Deterministic Petrophysics

1. Deterministic Petrophysics www.senergyworld.com

2. Log Evaluation Workflow Lithology Clay Volume Estimation Porosity Computation Water Saturation Calculation Fluid Zones Permeability Determination Net Pay / Net Reservoir Quantification Reality check

3. New Well data New Production data New core data Inconsistencies seen in sense checks Fluid samples Problems in 3-D modelling Problems in simulation Log Evaluation Workflow Reasons for iteration • Lithology • Clay Volume Estimation • Porosity Computation • Core calibration • Water Saturation Calculation • Core derived parameters • Comparisons with core • Saturation-height • Fluid Zones • Fluids present • Fluid contacts • FWL • Permeability Determination • Core derived predictors • Net Pay / Net Reservoir Quantification • Reality checks • Uncertainty Analysis Part or Total iterations

4. Log Evaluation Workflow: Reality Checks 1 • Look for consistency: • Between parameters from different data types. • Different data types may not all tell the same story but any conflicts should be explained. • Lithology, hydrocarbon shows and core data should be identified prior to log evaluation. • Lithology and Clay volume: • Compare with clays and other minerals seen in core. • Use core grain density as guide to main matrix material. • Compare with core mineralogy (XRD, thin section). • Porosity • Porosity: Differences or similarity of different log porosities. • Log to core comparison or calibration. • Sense check magnitude of porosity.

5. Log Evaluation Workflow: Reality Checks 2 Log derived water saturation should be compared with: • Capillary pressure curves. • Core fluid saturation measurements (Dean Stark). • DST and WFT samples. • Discrepancies may point to the need for modified interpretation. Log derived permeability should be calibrated to core data. • Compare cumulative log permeability with production log inflow profiles. • Compare permeability-height (KH) from log permeability with KH from well tests. Net Pay and Net Reservoir should be compared to permeability indicators and core if available. Effective formation evaluation is a process of integration of different data types in order to provide a robust interpretation.

6. Deterministic Petrophysics: Lithology & Clay Volume www.senergyworld.com

7. Basic Interpretation Workflow Lithology Interpretation • The Gamma Ray log responds to natural radioactivity in rocks. Contrast between sand and shale. • Exceptions: Feldspathic (potassium feldspars), micaceous, or glauconitic sands will show an atypical, high gamma ray response. Source rock shales can have very high GR values – often a characteristic of the Kimmeridge Clay Formation in the North Sea. • Neutron and Density logs when run together are, by convention, displayed with the curves superimposed in the same log track, on standard scales such that curves overlay in water-bearing limestones. The curves shift according to lithology and porosity. • Some minerals have characteristic D/N responses and cross-plots can be used to determine these. • Calcite, Coal, Salt, Anhydrite, Gypsum etc • The photo-electric curve (PE or PEF) can also be used.

8. Typical Log Responses to Lithology and Gas Density Neutron Sonic Log response Decreases with Increasing Porosity Log response Increases with Increasing Porosity Log response Decreases with Increasing Porosity Reservoir Rock Low High High High Low Low Limestone (Reference) 2.71 g/cc ≈ 0% 47.5 us/ft ≈ 52.5 – 55.5 us/ft Variable with Compaction 2.65 g/cc Sandstone ≈ - 4% 2.83 to 2.87 g/cc ≈ 42.5 us/ft Dolomite ≈ 6 to 8 % Non Reservoir Rock 2.98 g/cc ≈ 50 us/ft Anhydrite ≈ - (1 to 2) % 2.33 g/cc 52 us/ft Gypsum 48 % 2.08 g/cc 67 us/ft Salt 0% ≈ 130 – 175 us/ft Variable with Compaction Wide Range 2.3 – 2.7 g/cc Variable with Clay Density Reads High Increases with Clay Bound Water Shale Hydrocarbon Gas Effect Reads Low Reads Low Reads High

9. Lithology Example 1 Minerals Determined from D/N Cross-plot: Salt Dolomite  Anhydrite 

10. Lithology Example 2 Minerals Determined from D/N Cross-plot: Limestone Claystone-sandstone

11. Clay Volume Determination from Wire-line Logs Clay Volume (Vclay) • The clay content reflects the amount of clay minerals present in a rock. The term ‘SHALE’ normally denotes assemblages of ‘clay grade’ particle sizes which include clay minerals as well as other minerals such as quartz, mica etc. The proportion of clay in ‘shale’ can range from 50 to 100%. Clay volume is estimated to determine: • Shale / Sand ratios. • Shale corrections in porosity determination. • Shale corrections to Sw . • Log facies. • Reservoir Delineation.

12. Clay Volume Determination from Wire-line Logs Commonly used Clay Indicators are: • GR. • SP. • Resistivity (in hydrocarbon-bearing reservoir). • Neutron-Density log Cross Plot. Typically determine Vclay using several alternative methods and use either the minimum or average value of them • Care required: • If radioactive minerals (other than clays) occur in sands VclayGR is an overestimate. • If hydrocarbon type is gas VclayDN is an underestimate. The Vclay from logs should be calibrated or compared with core data where possible: • Shale count observed in core. • Thin section point count data. • XRD data.

13. Clay Volume from Gamma Ray VclayGR Normally shales contain radioactive minerals and sands do not. Sands may contain radioactive minerals e.g. Biotite, Potassium feldspars or Glauconite. Need corroboration with other clay indicators. Select ‘clay’ and ‘clean sand’ lines. A linear relationship is normally assumed (non-linear versions Larinov or Clavier used in FSU for older rocks). Vclay is obtained from the following equation:Where, VclayGR = Clay volume from GR (v/v) GRlog = Log GR (GAPI) GRsand = GR in clean sand (GAPI) GRclay = GR in clay/shale (GAPI)

14. Clay Volume from Gamma Ray: Thin Beds Heterogeneity – Thin Bed Problem In rock beds less than 2 feet thick, log resolution starts to have an impact by being strongly influenced by adjacent beds. Thinly laminated sand-shale sequences can have clean sands, which are not resolved and are interpreted as ‘shaley’ sands or shales. Note: This problem is not limited to shale volume detection and the GR log. Similar effects with respect to non-resolution of thin beds also occur with porosity and resistivity tools.

15. Clay Volume from Gamma Ray – Plot illustrating picking sand and clay GR It is often difficult to decide which shales are characteristic of the clays dispersed in the sands: This will depend on the mode of deposition of sands and shales. Talk to the project geologist to get his insights! Other considerations It is likely that different parameters will be required in different intervals in the well. Take care to note changes of hole diameter or presence of casing. Both will change the attenuation of the GR. Parameters are chosen by one of several methods: By “eyeballing” sand and clay GR. Using sand and clay lines in a depth plot. Note: GRsand <= the smallest Log GRlog and GRclay< largest GRlog . GR Sand Line GR Clay Line

16. Clay Volume from Gamma Ray – Histogram illustrating picking sand and clay GR In some cases to render the process of choosing less subjective or to facilitate fast interpretation in a large number of intervals the parameters may use specified percentile points in histogramsof GR. Typically 5 and 95 percentile values of GR are adopted as GRsand and GRclay respectively.

17. Clay Volume from SP VclaySP Responses in clay and sand – sand line and clay line. Select ‘clean’ and ‘clay’ lines (methods for choosing parameters are essentially the same as for GR). Vclay calculated using the following equation: Where, VclaySP = Clay volume from SP (v/v) SPlog = Log SP (mV) SPsand = SP in clean sand (mV) SPclay = SP in clay/shale (mV)

18. Clay Volume from SP SPsand and SPclay are picked in a similar manner to the GR equivalents Considerations: • SP deflection is suppressed (reduced) in hydrocarbon-bearing sands. • SP deflection varies with Formation Water Salinity changes. • Hence require different parameters in different zones of the well if formation (or mud-fluids) salinity changes. • SP is not effected by non-clay radioactive minerals. • SP has poor vertical resolution – “lazy” response compared with GR.

19. Clay Volume from Neutron-Density VclayDN Typically VClayDN isdetermined using Density-Neutron cross-plots: • Choose appropriate lithology line by observation and hence select clean points. • Choose a clay point as a “SE” point in the data distribution. • Parameters are likely to vary by zone in a given well and between wells. • Clay volume determined based on location of data points in the cross-plot.

20. Clay Volume from Neutron/Density Cross-plot Gas affected data: will lead to underestimate of Vcl from D/N cross-plot unless clean line is adjusted in gas zones. May wish to place the Clay point at a position of greater data density; it should not be at the extreme edge of plotted data. Increasing Vclay Clay Point

21. VClay Comparison of Methods

22. Clay Volume Calculation in IP www.senergyworld.com

23. Clay Volume - GR • GR minimum picked in clean zones. Minimum value in the cleanest zones. • GR max picked in shales. Value picked to give a maximum of about 80% clay in the shale. Note that shales hardly ever have 100% clay. 60-80% normal range. • Can overestimate clay volume due to radioactive minerals in the sands

24. Clay Volume GR • Non linear GR methods have been designed to work under specific conditions; certain ages of rocks or certain formations in certain fields. Usually developed in zones that have radioactive minerals associated with the sands (feldspars, micas, some heavy minerals). • They generally need some sort of calibration to verify their validity.

25. Clay Volume - Neutron • The neutron Vcl nearly always overestimates clay volume and the tools have a non-linear response. It is useful for tight streaks and gas sands where other indicators may overestimate. • Neutron clean is generally left at zero. Anything greater than that you risk underestimating Vcl. • Neutron clay set to calculate 60-80% Vcl in the shale zones. Set to give same sort of results as the VclGR in the shales.

26. Clay Volume - Resistivity • Can work well in hydrocarbon bearing zones. Does not work in shales or wet zones. Since it depends on the deep resistivity there are potential problems of vertical resolution. Needs to be used with care. • Usually used as a last resort when all else fails. • Res clean picked at maximum value in the hydrocarbon interval. • Res clay picked in the shale zones.

27. Clay Volume - SP • The SP quite often has a very lazy shape and does not respond quickly to bed boundaries. Will only work with high salinity contrasts between Rmf and Rw. The example shows a poor SP Vcl indicator and should not be used. • SP will probably need to be base-lined before use • SP response is suppressed by hydrocarbon • SP response is suppressed by thin beds • SP clean picked in thick, clean zones. • SP shale picked in the shales. • Use with great care.

28. Clay Volume - Neutron Density • One of the best clay indicators since the neutron and density tools respond linearly to increasing amounts of clay. The light hydrocarbon effect on the logs will mean an underestimation of Vcl unless this is adjusted for with the clean line. The indicator does not work well in complex carbonates (dolomite and shale can have similar responses). • Clean line and clay point normally picked using cross-plots. Clean line must be adjusted for matrix type (sand, lime) and also hydrocarbon. The hydrocarbon correction is made by changing the slope on the clean matrix line. • The Clay point is normally picked so that the N/D Vcl gives about 60-80% clay in the shales. Above plot shows the picks in the light hydrocarbon zones Note the Active Zones are 2 and 4

29. Clay Volume - Sonic Density • Can work well as a clay indicator, but generally is similar to the N/D Vcl. • Clean line is adjusted to fit the data in the clean zones. Hydrocarbon effects will be smaller than the N/D Vcl since gas has the effect of increasing both the sonic and density porosity. • Clay point is adjusted to give about 60-80% clay in the shales.

30. Clay Volume - Sonic Neutron • The S/N Vcl is generally not very effective since the response to clay is to increase both the neutron and sonic readings. However can be useful in situations where nothing else works. • Clean line and clay point are adjusted similar to the other double clay indicators.

31. Clay Volume

32. Deterministic Petrophysics:Porosity www.senergyworld.com

33. Basic Petrophysical Properties: Porosity Defined as the ratio of Void space to Bulk Volume of the rock: Porosity is a measure of the space available for storageof fluids: • Where, Ø = Porosity Vp = Pore Volume Vt = Total Volume Expressed as Percentage (%) or Decimal (v/v)

34. Basic Petrophysical Properties: Porosity Types by mode of formation Types of porosity Primary – originating as the sands were laid down Inter-granular or inter-particle Intra-granular Inter-crystalline Bedding planes Secondary – formed by various processes after sands were formed Solution porosity or Dissolution Dolomitisation Fractures Vugs Shale Porosity Secondary porosity is generally far more important in carbonates than sandstones For clean sandstones and carbonates, Porosity can readily be derived from logs For complex formations porosity data from core is required to calibrate the log response Fracture Inter-granular or inter-crystalline pores Micropores Vugs

35. Basic Petrophysical Properties: Porosity Types Total versus Effective Total Porosity Øt Ratio of all pore space (and clay structural water seen by some tools) to bulk volume. Includes all pores regardless of the degree of connectivity or pore size. Includes water in clay structure. Effective Porosity Øe Ratio of interconnected pore volume to the bulk volume.

36. Basic Petrophysical Properties: Volumes and Porosity Porosity Definitions Absolute or Total Porosity Øt Matrix Effective Porosity Øe VSHALE Clay Layers Clay surfaces & Interlayers Small Pores Quartz Large Pores Isolated Pores Hydration or Bound Water Capillary Water Hydrocarbon Pore Volume Structural Water Irreducible or Immobile Water Usually assumed negligable in Clastics May be significant in Carbonates Often assumed negligable in Carbonates Usually significant in Clastics

37. Basic Petrophysical Properties: Porosity Ranges Note: Theoretical maximum inter-granular porosity for cubic-packed spherical grains is 47.6%

38. Basic Petrophysical Properties: Porosity measurements Core porosity • Measure two of: pore volume, grain volume and bulk volume of core plug and ratio them. • Direct measurement but: • Measure Øt or Øe (or something in between) depending on pore types present, clay content and method of cleaning and drying. • Measured under laboratory conditions rather than reservoir stress. Require correction to reservoir conditions for comparison with or calibration of log porosity. Log Porosity • Sonic, Density, Density/Neutron, NMR. • Porosities measured differ. • No log measures porosity directly. • Calibrate to core when possible.

39. Basic Petrophysical Properties: Porosity and measuring techniques Log and core Porosity Measurements Total Porosity, Sonic Log Total Porosity, Neutron Log Total Porosity, Density Log Absolute or Total Porosity ** Oven-dried Core Porosity Matrix ** Humidity-dried Core Porosity VSHALE Clay Layers Clay surfaces & Interlayers Small Pores Quartz Large Pores Isolated Pores Hydration or Bound Water Capillary Water Hydrocarbon Pore Volume Structural Water Irreducible or Immobile Water ** If sample is completely disaggregated (after Eslinger and Pevear, 1988)

40. Which Porosity Log Should I Use ? Where possible all porosities should be calibrated to core data. Density porosity Ød is preferred provided that: • The well is in gauge. • The matrix density is known and reasonably uniform. • The reservoir fluids are liquids. Sonic porosity Øs (using RHG equation) is used as an alternative to Ød if: • The borehole is washed out or DRHO>0.05 gm/cc. Density/Neutron porosity Ødn is substituted for Ød if: • Gas is present in the formation. • The lithology is unknown or variable (exploration wells) NMR porosity ØNMR is of similar quality to Ød except in some carbonates and in gas zones. It is a specialised log used most often to address complex porosity issues: • Measure effective porosity in complex pore structures. In many instances there will only be one porosity log available in which case the best interpretation possible must be made with that available: • Early exploration wells using single detector neutron or sonic log.

41. Porosity from Sonic -Wyllie Time Average (WTA) Equation For much of the depth interval drilled in any well, the sonic log is likely to be the only means of deriving porosity. There are two equations (Wyllie time average and Raymer-Hunt-Gardner) In the Wyllie Equation, or the ‘Time Average’ equation, porosity is assumed to be a linear function of the interval transit time: Where, Øs = Sonic porosity (v/v) tlog = Interval transit-time measured by the sonic log (μsec/ft) tma = Matrix transit-time (μsec/ft) tfl = Transit-time of fluid contained in the formation (μsec/ft) Bcp = ‘Compaction factor’ determined by comparison with core or regional experience. Often assumed to be 1. 41

42. Porosity from Sonic: Comparison of WTA & RHG equation with Porosity Experience with WTA showed that it overestimated porosity at high transit times or in unconsolidated formations. Comparison of core and other log porosities with WTA confirmed: Overestimation of ØS at high transit times. Underestimates ØS at intermediate transit times RHG derived an alternative equation for ØSthat better fits porosity over the whole range of magnitude. Comparison of WTA and RHG equations with Field Data. After Porosity Reference1.

43. Porosity from Sonic- Raymer-Hunt-Gardner (RHG) Equation The Raymer-Hunt-Gardner relationship is an empirically-based Porosity solution using the comparison of sonic log transit times, coreporosities and porosities from other logs. It provides more realistic values than the Wyllie equation particularly at high porosities and in poorly consolidated formations.In simplified form it is: Where, Øs = Sonic porosity (v/v) tlog = Interval transit-time measured by the sonic log (μsec/ft) tma = Matrix transit time (μsec/ft) x = A lithology dependant constant This equation has the advantage that it does not require tfl as input.

44. Porosity from Density The Density measurement is the most reliable means of deriving porosity from logs given: Good hole conditions Fairly constant grain density Density porosity is calculated using: Where, Ød = Density porosity (v/v) b = Log bulk-density (gm/cc) ma = Matrix density (Sandstone 2.65, Limestone 2.71, Dolomite 2.88 gm/cc) fl = Apparent fluid density (Approximate using: Fresh water-based mud 1gm/cc, oil-based mud 0.85 gm/cc)

45. Neutron porosity is seldom used independently: However neutron porosity may be the only porosity log in some early wells. Usually used in combination with the density log. Weighted average porosity: Oil/water Gas Density-Neutron Cross-plot porosity Density-Neutron combined porosity is particularly useful in gas zones where Ød and Øs tend to be overestimates unless core is available to calibrate them. Porosity from Density-Neutron Combination If neutron was logged in Limestone units convert to actual matrix before use in weighted average Ønd

46. Porosity and Clay Volume Estimation from Density / Neutron Cross-plot in shaly sands Porosity-Clay volume D/N Overlay construction: Establish the (Wet) Clay point in the “SE” of Density-Neutron Cross-plotted data. Matrix line. Defined by a line joining the matrix point (porosity 0) to the fluid (water) point (porosity of 1). Scaled linearly in porosity. Matrix-Clay line. Defined by Matrix and (Wet) Clay points. Effective porosity 0 along this line. Scaled linearly in clay volume. Water Point Porosity Clay Volume 46

47. Effective Porosity Effective porosity: Where, Øe = Effective porosity (v/v) Øt = Total porosity (v/v) Øtcl = Total porosity of clay (v/v) Vcl = clay volume (v/v)

48. The Borehole Environment Rmc Ro Rxo Sxo Sw Rm Rt Ri Si Invaded Zone Non-invaded Transition Zone Flushed Zone Mudcake Borehole Invasion The depth of invasion is controlled by the formation porosity and permeability and the mud characteristics (pressure differential between mud column and formation, viscosity and fluid loss). High permeability beds generally tend to show less invasion, due to fast mudcake build-up, while lower permeability beds tend to have more invasion. As mud invasion is a volume system, the depth of invasion in high porosity beds is shallow and correspondingly the depth of invasion in low porosity beds is deep. The effect of invasion will decrease away from the wellbore so that there is a ‘transition zone’ developed, from mud filtrate at the well, through a zone of mixed filtrate and formation fluid, to the ‘non-invaded zone’ where original formation fluids are found.

49. SECTION VIEW PLAN VIEW Ri Si Rmc R = Resistivity S = saturation m = mud mc = mudcake xo = flushed zone i = invaded zone t = uninvaded zone w = formation water o = 100% water saturated, uninvaded zone Ro Hmc Rxo Sxo Sw Rm Rt Invaded Zone Non-invaded Transition Zone Flushed Zone Mudcake Borehole The Borehole Environment

50. (a) Water-bearing formation (b) Oil-bearing formation Mud Cake Mud Cake FORMATION WATER MUD FILTRATE MUD FILTRATE MUD FILTRATE FORMATION WATER Well Bore Well Bore OIL FORMATION WATER Flushed Zone Flushed Zone Transition Zone Transition Zone Non-Invaded Zone Non-Invaded Zone Mud Cake OIL FILTRATE FORMATION WATER OIL FILTRATE Well Bore Well Bore Mud Cake OIL FORMATION WATER Flushed Zone Flushed Zone Transition Zone Transition Zone Non-Invaded Zone Non-Invaded Zone Mud Filtrate Invasion Water-Based Mud System Oil-Based Mud System (c) Water-bearing formation (d) Oil-bearing formation