability.

Iw) ~esistivity v Permeability Resistivity will be related to permeability and to saturation however saturations are only likely to show significant variations above permeability limits.

Saturation v Permeability Saturation variations will only be evident above permeabili~limits where fluids are moveable.

!v;, Saturation v Rwa (Ratio) Rwa should be constant in non-permeable zones, and will increase where moveable hydrocarbon is present. In clean (clay-free) zones Sw should be constant (= 1.0) in water bearing zones and decrease in the presence of hydrocarbon. The onset of increasing Rwa and decreasing Sw will indicate the Sw cut-off for net pay.

Rwa (Archie) v Rwa (Ratio) Rwa (Archie) increases with any hydrocarbon. Rwa (Ratio) only increases with moveable hydrocarbon.

( O i ($Q' 4.3 Sensitivity Analysis 'I-

T e h plication of c l t n _ d c f i n e n e t a t cm&e &Jxuqu. Reservoir properties are often too complex, particularly in carbonates, to be categorised by simple fixed cut-of values. F w o m i c studies it is useful to check the sensitiviw of the resulting incremental and zonal c o m u u t e d o i r pqm3.w to v e t i o n s - At the m , e n t a l levd the sensitivity of porosity to key i- such as:

Matrix properties Hydrocarbon properties Clay content/clay determination techniques

or the sensitivity o f k t u a h ~ to parameters such as:

Formation water resistivity 'Rw' Cementation Factor 'm' Saturation exponent 'n' Water saturation model Resistivity log 'Rt'.

At the zonal scale then the sensitivity of net thicknesses to different input data such as:

Porosity Clay content Saturation .

or sensitivity of net thicknesses to cut-offs.

Economic Conseauences

' .ammetam the a u u h ~ ~ ~ The significant economic v o w v -h~ adumn thickness (EPC and EHCL. Mapping of these parameters alone can yield gross pore volumes and in-place hydrocarbon volumes and so the sensitivity of these to changes in evaluation parameters or cut-offs can be more readily appreciated economically.

Crossplots afw-tions w i b & e a s d ~ g h & h t d i ~ ~ . .

themost s i g n i i t t a n d . s ~ Q The process however requires that the reservoir summation should be made using a range of cut-off values.

&;r. a ~ k i t ! & ~

The recognition of the vertical extent of hydrocarbon accumulations is crucial to estimating & ,;i-fi/s , total and recoverable volumes. Hydrocarbons are generally considered in terms of being gas or oil. At atmospheric conditions it has to be either in a liquid or gaseous form. At reservoir conditions of higher temperatures and pressures the liquid phase may contain significant quantities of dissolved gas, and may be considered as a condensate. At the heavy end of the hydrocarbon range very viscous tarry oils may be encountered or even solid bitumen. .

Hydrocarbons are lighter than water, which is the other main occupier of the pore space, and the two fluids are immiscible. Where the two are present in the same reservoir fluid system ,+ then the mobile fluids will segregate with the lighter hydrocarbons being concentrated above I I

the heavier hydrocarbons and all hydrocarbons lying above the water. !

Evidence for the location of w t a c t s can be drawn from a wide w. These range from positive visual evidence and definitive flow tests, through ---A- interpreted~esults - - of s a w ~ n s from logs, tojnfc-red fluid densities..&om formation pressure gradients. These different sources, however, may produce apparent contradictory indications. An_ understanding of the capillary forces which contrplt,hg vertical distribution of the-uore a will enable many of the contradickry indications of contag . s J ~ h J i p ~ ~ . i s e _ d .

--TIY- i 1

If a mixture of hydrocarbon fluids and space, such as a flask, then with time, the fluids would segregate into discrete fluid layers. The contacts between the fluid types would be abrLpt with 100% saturation of the respective fluids being observed immediately above and below the contacts. If the void space is filled with vertical microscopic tubes then capillary forces will draw the underlying fluids up above their original upper contact levels. The height to which these fluids can be dependent both on the diameter of the tube the fluids. 5 +r.$.o-a py(&

- - 2 ".,-L:"/ . The s j t u a t 1 o . n , . 1 n ~ a _ x , e ~ ~ . e . ~ ~ ~ ~ ~ n ~ g o ~ o the c a p i l l a ~ h e r e J q d h

~ ~ e a b i l i t y _.I.I _I__ of the ____ rock .--. equnfeswth.&Miameter.&he.tuhes. The reservoir p s ,,, -- is never homogeneou_s and the appropriate laboratory model would comprise capillary tubes

I

-above to the o i l -wat~wntac t there may be tuhesacupied by oil immediately adiacent to with a variety of diameters each sustaining fluids at different heights. At a particular level /LveA ($tk narrow tubes occupied byxakr . The overall saturation of water at

tsha roportion of void sp bv w&r. At levels further above the oil- cater contact the n u m E f t u b z n g water columns would be reduced and thexx Dd(b h overall water saturation would be lower. q r . ~ L , pqY,/, & ~ S L &, d

Folmation Evaluation Course Notes

the o t h e r . This causes the fluid with s-on to draw into a spherical shape at the contact. The spherical shape, however, can only be maintained if there is a net force or pressure differential across the fluid interface. Capillary pressure is defined as the pressure discontinuity or drop across the interface separating the immiscible fluids (Pickett 1972).

i Where the fluid contact encounters a solid surface, i.e. the pore wall, the angle between the fluid contact and the surface will be constant. This reflects the preferentiaJxcttabi&yd,the surface thatis dicta.tehbv.,the.s&m~~&mh attraction of one of t&-o the sudace One of the fluids will tendto disdace the other and themle . b e t w e e n A d l u ~

l t v of one fluid over the o t h a

5.1.1 Calculating Capillary Pressure

Capillary pressure (PC) in a tube can be calculated from the fluid interfacial properties and the radius of the tube as:

PC = 2 T Cos8 r

where: T interfacial tension between the fluids 8 contact angle r tube radius

Typical values for interfacial tension and contact angle are surnrnarised below:

1 Oil-Water 1 30 1 0.866 148 1 42 I

/ Pore Fluids

Laboratory systems

I Air-Water

Air-merc 140 0 , Air-Oil 10 11.0 124 1 24 1

CosO Contact angle 8

0

C * - T V ~ tbc relative densitv di-between the two fluids. The computation for determining height above the hydrocarbon-water contact is:

Interfacial tension T

Reservoir Systems I water-oil Water-Gas

where: h height above water level- feet pw density of water- psilft

T Cose

1.0

1 I

72 I 72 I

* Pressure & temperature dependent. Reasonable value to depth of 5000 ft. (Source: Fundamentals of Core Analysis , Core Laboratories)

30 0

0.866 1.0

I I

30 2 6 50* g 50

ph density of hydrocarbon - psilft

g gravitational constant

from the two equations above, height can be directly related to the fluid interfacial properties and their respective densities In the form:

5.1.2 Capillary Pressure Measurements on Cores

u l a r y pressure p o r t pon-wettm-id - . j r e s s u r Q . The measurements can be undertaken with any combination of fluids provided one is a relative wetting fluid and the other a relative n m d . Common combinations are d w e t t i n g ) - mercury (non-wetting) and air - b*. Plots of capillary pressure (injection pressure) v wetting phase saturation are used to define capillary pressure curves.

The caplllari_pre~s_u_r~e~~can_b~_a@ted in to a ~ ~ _ a b o v , e - t h e . f iee -wa_te,rLflyLdm. The equation is based on the relationships defined above but has also got to account for the differences in the interfacial properties between the laboratory fluids and the reservoir fluids. Height is determined as follows:

where : (T C O S ~ ) ~ , , interfacial properties between reservoir fluids (T C O S ~ ) ~ ~ interfacial properties between laboratory fluids

Plotting height against the wetting phase saturation produces a saturation height curve that enables the prediction of saturations at any depth with reference to the contact.

5.1.3 Capillary Pressure and Saturation - Height Curves

The shape of capillary pressure curves reflects the pore geometry of t-. A range of samples from the same reservoir unit will produce capillary pressure curves that differ slightly or dramatically depending on the heterogeneity of the reservoir.

In samples with go@p_orosity and permeabi&y then or&..law iniecti~ldl..f)f.essures -ry ressures are required to inject non-wetti,ng fluid~uidn.t_o~the~ Characteristic capillary a- -_--.4---.,.+-., ---.*---"----

pressure curves will show rapid decreases in wetting fluid (wat~r) saturations at low pressures and a relatively abrupt stabilisation at low saturations.

In samples with poor permeability then the reduction in non-wetting fluid saturation is much more gradual. In extremely low permeabilities there may be no injection of fluids until a minimum injection pressure has been attained.

In evaluating cap. curves the

Threshold Pressure S ~ T L kh.d-3

This is the initial injection pressure, or start to decrease from 100%.

Irreducible Saturations A

This is the stabilised minimum saturation of the wetting fluid that is evident at high- vressures, It will be easily identified in highly permeable and porous samples where very low irreducible saturations may be indicated. In low permeability samples a stabilised saturation may not be achieved.

It is the capillary effects which dictate the nature of fluid contacts i k can make k v l . m d ~ e a . t a l o n e a n d transitional and

T.

dwS-to-pin=point,

iP ,

5.2 Contacts, Free Fluid levels and Tkansition Zones

Contacts The gas-water or oil-water contact is generally considered to be the depth above which water saturations are persistently less than 100% in reservoir quality rock.

Free Fluid Levels The free-water-level is generally considered to be the depth above which hydrocarbon is present as a continuous phase in the reservoir.

Transition Zone The transition zone is the interval of increasing hydrocarbon saturations below the zone of irreducible water saturation.

5.2.2 Identification of Contacts Contacts can be indicated from a number of data sources:

Mudlogs Loss of gas shows in mjd system. .

Change in chromatography of gas in mud. --Appearance/Loss of oil shows in samples.

Change of typeldescription of oil show in samples. Cores Loss of bubbling gas shows and odow in cores.

-Appearance/Loss of oil shows in cores. Loss of measured oil retortedcentrifuged from samples.

I Fol-rmtion ).\:~luatiorr o out^ \otcs

Logs curves. Loss of gas separation between Neutron and Density

Gradual or abrupt drop in deep resistivity. Water saturations computed from log analysis

1 \ / p&/eP-" 9

Whilst it is expected that contacts should be horizontal across a field, there are circumstances where this may be not occur:

Contacts may become tilted where a dynamic aquifer exists. F w l contacts can create a misleading and confusing impression of the hydrocarbon & '

distribution. 0 Variations in pore geometry will result in varying capillary threshold heights across a

field and apparent variations in the contact depth.

%im 'i$< :< . 5.2.3 Identification of Free-Fluid levels

Free-auid levels can be defined from formation-p-gdata usuallv a c a u i r g ~ b n e testin!z-toolsRFJ or FUT).

The formation pressure is the pressure in the pore fluid that occupies the pore space. Under normal pressure laws. at any one depth the pore fluid pressure should be the same across the accumulation. Pore fluid pressure will increase with depth at a rate dependent on the density of the pore fluid. Iftwoimmiscible fluids co-exist m A ~ s v n o r . - in ~ h ! o ~ ~ ~ ~ s ~ j _ n . ~ S h ~ ~ p ~ r e ~ s y ~ . S ~ m ~ i d l @.

Wireline testing tools are able to acquire fo~_a~n-pr.~su~:~easute.mc~ownhole at-.,, -ugh the h y d r o c a r b o n - a . n Q - w a t e ~ b e ~ ~ ~ t i ~ ~ s , ~ a ~ . If reliable pressure measurements are acquired and plotted against true vertical depthlthe pressure gradients between sampling points can be determined and related to a pore fluid density. Multiple pressure measurements from within one single continuous phase fluid should define a single pressure gradient. This will indicate the type of pore fluid present. Where two or ~ ~ . k n . t s . , a ~ ~ ~ n ~ ~ ~ h ~ free--1..

As pressures should be the same at any one depth in the accumulation pressure data from several wells can be combined in one display and used for determining pressure gradients, hydrocarbon types and free-fluid levels.

Compatibility of pressures, pressure gradients and free-fluid levels between two or more wells confirms they have all penetrated the same hydrocarbon accumulation.

Typical pressure gradients for different fluid types might be:

Hydrocarbon densities can be computed from pressure gradients:

Ph g/cc = Gradient / 0.433

5.2.4 Assessing Contacts & Free Fluid Levels Contacts are commonly associated with the presence or absence of hydrocarbon, and the data may not be adequate in determining whether the hydrocarbons are mobile or not, or whether the formation is of reservoir quality. ssure data, are indicative o&, t ~ u o u s kaselluids and cenerally ar-tative of re- r d . It is not uncommon therefore to find that the indicated contacts and free fluid levels do not match each other. Some points to note;

Where a well intersects a fluid contact in a thic-servoir unit {he c w s -vels-ld be in clos~eseement, particularly if it is a &as-water contact and a short transition zone is present. Where a well intersects a fluid contact iq poor @ty reservoir rock]the free-fluid level may appear to b e m than the fluid contact &?to threshold capillary effects, supporting

A water above the free water level. Where are present at the base of the hydrocarbon column the free- fluid level may appear higher than the fluid-t due to the residual hydrocarbons not being in continuous phase. Where reservoir quality is varying significantly across a field,contacts may fluctuate between wells. A single free-fluid level, however should be evident. Eor volumetrics the fi-ee-fluln level w e reliable reference to use

--

FORMATION EVALUATION

Course Notes

APPENDIX I

LOGGING TOOL INFORMATION SHEETS

GAMMA RAY

SPONTANEOUS POTENTIAL

COMPENSATED FORMATION DENSITY

SONICIACOUSTIC LOG

COMPENSATED NEUTRON LOG

PHOTO-ELECTRIC FACTOR

LATEROLOGIFOCUSED ELECTRODEIGUARD LOGS

INDUCTION LOG (ILD)

MICRORESISTIVITY LOG (MLL,PL,ML,MSFL)

ELECTROMAGNETIC PROPAGATION TOOL (EPT)

NATURAL GAMMA RAY SPECTROMETRY (NGS, NGT)

NUCLEAR MAGNETIC RESONANCE (NMRIMRIL)

SHEAR WAVE ACOUSTIC LOGGING (DIPOLE TOOLS)

STATUS : Developed 1935. Basic correlation, depth calibration log recorded on nearly all surveys.

MEASURES: Natural radioactivity ernmitted by the formation. Records levels averaged over a time constant synchronous with the sampling increment and the logging speed.

UNITS: API (American Petroleum Institute standard based on calibration test pit facility in Houston, USA.)

INTERPRETATION PRINCIPLES: Most widespread radiodctive element in sedimentary rocks is Potassium 4B. Thorium and Uranium also common but less extensive. Potassium 40 mainly associated with clay minerals. Clean sandstones, carbonates, most evaporites lack radioactive elements.

CORRECTIONS: Travel path of GR's impeded by electrons (Compton scattering). Electron density controls bulk density. Natural GR levels therfore particular= reduced if impeded by high density matter such as steel casing or heavy mud. C c

QUANTITATIVE ANALYSIS: Relative changes in GR more significant than absolute GR values. GR responds linearly to changes in radioactive element concentrations:-

e.g. Vclay = (GR - GRrmn)/(GRmax - GRrnin) Typical matrix response values:

I Clavlshale 1 80 - 200 1 Dolomite 1 10 - 20 I Salt/Anhv. 1 0 - 10 1 . . I I I I I

Sandstone I 20 - 40 1 Limestone 1 10 - 30 1 Coal 0 - 1 0

#'

PROBLEMS: Radioactive minerals - Mica, Glauconite, Zircon, Uranium KC1 mud systems - Potassium in mud and filtrate

APPLICATIONS: Define depth and character of lithology boundaries. Well to well correlations. Grain size indicator Quantify claylshale proportions. Detectlevaluate radioactive minerals.

&-- + &d+.$L- . - 0 vl- ,, +y-

2 SPONTANEOUS POTENTIAL STATUS: Principle correlation log before Gamma Ray. Recorded on all resistivity surveys. MEASURES: Electrical potential generated by ionic imbalances between the formation and

borehole fluids and ion-selective components in the formation such as clay. Ionic imbalances between fluids exist when salinities differ. I&&

In homogeneous impermeable shales, the SP has no character. DeflecJi,nt~ah&S_eS~q(2c~~r - where the ---.- formation fluids are ---.-_l___l_--r-*_CI_CIl- in contact with ----,. the --.. borehole ---.-..-.-. fluids A. and h~ceQfEumtsalmtig~lr Contact is only established in permeable formations. Negative deflections (SP curve moves to left) indicate formation fluid is more saline than borehole fluid. Positive deflections (SP curve moves to right) indicates formation fluid is fresher than the borehole fluid. The magnitude of the deflection (the Static SP, SSP) is controlled by the magnitude of the salinity contrast, the claylshale content and the permeability.

CORRECTIONS : The SP has poor vertical resolution and does not attain maximum SSP'S in beds less than 30-40 feet (10-15metres) in thickness. SSP is affected by varying filtrate invasion. Corrections,,ar~e.re.q.uired..f~r~bed-thYr_ckess acd jnva@on. -- - -a- -

P - - . - _ - - -

QUANTITATJYE ANALYSIS : G(.+ ,: J Relative change (SSP) is used in all

t2d C Rmf= SSP is related to the formation water resistivitv by ------ - ----------

PROBLEMS :

APPLICATIONS:

- - .- - -SSP = -(60 + 0.133 *T)*log(Rmf/Rw) -

- 7

where: Rmf = mud filtrate resistivity at T deg F ---. Rw = formation water resistivity at T

SSP may respond linearly to changes in clay content. Rd >-&,, __ __

Vclay = 1 - SSPISSP max

- - I_

No SSP if borehole salinity Incorrect Rw's calculated if formation is shaly. Large electrolunetic effects where borehole pressure exceeds formation pressure. Define depth and character of lithology boundaries, facies analysis. Well to well correlations. Locate porous and permeable formations. Determine formation water resistivities. Quantify claylshale proportions.

3 COMPENSATED FORMATION DENSITY STATUS: Introduced 1954 for gravity studies. The most imv- tool o\rer.reservoir

iptemls. Recorded with the compensated neutron as both a litklogy, por-ity and ga3dicator.

w+*" MEASURES: The reduction in intensity of a gamma ray stream between two receivers. The

+h* measurement is of the absorption coefficient of the formation.

UNITS : Gramrnslcubic centimeter (glcc, glc3)

ctod( . :&:,&.J$&LjiYTti- INTERPRETATION PRINCIPLES : t ~ j kd 4, ~ - , t

. . fl& f~,-- Gamma ray intensity is reduced by (Compton scattering). Electron w? v d a u l ~ ~ Absorption coefficient is therefore related to bulk density.

Density is linearly related to the rtions and densities of the f o ~ a t i o n constituents

@ 1 including fluid in the pore space%:is have lower density than matrix so I 7 b s i w - I , _ is expected in p o ~ s 7. Porosities from density logs are total porosities. 1 1 -- J-: ." w - i ,'&

' ! r CORRECTIONS: I

' Compensated density is automatically corrected for borehole size. Correction curve is L

-displayed to show level of correction. Detectors are pad mounted, if pad loses contact with borehole walbreadings will be unreliable.

d & Y C 4 ! ~ C / , . w c C . G i . c A &-- 'fitah+ *.-

Q U m A T I V E ANALYSIS : Bulk density varies linearly with matrix and porosity components such that in a shaly formation with hydrocarbons:

Pb = Pma*Vma + Pclay*Vclay + PPSxo + Ph*(l-Sxo) and in clean water bearing formations:

Porosity = (Pma - Pb)/(Pma - Pf) Matrix resvonses: I Sandstones 1 2.65. I Salt 1 2.07 Water I 1.0 - 1.2 I I Limestones 1 2.71 - 1 Anhydrite 1 2.97 I I I I Dolomite / 2.87 - I Shalelclay 1 2.00 - 2.70

M C e , 2. p r - L - q b

PROBLEMS: Gas significantly reduces densities if high saturations present near borehole. Porosities will be over-estimated if uncorrected. a~

Heavy minerals increase densities and reduce porosities if unaccounted for (eg. -r,ll

Mica, Pyrite, Siderite, Anhydrite). Porosity in clean formations. 8@?

Lithology and porosity when crossplotted with sonic, neutron, PEF. diii

Identifying gasflight hydrocarbon zones. rn

Determining hydrocarbon density. Creating synthetic seismograms with sonic. **.

Density measurements for gravity studies. lllr

STATUS: Principle correlation log used for cali-mic data. The most extensively recorded of all the porosity logs. With the GR probably the first log recorded in most wells.

MEASURES: The times from the emmision of an acoustic signal by the tool to the first significant

y o 4 0 f l k arrival at the two receivers mounted on the tool. Times presented reflect transit times between the receivers.

UNITS : Microseconds per foot@if) or metre (uslf).

INTERPRETATION PRINCIPLES: Sound waves compressional, shear and fluid waves. Compressional waves travel t w i c d e speed as others so tool measures compressional wave transit tune.~aster acoustic path is A_------

through the formation matrix so are matrix dependent. In porous rocks the transit path is longer to circumnavigate pores, so transit times are related to matrix porosity. Secondary porosity such as fractureslvugs will only affect transit times if intensive.

There are no standard or common corrections. Calibration checks can be made in casing (57 pslf) or in homogeneous zero porosity formations such as salt (67~s i f ) or anhydrite (50 )@If).

PROBLEMS: Cycle slaps due to borehole, weak signals, fractures may reduce quality but may aid fracture detection.

QUANTITATIVE ANALYSIS: Traditionally transit times have been considered to change linearly with porosity, but with some factor adjustments in under-compacted formations (Cp), this is described by the Wyllie time average formula:

Porosity = (DTlog - DTma)/(DTf - DTma)*Cp $. Non-linear responses have been demonstrated (Raymer-Hunt).

.fp..

Typical matrix responses: & P/F+ ,Quartz(sst) 155.5 IAnhydrite i51.8 i Water 1189.0

High gas saturations near borehole may increase transit times. No corrections. APPLICATIONS: Well to well correlation.

Limestone ] 47.5 1 Salt 1 Dolomite / 43.5 1 Clayishale

Evaluating porosity in homogeneous formations. Detecting lithology by crossplottting with densitylneutron. Identifying secondary porosity.

67.0 1 I I

80.0+ 1

Identifying fractures. Seismic depth conversion, synthetic seismograms. Detecting overpressured formations. -

( U' L g7 - ~ M $ flQ *whL kp y-7 -'I

~ W L m%wia 4 iibr &%X @+ C(r- 4<& &&Uj L s t -

L(~:;~III$ i o ~ d 1 1 1 f i v ~ ~ ~ t i 0 1 ; 5 l i L ? f .

5-?w 6 3 - L'kA &t , ~d'v-d-? ) LJ&- c efl0.t h w&$4'

i 5 COMPENSATED NEUTRON LOG Present day preferred Neutron tool, supercedes older gamma neutron (GNT) and sidewall neutron (SNP) devices. Recorded with Litho- and Formation Density tools as a porosity, lithology and gas indicator.

MEASURES: Thermal neutron energy levels of high energy neutrons emitted by the tool. These r w

levels are intermediate to the epithennal (early, SNP) and the neutron capture (late, 1

GNT) in the energy decline process. m'

UNITS: Porosity units (calibrated in limestone) I

INTERPRETATION PRINCIPLES: i II*

Decline in energy levels is due to collision with atoms of similar mass, in particular J

hydrogen. It is therfore a measureaf the hydrogen index of the formatioa As hydrogen is primarily associated with water it is adirect measure of the total water filled porosity of the

7 - l formation. Hydrogen also occurs in hydrocarbon. Oil may have similar hydrogen index to water so no significant effect observed-Gas has much lower hydrogen index so may reduce apparent porosity from CNL. I I CORRECTIONS:

I Dual spaced detectors correct for some borehole effects. Additional corrections required for i mudcake thickness, borehole and formation sdinity, mud weight, tool stand-off, pressure,

&m +L temperature. Can --- be run - in cased . holes . - where corrections _for casing and _cement arerequired. -

i I \ QUANTITATIVE ANALYSIS:

Neutron porosity directly reflects porosity in clean, water bearing limestones Corrections for other matrix types are non-linear. Approximations however are:

j! ,w. '+A I.W

Sandstones:- Limestones:- Dolomites:- Porosity = CNL - 4 % Porosity = CNL Porosity = CNL + 3.5% (Porosity < 1.5%)

Porosity = CNL + 5.5% (Porosity 1.5 - 5%) Porosity = CNL + 7.0% (Porosity 5 - 20%) Porosity = CNL + 6.0% (Porosity 20 - 30%)

Ira fCd Porosity = CNL + 5.0% (Porosity > 30%)

PROBLEMS: Bound water in clays appears as porosity. Needs to be corrected for in shaly 0

formations. High gas saturations near the borehole reduce the apparent porosities.

APPLICATIONS: Porosity in clean formations.

,i1, ,Lc q' I: LG (I-% Lithology and porosity when crossplotted with sonic, or density logs.

r i p @' Identifjmg gasnight hydrocarbon zones. /?LA f---

-_ - . Determining hydrocarbon density. -_ /, pv.<b $ d e b 664r64 d h . l t :I c J G j q do, t( M1

J 4d

&wf i * R - - c k p . L d 9 LL~L CP" 4a 5 I ~h vy-. 5 ...-.- ----C------l J - Wd-b

f- W S * , &y.hl&hJ .e .-& ,,&C* P[~J 8 h h c ~ ~ w - --- -_ --- &.i W L ~ C 6 k pt (J7L , d+,*

STATUS: Recorded as an additional formation response by the ~ i t h o - ~ e n i i t y ~ b d (LDT). This tool is now the standard porosity tool and run in combination with the compensated neutron (CNL). PEF is an indicator of lithology.

MEASURES: The photoelectric absorption index ( P d of the formation by comparing gamma ray - levels at the low and high e n e r w the suectrum. The earnma rays are emitted by the tool at an ~ ~ - Q ~ ~ Y .

UNlTS : Barns per electron (ble)

INTERPRETATION PRINCIPLES: At high enmleJJP1F_thenumber gamma rays are related p r i m to e-. & l o w r w w = r . e M 3 ~ electron de&andphc&&cahsnrgtran. Comparison of the two gamma levels can indicate the photoelectric absorption index. This index is linked to the average atomic number of the nuclei of the atoms in the formation:

Pe= ( z ~ . ~ / 1 0) where: Z = mean atomic number and is directly related to lithology.

CORRECTIONS: No corrections are currently published for the PEF. Both the PEF and associated LDT bulk density measurment are dependent on direct pad contact with the formation. If this is lost readings will be unreliable.

QUANTITATIVE ANALYSIS: ) L/(ni

May be related linearly to matrix absorption cross sectlon (U) by multiplying by the bulk density (Pb).

/ I

PROBLEMS: PEF can be significantly affected by barlte in the mud system. PEF of barite is 266 with U = l0JJ-h such muds tool unreliable. However where barite mud penetrates open fractures PEF can be a good fracture indicator.

Typical response values:

Some heavy minerals may increase PEF and U values and lead to erroneous lithology interpretation. E.G. Pyrite, Hematite, Zircon.

APPLICATIONS: Lithology typing. -- M,Fi : i./ , ..&-. A . + 2 Lithology and porosity when crossplotted with density log. Identifying fractures in barite mud boreholes.

f j PEF ' U

j Qua* 'Calcite '5.084 ;?7 I

: Dolomite 3.142 1 9.00 FL,J I(,n h l ? j

fb ch2hM r ) l Q b * e

1 PEF Halite 1 4.650 Anhydrite 5.055 Ilhte 3.450

U 9.65 11.95 8.69

Water Oil

PEF U 0.358 1 0.30 0.120 1 0.11

I c

LOGS &WL b-4 .f- pcpir3.

STATUS: Devised to measure formation resistivities in boreholes with conductive muds. \ More accurate where resistivities _ e u c t i o n log; and-hasBette~\rerticalre&~&.&n. Cannot be run in oil based or fresh water ' j

. . MEASURES: T s h nt and

measuring t h e g n f t h ~ c l l r r e n t at The spacing I I

between the transmitting and monitoring electrodes dictates the depth of investigation. Tool also features guardlbucking electrodes that focus the current into a thin sheet and increase the vertical resolution. Sp- I

e a g h a d s h m e t o e

P==- UNITS: Ohm-meter /meter (Ohms) - Resistivity - ' C

INTERPRETATION PRINCIPLES: Electric currents flowing through the

. . . . matrix is assumed to be non-conductive. W a u e n t l v

mB

-pue system. Within the pore fluid,the electric current is conducted via the dissolved salts and more easily at high temperature. ~ o n d u c t i u i + d t b A u i d - i ~ ~ gilinitv and tkmpxrahue. In the formation c o n d s i v i - w e

Laterologs are affected by the borehole mud, the invasion effects of mud filtrate and adjacent beds. Correction charts for all these are published. The Laterolog-3 subject to the Delaware effect below thick resistive formations **,

(anhydrite) causing high resistivities to be recorded for some 80 feet. 41.)

t QUANTITATIVE ANALYSIS :

*I

Resistivity is related to porosity (0) and formation fluid resistivity (Rw) by Archies relation: Ro = (a * Rw)/(Bm)

and can be used to calculate water saturation (Sw) in clean formations by Archies Eq.:- +<# +J 6 - 3

Sw" = (a * Rw)/(am * Rt)

ow

where: Ro Formation resistivity 100% water m Cementation factor, based on pore bearing geometry ranging 1.5 - 2.5

a Archie constant ranging 0.62 - 1.0 n saturation exponent (usually = 2.0) .-

LATEROLOGIFOCUSED ELECTRODEIGUARD LOGS (Continued)

PROBLEMS: Is unreliable if borehole is too resistiveBest suited to conditions where . .

Rt>2.5*Rxo and invasion is < 100 inches. 1-n it i s thafke reliable in he water in^

s l a y s --. are conductive ---..+ ..T----- and may negate use.sf ArcMe:s , . ~ u a ~ A d d i t i o n a l and more complex models/algorithrns are required.

APPLICATIONS: Measuring formation resistivities in seawater or salt saturated muds. Indicating in clean water zones. - Determining formation water properties.

T&e fl Determining hydrocarbon saturations.

(fipqh water or oil based muds). Uses the concept of electrical currents creating magnetic fields and vice-versa.

MEASURES: The conductivity/resistivity of the formation. An electro-magnet in the tool induces a current to flow around the borehole. This current in turn creates a magnetic field the strength of which is dependent on the strength of the current flow. This I

magnetic field is measured by the tool. The data is presented as a formation . . .

resistivity. Tools are configured to readf inv- formation, hence I L D h p induction. EM. medium induction. I I

UNITS: Ohm-meter /meter (Ohms) - Resistivity

INTERPRETATION PRINCIPLES : Electric currents flowing through the formation are conducted through the pore fluids. The matrix is assumed to be non-conductive. Ihe.conductivity of the fomathn is consequen@

. . . . d-hlxdl~tmwnfth d ~ o r e f l l u d e and g e m pore svstem, Within the pore fhid the electric current is conducted via the dissolvedas and

. . . . more easily at high te-ee- -e

. . sa m. In the formation conductivity will be reduced where a more tortuous pore system is present.

CORRECTIONS: Ilr

Skin Effect - in very conductive formations the strong magnetic fields can induce additional current loops that counteract and reduce the main fields. Erroneously high resistivities may result. Most modem tools automatically correct for this. Borehole effects - any conductivity in the borehole fluid will contribute to the measurement. II

The induction tools have poor vertical resolution. Bed thickness corrections are required. d*

Invasion of the formation by borehole fluids will affect the measured resistivities. m

QUANTITATIVE ANALYSIS : I

Resistiklty is related to poros~ty and formation fluid resistivity and can be used to water saturation in clean formations by Archies Eq. See notes for

PROBLEMS: Is unreliable if borehole is too conductive, Rt<2.5*Rxo and invasion is < 100 inches. reliable in the w a ~ ~ d r o c a r b o n inter& - clays are conductive and may negate use

- , more complex models/algorithrns are required. i

Indicating porosities in clean water zones

*

c/qz

.m

9 MICRORESISTIVITY LOG (MLL,PL,ML,MSFL) STATUS: Devised to measure formation resistivities in the flushed zone immediately adjacent

to the borehole. Have very good vertical resolution and good for picking bed boundaries. Unreliable in oil based muds.

MEASURES: The conductivity/resistivity of the formation by emitting an electric current and measuring the strength of the current at a monitoring electrode. The close spacing between the transmitting and monitoring electrodes means a very _shallqv_depthof investigG03-ofonly a few centime&=. Focussing electrodes are used to control - -~ - current shape and reduce mudcake effects. Relies on direct contact between electrode pad and borehole wall.

UNITS : Ohm-meter /meter (Ohms) - Resistivity

INTERPRETATION PRINCIPLES: Electric currents flowing through the formation are conducted through the pore fluids. The matrix is assumed to be non-conductive. The conductivity of the formation is consequently dependent on the conductivity of the pore fluid itself and the volume and geometry of the pore system. Within the pore fluid the electric current is conducted via the dissolved salts and more easily at high temperature. Conductivity of the fluid is therfore dependent on the salinity and temperature. In the formation conductivity will be reduced where a more tortuous pore system is present.

CORRECTIONS : Microresistivity logs are affected by mudcake on the borehole wall.

QUANTITATIVE ANALYSIS: Micro-resistivity is related to porosity (0) and formation fluid resistivity and can be used to calculate flushed zone water saturation (Sxo) in clean formations by Archies Eq.:-

Sxon = (a * Rmf)/(0" * Rxo)

where m Cementation factor, based on pore n saturation exponent (usually 1.8 - geomehy rangmg 1 -5 - 2.5 2.0)

a Archie constant ranging 0.62 - 1 .O Rxo flushed zone resistivity Rmf Mud filtrate resistivity

PROBLEMS: Unreliable if borehole is rugose and pad contact is lost. Tool reads largely mud. Clays are conductive and may negate use of Archie's equations. Additional and more complex models/algorithms are required.

APPLICATIONS: Measuring resistivities in the flushed zone. Indicating porosities in clean water zones. Determining flushed zone water properties. Determining residual hydrocarbon saturations. Identifying open fractures Defining bed boundaries and thicknesses.

ELECTROMAGNETIC PROPAGATION TOOL (EPT) STATUS: Devised to resolve the problems of determining water saturation in reservoirs of low

or variable water salinity. Being a shallow reading tool it is used to investigate saturations in the flushed zone and also pore geometry characteristics. 1

MEASURES: The Propagation time (Tpl) of the formation and the signal Attenuation (EATT) 4

resulting from the transmission of 1.1 GHz microwaves by the tool. UNITS: Tpl - nanosecondslmetre (nslm) @I

EATT - decibelslmetre (dblm)

INTERPRETATION PRINCIPLES: LIII* i The Propagation time measurment responds mainly to the water in the formation, be it J

formation water, filtrate or clay bound water. Depth of investigation is shallow 1 - 6" so reads primarily the flushed zone. The dominant water is likely to be filtrate. In fresh muds Tpl is em

only slightly affected by saline formation water, however where resistivities are below 0.3 ohmms then both Tpl and EATT will increases and become less reliable. Under ideal

I

conditions -- -- - -. - should be a-godind~cator of water-filled poros~ty,Ifihis less .In

hydrocarbon. -

CORRECTIONS: Unaffected by borehole and mudcake less than 0.4" where pad contact is maintained. Readings unreliable where thicker mud cakes exist and borehole rugose. Corrections for water salinity and temperature are required.

QUANTITATIVE ANALYSIS: Three interpretation methods based on linear weight-average equations. Complex Refractive Index method (CRIM), Tpl and Ac methods, and Tpo method. CRIM is an iterative calculation. Tpl & Ac methods: Tpl = PhiEPT*Tpw + (1 - PhiEPT)*Tpma

EATT = PhiEPT*EATTw Tpo method: Tpo = Tpl - (EATT )I3604

PhiEPT = (Tpo - Tprna)/(Tpow - Tpma) In both methods: Sxo = PhiEPTPhi Matrix remonses:

PROBLEMS: Tpl and EATT significantly affected by water salinity where borehole is saline. rL

Loss of pad contact can cause erratic readings. APPLICATIONS: Porosity in water bearing zones.

Sxo calculations in hydrocarbon zones. w

Cementation factor in hydrocarbon zones when another Rxo log is present. . .

m u

I !

Quartz Calcite

T P ~ 4.65 7.5 - 9.2

Dolomite Anhydrite

T P ~ 6.8 6.35

T P ~ 56.0 - 80.0 2.00 - 2.40

Halite Shale

T P ~ I 5.60 - 6.35 5.00 - 25.00

Water Oil

NGT) STATUS: Correlation tool that distinguishes basic contributers to total gamma. U J

defining g. MEASURES: Total number of gamma rays and the energy level of each. Examines the high

energy part of spectra to determine amounts of Potassium 40, Thorium 232 & Uranium 23 8.

UNITS : Total gamma (SGR) in API units, Potassium in %, Thorium and Uranium in ppm.

INTERPRETATION PRINCIPLES: Most widespreadradioactive element in s e d i m e n t . rw-. Thorium and Uranium also common but less extensive. Potassium 40 mainly a- clay minerals. A b s o l u t e l a r e o f t e n s soratlas Th/K, U/K and PEF are cr- aid mineral identification. Thorium & Potassium response better clay indicator then total GR.

)

CORRECTIONS: Travel path of GR's impeded by electrons (Compton scattering). Electron density controls bulk density. Natural GR levels also therfore particulary reduced if impede by high density matter such as steel casing or heavy mud. Corrections required for borehole size, mudweight and casing. d4 "

QUANTITATIVE ANALYSIS: GR responds linearly to changes in radioactive element concentrations:-

e.g. Vclay = (GR - GRmin)/(GRmax - GRmin) Typical mineral response values:

/ Muscovite ; 7.9 - 9.8 1 <0.01 1 I Montmorillonite 1 0.16 1 2.0 - 5.0 1 14 - 24 1

- A

1 I I I I Illite I 4.5 1 1.5 1<2.0 1

PROBLEMS: KC1 mud systems - Potassium in mud and filtrate APPLICATIONS: Well to well correlations.

Quantify claylshale proportions. Grain size indicator Detect-evaluate radioactive minerals.

L

I Biotite K-% 6.7 - 8.3

U-ppm <0.01 Kaolinite

Th-ppm K-% I U-ppm ,

0.42 11.5-3.0 Th-ppm 6 - 1 9

NUCLEAR MAGNETIC RESONANCE (NMRIMRIL) STATUS: Measurement technique used in analyticaVphysica1 chemise, biochemistry and

medicine. Applied in petrophysics to indicate free fluid levels. Heavily marketed as a permeability indicator.

MEASURES: The relaxation time (T2) of hydrogen nucleon (protons & neutrons) that have been re-oriented by an applied magnetic field

UNITS : ms

INTERPRETATION PRINCIPLES: All atomic nuclei containing an odd number of nucleon (protons and neutrons) exhibit an intrinsic angular momentum, behaving like spinning tops. The nuclei are charged and their spinning produces a magnetic field that has a strength and direction (nuclear magnetic momentum). In the absence of an external magnetic field these are randomly oriented. When a uniform magnetic field is applied the nuclei become polarised and aligned to the applied magnetic field. If the external magnetic field is removed the nuclei start to precess again and the frequency of the precession is the product of the magnetic field strength and the nuclear gyromagnetic ratio. This latter property is a physical constant with a unique value for each nuclei. Hydrogen is a commonly occurring nuclei that responds in this manner and only nuclei associated with free fluid are responsive. The logging sonde measures the frequency and relaxation times of the nuclei's precession and provides a free-fluid porosity, signal decay time (T2) and signal-to-noise ratio (SNTR). Radius of investigation reported as approxiamtely 2" (5 cm) and so reads primarily the flushed zone.

CORRECTIONS : No correction charts published. Processing largely by logging contractors.

QUANTITATIVE ANALYSIS: The following general processing can be applied: Free Fluid Index (Porosity) - from signal amplitudes at after a range of polarisation times. Presented as part of standard NMR log display. Permeability - from comparisons of FFI and (DT (total porosity from logs) but only where FFI<(DT. Swirr intervals - by comparing FFI, aT and Resistivity Residual Saturation - using mud spiked with paramagnetic ions that cancel out the signal indicating water (log-inject-log technique)

PROBLEMS: Effects of pore lining waters not fully understood Free fluid index not necessarily same as effective porosity particularly in carbonates. Still considered to require core analysis data for calibration to permeability.

APPLICATIONS: Effective porosity, permeability, saturations in intergranular pore systems.

13 SHEAR WAVE ACOUSTIC LOGGING (DIPOLE TOOLS)

STATUS: Shear wave velocities required for determining geomechanical propeties such as Poisson's Ratio. Data an essential requirement for seismic attribute analysis (e.g AVO). Tools can also acquire compressional, fluid and Stoneley wave velocities.

MEASURES: Shear wave transit time by applying a directional (sideways) pressure in the borehole. Operates at low frequency (< 4 kHz) and measures a sheadflexure wave travelling up the borehole that at low frequencies is the same as the formation shear.

UNITS : uslft, uslm

INTERPRETATION PRINCIPLES: Sound is propagated through the formation by compressional, shear and fluid waves. Shear waves (DTS) travel at intermediate speeds to the compressional (DTC) and fluid waves. Analysis of the full acoustic waveform is required to extract the shear wave transit time this is achieved by various standard processing techniques (e.g. Slowness-timecoherence). The shear wave velocity is a function of the matrix and pore fluid properties and their respective volumes. I&pri.me~applicationjs in d e t e r m ~ n ~ m e c h a n i ~ a 1 ~ p r o , p & r t _ ~ _ ~ . Depth of investigation is estimated at 5 - 12 " for shear waves and 12 - 24" from compressional waves.

CORRECTIONS: Like the sonic log there are no standard corrections to be applied. Borehole compensation can be applied by special processing of the receiver arrays.

QUANTITATIVE ANALYSIS: Used for geomechanical properties:

Poissons Ratio = [0.5 *(DTs/DTc)~ - I] 1 [DTSI DTC)' - 11 Shear Modulus = a * ~b 1 DTS' Bulk Modulus = a * Pb * [ I DTC' - 4/(3 *DTS~)]

where: a - 1.34 * 10" (if Pb in glcc, DT in uslft) -

PROBLEMS: As waveforms are the source of the shear and compressional measurements minimal problems are expected that can be attributable to specific borehole properties.

APPLICATIONS : Seismic attributes analysis Perforation stability and sanding analysis Hydraulic fracture analysis, well bore stability Gas detection, fracture detection, qualitative permeability

Fon~rat~on Evaluation C.*ourse Notes

FORMATION EVALUATION

Course Notes

APPENDIX II

CORE ANALYSIS DATA INFORMATION SHEETS

1 CORE POROSITY i

2 CORE PERMEABILITY

3 FLUID SATURATIONS

4 FORMATION RESISTIVITY FACTOR

5 RESISTIVITY INDEX

1 CORE POROSITY

DEFINITIONS: Porosity Pore space in a rock is void space normally filled with fluids, such as water, oil

or gas. The porosity is the ratio of that total void space to the total bulk volume of the sample.

Total Porosity Reflects the total void space in a rock. Effective Porosity Reflects the total interconnected void space.

UNITS : % (from core analysis reports), or decimal (from log analysis).

MEASUREMENT TECHNIQUES: Sample Preparation: All oil and brine is extracted using solvent extractors, centrifuges, refluxing solvent extractors (Soxhlet, Dean-Stark) or vacuum retorts. Solvent is commonly toluene. The sample is then d ied using humidity-controlled ovens to prevent dehydration and collapse of clays or other hydratable minerals. Fluid Summation: Volume summation of all fluids extracted from a fresh core sample by centifuge or retort methods. Gas Transfer: Compression or expansion of gas into or from the prepared sample using a Boyles Law porosimeter. Can be used in both pore and grain volume determination. Gas Extraction: Vacuum extraction of gas (air) from a prepared sample using Washburn- Bunting Porosimeter Liquid Resaturation: Saturation of a prepared sample with a liquid of known density. Weight increase of sample indicates porosity.

ACCURACY: +I- 0.5 porosity %, if procedures for each technique are correctly followed.

ADDITIONAL MEASUREMENTS: Porosities measured at confining pressures will be more representative of the in-situ rock. Confining pressures should be used that most closely approximate the in-situ stresses. Porosity reductions by 70% may be evident in under-compacted samples.

PROBLEMS: Sample preparation can damage mineral components such as fibrous clays, or remove soluable mineral such as halite. Plug sample porosities may not incorporate secondary porosity in inore sparsely distributed vugs or fractures.

CORE PERMEABILITY

DEFINITIONS: Permeability Measure of the capacity of a porous rock to transmit fluids. Permeability is related to

the pore geometry, that is volume, extent, tortuosity and texture of the pore system. There is commonly a directional bias to permeability that is related to the original deposition of the sediments. Permeability will vary between different fluid types.

Specific Permeability with a single fluid phase in the rock, e.g.air or water. Permeability Effective Permeability of one fluid phase in rock where other fluid phases are also present, e.g. Permeability oil and water. Effective permeabilities will changes as the relative saturations of the

fluid phases changes. Relative Ratio of Effective to Specific permeability and is dimensionless and presented Permeability graphically as a function of saturation.

Darcies Law states: q

where:

UNITS: Darcy, millidarcy (Md).

q k A

CL dpldx

rate of flow (volume per unit time) - cc/sec permeability constant - darcies cross-sectional area - cm2 fluid viscosity - cP hydraulic gradient - atm/cm

One darcy is the permeability that permits a fluid of one centipoise viscosity to flow at a rate of one cu-cm per second through a cross-sectional area of 1 sq.cm when the pressure gradient is one atmosphere per cm.

_ , ;r... One millidarcy is 111000 of a darcy.

/

MEASUREMENT TECHNIQUES: Specific ~ermeabilitv to air is measured by pushing air through a sample contained in a -. The pressure differential between the air entering and air leaving the sample is measured plus the flow rates. From these are computed the permeability to air Ka. .

Horizontal Permeability is measured routinely. In whole core samples two measuements are made, Kmax in the direction of maximum flow, and KgO at 90" to this direction.

Vertical Permeability is measured at requested intervals.

Klinkenberg Permeabilities are equivalent liquid permeabilities derived from permeabilities to gas and corrected for the gas slippage (Klinkenberg) effect. This correction attempts to account for the different flowing characteristics of gas and liquid. Larger corrections are

required in low permeability formations. Corrections will reduce air permeabilities by factors of 0.6 to 0.95.

ACCURACY: +I- 5% of the value in routine analysis.

ADDITIONAL MEASUREMENTS: Permeabilities measured at confining; pressures will be more representative of in-situ conditions. Permeabilities at C.P. may be 20% of the values at surface conditions in under- compacted formations.

PROBLEMS: The drilling and extraction of both cores and particularly core plugs may cause microfracturing,m..Lhe.sa@s. These..,&artlficlallvbilitie~ Sample preparation may damage delicate authigenic minerals, such as fibrous illites. Permeabilities in the samples will not represent those in the formation even under confining pressures.

App-II-Core.DOC - A.E.Stocks - 07/11/02 iii

3 FLUID SATURATIONS J

DEFINITION: Saturations are that proportion of the pore space occupied by a specific fluid. Saturations of gas, oil and water can be measured from d u g s and w w - . They can identify the presence and extent of any hydrocarbon.

UNITS: % (from core analysis), or decimal (from log analysis).

MEASUREMENT TECHNIQUES: Gas saturation by the injection of mercury into the sample. The gas is compressed or goes into solution in the pore liquids. The volume of injected mercury represents the gas volume.

Oil saturation by the distillation of oil from the plug samples. The sample is heated in retorts up to temperatures of 1200°F (650°C). Oil from whole core samples is extracted by vacuum distillation at maximum temperatures of 450°F.

Water saturation by distillation concurrently with oil. Temperatures are controlled to enable clear distinction between pore water and water of crystallisation. Whole core analysis is identical to oil extraction.

Dean-Stark distillation is a solvent refluxing method that directly removes water. The oil is retained in solution, its content is calculated from the measured water content and weight loss of the sample through drying.

ACCURACY: Unspecified, dependent on handling and age of samples.

ADDITIONAL MEASUREMENTS: Analysis of recovered oil samples f ~ r geochemistry.

PROBLEMS: Exposure of the samples for prolonged periods will inevitably reduce fluid levels. Gas and light oils may be particularly reduced.

FORMATION RESISTIVITY FACTOR /'

DEFINITION: - '

. . . i. Electrical currents passing through a formation are conducted primarily through the water in the pore spaces. The conductivity of a formation is influenced by the conductivity of the pore water and the tortuosity or geometry of the pore network.

FRF = Ro / Rw where Ro formation resistivity, 100% water saturated, ohrnms

Rw resistivity of saturating pore water, ohmms

FRF measu~-ments are uscd to ckdixnu- constant 'a' and the cementation factor 'my throughfhe&&i~n&ip :

FRF = a /(Dm

where 0 porosity - fractional

UNITS: None, FRF is a ratio of resistivities. Values range from 1 to imfinity

MEASUREMENT TECHNIQUES: Sample Prevaration: All oil and brine is extracted and the sample dried using humidity- controlled ovens to prevent dehydration and collapse of clays or other hydratable minerals. Sample is then saturated with a prepared bdn-imilay~mposition -- and salinity to the true formation -- w m s .

Resistivities of the saturated samples and the brine solution are measured and the FRF calculated.

ACCURACY: Unspecified, dependent on sample handling and preparation.

ADDITIONAL MEASURMENTS: FRF measurements at overburden -. . pressures. These are likely to be higher than at surface conditions due to reduction in pore space.

PROBLEMS: Coring and plug-extraction induced fractures can produce erroneously low FRF values. Over zealous drying can damage delicate diagenetic minerals, radically alter pore geometry and indicate FRF's that are unrepresentative of the in-situ rock onditions.

Forniatmn E l alu3tin1i Course hotes C ore l>am l ~ i l b r n ~ ~ r i o n Snccl\

5 RESISTIVITY INDEX / DEFINITION: TheX.1. reflects M f f o r m a t l o n resistivity aah3rdrac;arbon. or any non-conductive fl-l-

R.I. = Rt / Ro where Rt true resistivity of the formation, ohmms

Ro resisitivity of formation 100% saturated with water, ohmms R.I. measurements on one sample are used to determine the saturation exponent 'n' of the sample through the relationship:

RI . = l / S w n where Sw water saturation, fractional

UNITS: None, R.I. is a ratio of resistivities. Values range from 1 to infinity.

MEASUREMENT TECHNIQUES: Porous Plate: Desaturation and resisitivity measurement takes place separately. 100% brine saturated samples are placed with one end face in direct capillary contact wpith a porous plate. Gas pressure applied to the remaining surfaces of the sample induces desaturation through the porous plate until capillary equilibrium is reached. Samples are removed from the pressure cell and the resistivity and weight loss measured. The weight reduction is used to compute the saturation level. The process is repeated for a number of increasing gas pressures and saturation levels. Capillam Eauilibrium: 100% brine saturated sample is placed in a pressure cell and subjected to constant hydrostatic stress. Oil is injected at one end and brine displaced at the other end of the sample through a semi-permeable membrane. Measurements are made after capillary equilibrium is reached at a range of pressures. Continuous Iniection: Sample processing is similar to the capillary equilibrium except that oil is injected at a very slow constant rate.

ACCURACY & PROBLEMS: Porous Plate technique is cheap and quick but requires careful sample prepartion and handling. Erroneous measurements may result from grain loss, excess surface brine, or poor capillary and electrical contact. OiVbrine capillary curves can be obtained. Cauillarv Eauilibrium is accurate but slow (6 weeks +). Measurements can be made at net confining pressures. Oilhrine capillary curves are obtained. Continuous Iniection is accurate and fairly rapid (2 weeks). Measurements can be made at confining pressures. As capillary equilibrium is not attained no oilhrine capillary curves can be generated.

-Formation Evaluation

Course Notes

Appendix IV

REFERENCES

ALLAUD, LOUIS, & MARTIN, MAURICE, Schhmberger The History of a Technique. John Wiley, New York, 1977.

ASQUITH, GEORGE, with GIBSON, CHARLES R., Basic Well Log Analysis for Geologists AAPG Publication, Tulsa, Okla., USA, 1982

BATEMAN, RICHARD. Log Quality Control. International Human Resources Development Corporation, 1984

BEVINGTON, P. R., Data Reduction and Error Analysis for the Physical Sciences. Magraw Hill, New York, 1969

DAVIS, JOHN C., Statistics and Data Analysis in Geology John Wiley, 1973

DESBRANDES, ROBERT, Enclycopedia of Well Logging. Graham & Trotman, London, 1985.

DEWAN, JOHN T., Essentials of Open-Hole Log Interpretation. Pemwell Books, Tulsa, Ok., USA, 1983.

DOVETON, JOHN H., Log Analysis of Subsurface Geology, Concepts and Computer Methods John Wiley, New York, 1986

DRESSER ATLAS, Log Review Interpretation Charts

ELLIS, DARWIN V., Well Logging for Earth Scientists Elsevier, 1987

EXLOG, (Editor, Alun Whittaker), Field Geologists Training Guide. Mud Logging, Principles and Interpretations. Formation Evaluation, Geological Procedures. Theory and Evaluation of Formation Pressures, A Pressure Detection Reference Handbook. Coring Operations, Procedures for Sampling and Analysis of Bottomhole and Sidewall Cores. Reider, Dordrecht, 1985

FERTL, W.H., Shaly Sand Analysis in Development Wells SPWLA Transactions, 1975, Paper A

HELANDER, DONALD, Fundamentals of Formation Evaluation. OGCI Publications, Tulsa, USA, 1983.

HILCHIE, DOUGLAS. Old (Pre 1958) Electrical Log Interpretation. Hilchie, Golden, Col., USA, 1979.

HILCHIE, DOUGLAS. Applied Open-Hole Log Interpretation. Hilchie, Golden, Col., USA, 1982.

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