Well Log Fundamentals

Fundamentals of Log Interpretation - I

SPONTANEOUS POTENTIAL LOGS GAMMA RAY LOGS

Log Characteristics • The difference between the electric potential of a moveable electrode in the borehole and the electric potential of a fixed surface electrode is measured as a function of depth

Sand line

Shale line

•

Opposite shales, the SP curve is usually a more-or-less straight line – called a shale baseline

•

Opposite permeable formations (sands), excursions from the shale base line are observed. Opposite thick permeable beds, the excursions reach a constant value – called a sand line

•

The deflections on a SP log may be either to the left (negative) or to the right (positive), depending on the relative salinity of the mud filtrate and the formation waters. if, water salinity > mud filtrate salinity, deflection to left if, water salinity < mud filtrate salinity, right deflection

•

SP log cannot be recorded in holes filled with non-conductive (oil based) muds. If resistivities of mud filtrate and formation water is similar, SP deflections will be minimal and featureless

Basic Principle • SP currents caused by electromotive forces in the formations: − Electrochemical component − Electrokinetic component • Two electrochemical effects I)

Electric current

Saline mud filtrate

SHALE SAND

Layered clay structure and charges on the layers favor the transport of Na+ ions from the filtrate. Movement of charged ions electric current The electrical potential that induces the flow of cations through shale is called membrane potential II) At the edge of the invaded zone: Electric current Saline mud filtrate

SHALE SAND

More saline formation water

Since formation water is more saline than mud filtrate, transport of Cl- ions from formation water to mud filtrate, current in opposite direction to flow of anions Electric potential driving this current is liquid junction potential

Basic Principles • Electrochemical forces: − Membrane Potential >> Liquid junction potential − If permeable zone contains some shales or dispersed clay, total electrochemical emf reduced since these shales/clays produce an electrochemical membrane of opposite polarity to that of the adjacent shale bed

• Electrokinetic Potential: Induced when an electrolyte flows through a permeable, non-metallic porous medium − Magnitude of electrokinetic potential depends on the differential pressure producing the flow and the resistivity of the electrolyte − Electrokinetic potential (Eek) is produced by the flow of mud filtrate through the mudcake found opposite the permeable zones. Low permeability of mudcake high differential pressure higher Eek − Electrokinetic potential also produced across the shale (low permeability) − Net electrokinetic potential contribution to the SP reading is the difference between the contributions of the mudcake and that of the shale Direction of electrokinetic current Mud cake

SHALE SAND

SP Principles

Current direction in above figure corresponds to formation water being more saline than mud filtrate Potential adjacent to permeable sand bed negative compared to potential adjacent the shale – Negative (left) deflection of SP curve If formation water is fresh (less saline), opposite direction of current flow – SP deflection to the right opposite permeable bed SP currents flow through four different zones/media: − borehole − invaded zone − uninvaded portion of the permeable zone − shales SP measurements are of the potential drop in the borehole only – a small portion of the total potential drop If the current loop could be prevented from being complete – potential drop in the borehole (mud) will be equal to the total emf SP under such idealized condition is called static SP (SSP)

SP characteristics • Small cross-sectional area of the borehole available to flow of current compared to the formation implies that maximum potential drop occurs across the borehole SP deflection opposite thick permeable sands do approach SSP value • SSP value can be determined from SP curve if there exist clean, thick, water bearing beds in the given horizon. A line is drawn through the negative maxima opposite the permeable bed. Another line is drawn through the SP opposite intervening shale beds. The difference in mV is the SSP Shape of the SP curve

If formation resistivity and the mud resistivity are comparable , then the resultant SP curves yield a much crisper definition of the bed boundaries than when Rt = 21 * Rm. Why?

SP Baseline Shift Baseline shift occurs whenever formation waters of different salinity are separated by a shale bed that is not a perfect cationic membrane.

Shale base line does not return to the earlier base line

Gamma Ray Logs • Measure of natural radioactivity of the formations • Gamma rays are bursts of high-energy electromagnetic waves spontaneously emitted by radioactive material (potassium, uranium and thorium) in rocks • Radioactive material predominantly in shales. Why? o The lattice structure of clay materials has holes (gaps) that are occupied by radioactive material o Shales have very low permeabilities – little possibility of radioactive material getting washed out o Clays have igneous origin – more likely to be radioactive o Sandstones have quartz origin that have very tight lattice and cannot accommodate radioactive material • What comprises a gamma-ray logging device? o A detector to measure gamma ray radiation emanating from near the borehole o Gamma ray propagation through porous media is a statistical phenomena - measurement may fluctuate over time o Average gamma ray intensity over a time window (‘time constant’ of the tool) is recorded • The propagation of γ-rays through reservoir rocks is controlled by the density of the rock – higher the density of rock, lower will be the measured γ-ray count

Gamma Ray Characteristics • Resolution of the gamma-ray tool is generally: o 6 inches to 2 ft. vertically o 6 inches to 1 ft. horizontally • Resolution is governed by: o the time constant of the tool : if time constant is too large, the γ-ray emitted by thinner shale features in the reservoir will be averaged out o Logging speed : slower speed more time to establish meaningful statistical counts – good record • Gamma-ray useful for establishing shale beds: o Can be used in cased/uncased holes o Can be used in holes with any type of drilling fluid • Bed boundary picked midway between maximum and minimum deflection opposite a shale feature • Gamma-ray can also be used to compute volume proportion of shale at any vertical location along the well: GR − GRclean sand o Calculate γ-ray index: GRI = GRshale − GRclean sand o Read volume of shale Vsh from chart o 3 curves in the chart: 45o line – upper bound regardless of formation, line 2 – older (pre-tertiary rocks – more dense), line 3 – younger (tertiary rocks – less dense)

Vsh correlation (empirical – Dresser Atlas)

POROSITY LOGS

Neutron Log • Delineates porous formation and determines their porosity • Respond primarily to the amount of hydrogen in the formation (predominantly in water and liquid hydrocarbons) reflects the amount of liquid-filled φ Tool cannot distinguish between oil and water • Gas zones are primarily detected by comparing neutron logs to other logs e.g. density logs • Neutrons (neutral particles – mass nearly equal to Hydrogen atom) emitted into formation collide with nuclei of formation material reduction in energy • Maximum reduction in energy when neutron collides with particle of same mass (hydrogen nucleus) • After few collisions, velocity of neutrons slow sufficiently to diffuse randomly in the media and are captured by nuclei of atoms such as Cl, H or Si • Capturing nucleus is excited and emits a burst of highenergy γ-ray of capture : tool measures γ-ray and/or counts the neutrons impinging a detector • When H-conc. in area around well bore is high (high hydrogen index), most neutrons captured in immediate vicinity of well neutron count rate decreases

Neutron Logging Tools • SNP – Sidewall Neutron Porosity Log
Neutron source and detector mounted on a skid that is pressed against the hole wall
Detector is shielded - only electrons with energies above certain (epithermal) threshold are detected
minimizes spurious effects due to strong thermal neutron absorbers (e.g. Cl and Bo) in formation waters


Provides good measurement in open holes – liquid-filled or empty

• CNL – Compensated neutron Log
Mandrel-type tool – tool in conjunction with other types of logging tools
Dual- thermal neutron detectors – ratio of recordings at the two detectors used to compute neutron porosity index
Long source-detectors spacing gives greater depth of investigation
Effect of borehole parameters reduced by taking ratio of two readings
Can be used in liquid –filled cased or uncased holes but not air-filled holes
Since thermal-neutrons are captured – tools affected by presence of elements having thermal neutron capture properties such as shales
Neutron tools tend to read high porosity in shales – due to bonded-water in clay. If gas present in shale, neutron count is high – offset by low count due to shale neutron capture effect of gas is masked on the log readings

Neutron-Log Corrections

• Correction for varying borehole radius • Salinity effects (mud and formation fluid) : Chlorine an excellent neutron absorber – reduction in neutron count – higher φ • High apparent porosity in shale due to bonded water • Mud and mudcake have high hydrogen count – apparent high neutron porosity • Porosity reading affected by lithology – SNP/CNL scaled for limestone matrix – correction for other matrix using figure

Density Log

• Gamma rays emitted by a source in the tool. These γ-rays interact with atoms in formation material and dislodge an electron – Compton scattering • G-ray diminishes to lower energy level and is recorded by a detector • Extent of Compton-scattering (hence of energy of impinging g-ray) related to electron density in formation • Electron density is directly related to material bulk density (i.e. combined density of rock matrix, fluids in pore spaces)

Skid-mounted tool

Density tool corrections 1. Mud cake correction – Ideally count rate in both short and long-spaced detectors should be same in absence of mud-cake - however mud-cake invariably present

formation density constant, but thicknessmud cake varied

mud cake density constant but thicknessmudcake and formation density varied Density log corrections Mud-cake correction charts

mud-cake density and thickness varied, formation density constant

2. Lost pad contact: Results in density reading to be affected by borehole fluids. If problem is severe: significant deviations from average readings in a zone.

Porosity from Density Logs • Reading from density log affected by matrix + fluids (volume of pore spaces) i.e. ρdensity=ρfluid * φ + ρmatrix * (1-φ) or

ρ matrix − ρ density φ= ρ matrix − ρ fluid

ρmatrix commonly: 2.65 - for sands and limestones 2.68 - “limey” sands or “sandy limes” 2.71 - limestones 2.87 – dolomites ρfluid commonly: 1.1 gm/cc – highly saline water 1.0 gm/cc – fresh water >1.0 gm/cc – oil based mud φtrue Empirical corrections: Oil zones :

φcorr = 0.9 × φdensity

Gas zones :

φcorr = 0.7 × φdensity

POROSITY CROSSPLOTS

Presence of Gas • ρb (bulk density) read to be too low

φdens too high

• φneutron reads low (provided no shale present)

“Football” effect seen on the log Detection of gas zone difficult in shale zones

Lithology determination Neutron- density cross plot for freshwater mud/formation water (ρwater = 1.0 gm/cc)

Note: The porosity on both axes is limestone porosity. If φdensity is computed in sandstone, calculate: ρbulk = ρ sand − matrix − φdensity ⋅ ρ sand − matrix − ρ fluid ρ − ρbulk Calculate: φlime − density = lime − matrix ρ lime − matrix − ρ fluid

(

)

Lithology determination

Lithology Determination

Lithology Determination

Mixture of matrix material (sandstone + limestone, limestone + dolomite or sandstone + dolomite)

Presence of Gas

• Low neutron porosity reading and high density porosity reading • Connect equal porosity tie lines on sandstone and limestone curves and extend to porosity read value – gives approximate φ for the formation

Evidence of shale

• Shale point established using readings on nearby shale bed • Plotting points corresponding to values within a formation of interest, we might observe a trend or trajectory: o If trajectory resembles A – structural shale o Trajectory B – laminated shale o Trajectory C – dispersed shale

o Recall- structural shale implies little correction to φdens, dispersed shale – maximum correction, laminated – less correction

RESISTIVITY LOGS

Basic Concepts • Ability of formation to conduct current is directly related to the amount of water in formation • Rock grain material have very low conductivity, hence measured conductivity (resistivity) is a function of water saturation and porosity • Resistivity is related to resistance through: A R =r× R – resistivity ohm-m L • Formation resistivities range from 0.2 – 1000 ohm-m • Current flow in formation through water made conductive by salts (Na+, Cl- ions) • Resistance due to a cube full of water: L rw = Rw × A Replacing water with porous material 100% saturated with water, resistance measured is: L' ro = Rw × (neglecting resistivity of rock material) A' L' > L due to tortuosity, A' < A reduced by the effective pore volume available for current flow.

Basic Concepts (cont’d) ro is a measure of the formation rw characteristics r R • Taking L = 1 m and A = 1 m2, o = o and formation rw Rw R resistivity factor , F = o Rw • Since Ro is different from Rw because of tortuosity (related to cementation and rock texture) and reduction in area (due to porosity), formation resistivity factor F: a F= m (Archie’s • The ratio

φ

formula) a – rock texture; m – cementation index

• Calibration results: F= F=

0.81

φ

2

1

φ

2

in sands in carbonates

• Humble formula: F=

0.62

φ

2.15

sandstone

Saturation determination • In formation containing oil or gas (insulators), resistivity is a function of F, Rw and water saturation Sw (fraction of pore space occupied by water): R S w2 = o Archie’s formula Rt Resistivity of formation

• Ro, resistivity corresponding to formation 100% saturated with water is rarely measured directly. Knowing porosity from sonic and/or neutron log: F ⋅ Rw a ⋅ φ − m ⋅ Rw 2 Sw = = Rt Rt Rt measured by resistivity log, Rw from oil field water catalog / water compositional analysis / SP log • The Rwa log is computed as Rt F where Rt is from a deep-investigation resistivity log and F is calculated from a porosity log reading. Rwa =

For clean water bearing zones, Rt = Ro = FRw, which implies that Rwa = Rw

If a consistent low value is observed in the Rwa log for several potential reservoir zones, then that low value of Rwa is probably the formation water resistivity Rw. Water resistivity from SP logs Recall SP is natural potential induced due to salt concentration difference between formation water and mud filtrate: a SP = K ⋅ log w amf aw is the chemical activation potential of formation water, amf of filtrate and K is a solution constant (function of Tformation) Expressed in resistivity terms: SP = −(60 + 0.133T ) ⋅ log

Rwe Rmfe

T – formation temperature in oF Formation waters rarely composed of pure NaCl, other ions such as Ca+ and Mg+ are present. Similarly, mud filtrate may sometimes contain potassium, calcium or magnesium Rmf measured must be converted to Rmfe using chart in following page Rw SP = − K ⋅ log e Rmf e K = -(60 + 0.133T)

Rwe =

Rmf e −

10

SP K

Formation water resistivity Read SP corresponding to clean water bearing layer. Calculate Rwe, calculate Rw from chart or from:

Rw = −0.58 + 10(0.69 Rwe − 0.24) if Rwe @ 75oF > 0.12 ohm-m Rw =

77 Rwe + 5 146 − 377 Rwe

otherwise

Resistivity Tools - Normal Device

• Current of constant intensity between electrodes A & B. • Equipotential lines due to current are spheres • Difference in potential between M and N (located an infinite distance away) measured • Potential recorded is related to resistivity of formation • Distance AM – spacing of tool (16 in., 64 in etc.) • Deepest point where measurement is made corresponds to point O (zero point - midway between A and M)

Resistivity Tools - Lateral device

• Constant current between A and B • Potential difference between two points M and N on two concentric spherical surfaces centered on A measured • Zero point is at O midway between M and N • Spacing of tool is AO (18 ft. 8in lateral etc.) • In general for both normal and lateral tool, longer the spacing, deeper the radius of investigation

Normal and Lateral Curves

• Normal curve opposite resistive formation – apparent bed thickness less than true by distance equal to tool spacing – thick bed Rt equal to true resistivity (no invasion) • Thin resistive bed – curve reversed: Rt-app Rsh. Two spurs observed – distance between spurs equal to true bed thickness + tool spacing

• Thick bed less resistive than surrounding formation – apparent thickness greater than true thickness by amount equal to tool spacing

Effect of bed thickness on lateral device

Formation more resistive than surrounding

Formation less resistive than surrounding

• A minimum bed thickness is needed to obtain plateau reading uninfluenced by surrounding formation • In very thin beds – strong peak corresponding to resistive bed, “blind zone” below the bed and a spurious reflection peak • Curves in all cases not symmetrical • When formation less resistive than surrounding, anomaly extends below bed for distance > tool spacing

Resistivity Tools

Focussed devices (Laterologs, SFL)

Useful when: − Rt/Rm ratios are large − Beds show large resistivity contrasts and/or are thin − Drilling muds are salty and conductive

• Comprises of a center electrode A0, three pairs of electrodes: M1M2, M1’M2’ and A1A2 • Each electrode pair symmetrically located with respect to A0 and connected to each other (shortcircuited) • Constant current emitted from A0. Adjustable bucking current emitted in A1A2. Current intensity adjusted until same potential measured at the monitoring pairs M1M2 and M1’M2’ • M1-M2 and M1’- M2’ are at same potential (since they are shorted). M1-M1’ are at same potential. No current flowing in hole between monitoring pairs current from A0 flows as a sheet into the formation

• Potential drop between M1M2 (or M1’M2’) and ground electrode recorded

Effect of bed thickness

• Thickness of current sheet is approx. 32 in when length A1A2 is 80 in. (Laterolog 7) • If bed thickness is greater than 32 in. – adjacent bed effects eliminated • If bed thickness < 32 in. current divided between bed and adjacent formation – apparent resistivity reading increased if Rsh > Rbed and lowered if Rsh < Rbed • In general, even if Rt/Rm > 5000, beds can be clearly delineated

Induction Tools • Measures conductance (inverse of resistance) of the formation • An alternating current is applied to the insulated transmitter coil, produces an alternating electromagnetic field • Magnetic field penetrates formation and induces current • Formation current induces secondary magnetic field around receiver coil • Secondary field converted to current whose intensity is proportional to conductivity of formation

• Tool response can be visualized as sum of all formation loops (mud + invaded zone + virgin zone + surrounding formation) Total induced current on receiver coil can be written as:

C I = Gm Cm + G xoC xo + Gt Ct + Gs C s G’s are geometric factors and Gm + G xo + Gt + Gs

=1

Induction tools

• Volume of space (mud, invaded zone etc..) defined only by its geometry relative to the tool and this can be used to prepare correction charts for invasion, mud etc..

• In dual induction tool– a shallow curve measures flushed zone resistivity, a medium zone measures invaded zone and a deep zone reflects Rt

• Induction log ideal for air-drilled holes or holes drilled with non-conducting mud

Induction log corrections Borehole diameter correction

Induction log corrections Bed thickness correction

Porosity- Resistivity Crossplot (Pickett plot) S nw =

Ro F ⋅ Rw a ⋅ Rw = = m Rt Rt φ ⋅ Rt

Taking logarithm of above expression: log Rt = − m log φ + log(a ⋅ Rw ) − n ⋅ log S w If we have a formation with constant lithology (texture) index “a” and Rw, then in regions with constant Sw :

log Rt = − m log φ + Const. i.e. a log-log plot of Rt versus φ (or vice-versa) will be a straight line, with slope = − m (cementation factor).

Log Rt Slope = m

Constant Sw

Log φ

If Sw = 100%, then log Rt = − m log φ + log(a ⋅ Rw ) Another straight line, parallel to other Sw lines. At φ = 100%, log Rt = log(a ⋅ Rw ) Therefore: Log Rt Sw=100% aRw Log φ

φ=100%

Resistivity-Porosity Cross plots

When it is not known that the resistivity values correspond to 100% water saturation, but aRw is known, using estimate for m and plotting a point (Rt = aRw, φ = 100%), draw the line for Sw=100% Sw=100% Points with unknown Sw

Log Rt Assumed m

(Rt=aRw, φ=100%) Log φ

φ=100%

Adjusting log values for presence of shale φ D corr = φ D − V sh ⋅ φ DSh

Log reading in a shale zone

φ N corr = φ N − Vsh ⋅ φ N Sh

Compute corrected porosity as: φ=

φ Dcorr + φ N corr 2

Then calculate the corrected saturation as: S w = S w Archies −

This is called Fertl’s correction

Log reading in a shale zone

VSh ⋅ Rw 0.4 ⋅ φ ⋅ Rsh