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Hydrocarbon Correction for Neutrondensity log. Respond of neutron and formation density log in HC bearing. How to correct them? Hydrocarbon Correction for Neutrondensity log. Respond of neutron and formation density log in HC bearing. How to correct them? Hydrocarbon Correction for Neutrondensity log. Respond of neutron and formation density log in HC bearing. How to correct them?
RESPONSE OF NEUTRON AND FORMATION DENSITY LOGS I N HYDROCARBON BEARING FORMATIONS by R GAYMARD and A POUPON SPE Schlumberger - P a r i s trons before they have reached t h e thermal l e v e l (Neutron-Epithermal Neutron tool) For all tools, the slowing down of t h e fast neutrons by hydrogen nuclei is t h e predominant phenomenon, and t h e reading, for given hole conditions, depends mostly on t h e hydrogen index of the formation, proportional t o the quantity of hydrogen per unit volume of formation near the bore hole EDITOR’S NOTE: In this interesting paper the authors consider the effect of residual hydrocarbons on the res p o n s e of the Neutron a n d Formation Density logs I t should be o f interest to those working with t h e s e porosity tools P o s s i b l e applications a r e included for both shaly formations o r complex lithologies In clean water bearing formations, the hydrogen is found in the water only, and with a concentration which is practically independent from the combined effects of temperature and pressure; in t h e s e conditions t h e Neutron reading is directly related to porosity Hydrocarbons, like water, contain hydrogen, but a t variable concentrations which depend mostly on the density of the hydrocarbons in situ For some oils, the hydrogen concentration will be practically the same a s in water; but g a s and light oil have substantially lower hydrogen concentrations As a result the presence of gas, or light oil, in t h e volume of formation near the bore hole, is likely to have a substantial effect on the Neutron reading ABSTRACT I t is usually assumed that, in oil bearing formations, the Neutron and Formation Density logs are not significantly affected by the residual oil in the invaded zone and that they respond as if t h e volume investigated was entirely filled with mud filtrate However when porosities a r e fairly high, t h e effect of t h i s residual oil is not always negligible, particularly if the oil is light Computations have been made t o evaluate t h i s effect Formulae have been developed for clean oil or g a s bearing formations T h e s e formulae permit a more accurate evaluation of the porosity Some of the formulae may a l s o have application in the cases of shaly formations and of complex lithologies Let If the Neutron log is calibrated in fresh water bearing formations, we can write: EFFECT OF HYDROCARBONS ON THE NEUTRON LOG Neutron log porosity = In Neutron logging, a source emits fast neutrons into the formation T h e s e neutrons a r e slowed down through collisions, mostly with hydrogen nuclei of t h e surrounding medium, and after reaching the so-called thermal level of energy, a r e absorbed by nuclei of the formation, usually hydrogen or chlorine nuclei; e a c h capture of a thermal neutron is followed by t h e emission of gammarays of capture A detector, a t some distance from the neutron source, measures either t h e gamma-rays of capture (Neutron-Gamma type of tool) or the thermal neutrons (Neutron-Thermal Neutron tool) or the neuTHE L O G A N A L Y S T Srh : residual hydrocarbon saturation in invaded zone = : hydrogen index of the hydrocarbons : hydrogen index of t h e mud filtrate + [ a s , h + p (1 - S,, ) ] (1) T h e hydrogen index of fresh water is 1, by definition; the hydrogen index of a sodium chloride solution i s somewhat smaller than It will be assumed in t h e following that the Neutron log is calibrated through cross-plots Neutron-Formation Density or Neutron-Resistivity in water bearing intervals; then one can write: N a = $ [pS,h + - s,,] (2) EFFECT O F HYDROCARBONS ON THE FORMATION DENSITY LOG T h e r a t h e r large departure from which a p p e a r s for o i l and water i s d u e t o t h e p r e s e n c e of hydrogen, t h e C of which is almost e q u a l to Gamma rays of fairly high energy l e v e l a r e emitted by a radioactive s o u r c e T h e i r intensity i s gradually attenuated through c o l l i s i o n s with t h e e l e c t r o n s in t h e formation (Compton effect) T h e Schlumberger Formation Density log i s b a s e d on t h e measurement of the gamma ray decayed intensity a t a given d i s t a n c e from t h e source To c o p e with t h i s problem t h e tool r e s p o n s e is calibrated in c l e a n fresh water bearing limestones with porosities ranging from z e r o t o 40%; in fresh water bearing dolomites or s a n d s t o n e s , t h e error resulting from t h i s calibration is very s m a l l , and entirely negligidle F o r fresh water bearing limestone t h e standard formula relating density to porosity c a n b e written both for true density and for electronic density: As t h e Compton effect i s proportional to the number of e l e c t r o n s per unit volume and as, in first approximation, t h e number of e l e c t r o n s per unit volume i s proportional t o t h e d e n s i t y of t h e formation, i t i s c l e a r that t h e log responds t o t h e density of t h e formation Actually t h e number of e l e c t r o n s per unit volume i s not exactly proportional to t h e density In t h e case of an element, if w e c a l l p b t h e true density and p e the ((electronic density)) t o which t h e s o n d e responds, i t c a n b e shown that: (5) By virtue of formula (3), equation (5) writes: By eliminating between (4) and (6), then replacing p L s , p w , C I S and C w by their numerical v a l u e s , we get: with C = Z 2- where Z A = pb atomic number A = atomic weight Plog I H 1.008 12.011 16.000 22.99 28.09 35.46 40.08 C NO SI CI Ca Compound ~ 11 14 - 1.9841 ,9991 oooo ,9569 ,9968 ,9588 ,9980 f'b C 510, CaCO, 2.654 2.710 0.9985 Calc1tc Dolomite CaCO,!MgCO, 2.870 0.9977 Anhydr i t e CaSO, 2.960 0.9990 1.000 1.146 1.1101 1.0797 0.850 1.1407 F r e s h water H, Salt water 200,000 01I flog I II(CH2) ppm (7) 1.07 p, - 0.188 (7) where C m a p,,, Cm,p m f and C h ph are respectively the electronic d e n s i t i e s of t h e matrix, of t h e mud filtrate and of t h e hydrocarbons -~ Quartz 0.188 L e t u s now revert to our problem and consider a c l e a n hydrocarbon bearing formation T h e fluid in t h e investigated z o n e i s made up of Srh % of hydrocarbon and (1 - Srh) % of mud filtrate Equations (7) and (6) write: A R Formula L = 1.07 p , - = T h i s , then, i s the relationship, between t h e electronic density and t h e reading of t h e Formation Density log For most of t h e e l e m e n t s and compounds found in sedimentary formations C i s very c l o s e to one, a s shown in t a b l e s herebelow: A 1.07 p , - 0.188 Since t h e log i s calibrated in s u c h a way that p log p b in fresh water bearing limestones, it r e s u l t s that: Similar relationships e x i s t for compounds pe differs from pb only to t h e extent that C i s not e x a c t l y e q u a l t o Element = 0.9991 By eliminating p , between (7) and (8), and noticing that: pmo = 1.07 Cma p,, - 0.188 S E P T E M B E R - OCTOBER, 1968 and assuming the heaviest components to have a density of 0.9, we have obtained the following empirical formula: derived from the Density For methane which h a s a density of 0.2 f 25% under most of reservoir conditions, t h e formula gives nH = 0.25, the correct figure, if one t a k e s ph = 0.2 w e get the relationship between pb (log reading) and (true porosity): T h e apparent porosity $, log, by definition: 4D pma= pma - pb , is given by: For heavy oil, i.e p h Pmf = 0.9, the formula gives nH = 0.15, which is a good approximation s i n c e the lower l i m i t for heavy saturated hydrocarbons is: INFLUENCE O F MUD SALINITY - 0,143 T h e following parameters, used in formulae (2) and (lo), depend on mud filtrate salinity: P By eliminating nH between (14) and (15), we obtain = as a function of p,only: mud filtrate hydrogen index, a = p m f mud filtrate density, C, pd mud filtrate electronic density p, f0.15 + 0.2 (0.9- p,) In the formulae the filtrate salinity will b e given a s - if 0.25 a function of the parameter: ph < 0.9, i.e practically for oil, we can write: a N a C l Concentration (ppm) 1,000,000 Z = 1-.4P pmf= + 0.30 p, (17) - if p,< 0.25, i.e practically for gas, we can write: T h e following approximate formulae have been esblished: p 1+.7P Cmf pmf = 1.11 + 65 P a 2.2 (18) ph (11) b On ( 12) In formula (lo), C, p h is the electronic density of the hydrocarbons C, is related t o nH through the following simple formula: (13) Formation Density log Ch = + INFLUENCE O F HYDROCARBON DENSITY rIH ( 19) Taking (14) into account, we get: a On Neutron log c, In formula (2) above (Neutron equation) is the hydrogen index of the hydrocarbons or, more precisely, t h e ratio of the hydrogen content per unit volume of hydrocarbons over that of water It c a n b e shown that is given by the following formula: p, - (1 + rlH) p, = D( x+ i f 0.25 ph p h < 0.9 D( using the expression of chph where nH is the proportion of hydrogen by weight in the hydrocarbons By plotting nH v s ph for a number of saturated hydrocarbons (C,H,, + ,) under average reservoir conditions, THE LOG ANALYST (16) Graphical study of t h i s third degree function shows that i t can reasonably b e assimilated to two different linear functions, depending on t h e range of P, values ( s e e fig 1): We s h a l l l i m i t our study t o the case where the mud filtrate c a n be considered as a pure N a C l solution P = - if ph < 0.25 with = 0: given by (17), we find: = 1.11 ph + 0.03 p h , we find: C, O( ph = 1.24 p , d RELATIONSHIP BETWEEN DENSITY OF HYDROCARBONS A N D THEIR HYDROGEN INDEX ( H index) 25 a FIGURE G E N E R A L F O R M U L A E EXPRESSING T H E E F F E C T OF R E S I D U A L H Y D R O C A R B O N S A T U R A T I O N O N N E U T R O N A N D F O R M A T I O N D E N S I T Y LOGS b I t is assumed in t h e following t h a t t h e Neutron l o g i s calibrated t o give t h e true porosity in c l e a n i n t e r v a l s where there is mud filtrate only, with no residual hydrocarbons If a n interval c o n t a i n s residual hydrocarbons, t h e apparent Neutron porosity + N will n o longer b e e q u a l t o t h e true porosity : v a l u e of A& Formation Density log T h e p r e s e n c e of residual hydrocarbons i n s t e a d of mud filtrate c a u s e s a variation Ap, of t h e log reading, and a s a result t h e apparent porosity q5D differs from t h e true porosity a Neutron log The f h T h e e x p r e s s i o n s of Apb and ApD are found by combining e q u a t i o n s (9) or (19), (12), (13), (21) or (22), and (26) for oil: i s readily found by combining relationships (2), i l l ) , (17) or (18), and (23): A+D = p, for oil: - ph) + - - P + 1.07 Srh [1.11 (1 65 P - 031 (28) for g a s : Apb for g a s : = A4D = - 1.07 + 1.07 Srh [1.11 + 65 P - 1.24 S , h [ l l l + 65 P - 1.24 ,p, - - P phl ph I (29) (30) F i g u r e s and are a graphical representation of t h e and Ap, relationships SEPTEMBER - OCTOBER, 1968 EFFECT OF HYDROCARBON ON NEUTRON LOG A@,,, CHART TRUE POROSITY = 28% HYDROCARBON DENSITY Qh = 0-2 EXAMPLE RESIDUAL HYDROCARBON SATURATION srh FILTRATE SALINITY 200.000 P P M I 8 0 S F H 0 o THE NEUTRON LOG READS 28 - 8.5 = 19.5 % 50 100 40 10 = I = 60 % "N 80 -s*5% 60 20 srh(%) 40 I FIGURE From (29): PRACTICAL APPLICATIONS pb = The final Neutron and Formation Density formulae (24), (25), (27), (28), (29) and (30) look somewhat complicated, but charts based on these formulae are easy to use, a s will be illustrated on a few typical cases a Clean sands ( p g = S,, (32) On a cross-plot of r,bN versus pb, the lines for constant values of and for constant values of Srh are straight line The chart (fig 4) is practically the same a s chart 40-1 in the Schlumberger Paris Chart Book of 1966 + 2.65) containing hydrocarbons with known p h Let us assume, for example, that the density of the mud filtrate pf = 1, and that ph = 114 (this is the c a s e of gas with a hydrogen index of 25) Similar charts can be made for other values of ph (see fig for ph = S ) From (25) we derive: T H E LOG ANALYST 2.65- 1.65 4-1.04 Similar charts can also be made for clean limestones (pma = 2.71) or dolomites (pma = 2.87) EFBECU OF HYDROCARBON OM FORMATOOM DENSITY LOG AQb CHART I TRUE POROSITY = 21% EXAMPLE HYDROCARBON DENSITY ph ~ RESIDUAL HYDROCARBON SATURATION S,h= 75% FILTRATE SALINITY 150.000 P P M I "4 b = - 0.09 FIGURE b Clean Sands containing hydrocarbons of unknown for g a s : ph I t c a n b e shown that, to a good approximation, regardl e s s of t h e value of ph: T h e whole p r o c e s s i s s o l v e d graphically by figure T h e more a c c u r a t e v a l u e of Srh which is n e e d e d to derive p h from t h e s e c o n d part of t h e chart is c a l c u l a t e d from: Therefore, t o e v a l u a t e 4, we need to make an assumpabout Srh Fortunately t h i s assumption i s not critical We can then c a l c u l a t e a value of ph which is e x p r e s s e d a s a function of Srh and = C , S ~ / + , in t h e following equations: 62 Rm, Rxo = 62.15 (1 - SrJ2 c Hydrocarbon bearing shaly sands for oil: Formulae (24), (25), (27) and (29) remain valid in s h a l y formations T h e s e formulae s h o w that t h e often u s e d method of deriving a value of s h a l e content V s h S E P T E M B E R - O C T O B E R , 1968 FIGURE EFFECT O F GAS ON N-FDC C O M B I N A T I O N 1.65 1.25 30% 1.114 I o L 40%, \ z a I 20% 60; ' 10% 1.7 1.8 2.0 1.9 2.1 2.2 2.3 2.4 2.5 2.4 2.7 FIGURE EFFECT O F LIGHT OIL ON N - F D C COMBINATION SANDSTOb 2.65 m 30% HYDROCAfi D N DENSIlY FRESH M U (X a e = 0.5 Pf = 1.0 fh 20% A I z t 10% 1.7 THE LOG ANALYST \ 1.8 1.9 o I 2.3 2.4 2.5 ? 2.6 I I I L f a 10 SEPTEMBER - OCTOBER, 1968 SYMBOLS USED ABOUT T H E AUTHORS T h i s paper h a s been written using a new set of symbols which follows as closely as possible the standard API list We apologize for t h e inconvenience t h i s will certainly c a u s e those who are accustomed to t h e old system, but we felt that the change had to b e made: Physical Parameters: R p q5 S V a P= resistivity density porosity fluid saturation proportion by volume hydrogen index of hydrocarbons hydrogen index of t h e mud filtrate Mr R Gaymard graduated in 1947 from Ecole Polytechnique, Paris, and in 1948 from Ecole Nationale Supgrieure du P&role, near Paris, with a Petroleum Engineering degree During 1948-1951 he was drilling and Production Engineer for SN REPAL, Algeria He joined Schlumberger in 1951 and was assigned successively to SWSC (U.S.), Surenco (South America), SPES (Europe and Africa) and Schlumberger Overseas (Libya) ppm N a C l 1,000,000 He is presently working a t the Sales Interpretation Department of Schlumberger, Paris, headquarters where he is in charge of Computer Processed Interpretation Subscripts: w h mf ma 1s sh water hydrocarbon mud filtrate matrix limestone shale b e r N D bulk electronic residual Neutron l o g Formation Density log Under t h i s system we have t h e following equivalence t o the old list: Former symbols: New symbols: ROS Sro Residual oil saturation RGS Srg Residual g a s saturation Srh Residual hydrocarbon sat p, P p m a Matrix (Grain) density Vsh Proportion of s h a l e by volume of formation I Andre Poupon graduated in 1933 from Ecole Polytechnique in Paris After one year of military service and three years with the French Railroad, he joined Schlumberger at the end of 1937 He worked in the field in Trinidad, France, and Venezuela and was transferred to Schlumberger’s research center i n Ridgefield in September, 1948 REFERENCES Mr Poupon moved to Paris in September, 1955, to work in the Interpretation Department of S.P.E Schlumberger He is at present head of this department J Tittman and J S Wahl: “The physical Foundations of Formation Density logging” (Geophysics, April 1965) 12 SEPTEMBER - OCTOBER, 1968 i P < I i I I I chart indicates a porosity of 25% and the probable lithology is 50% h e s t o n e + 50% dolomite, with a grain density of 2.79 through a cross-plot of q5N versus pb gives Vsh values that are too low in formations containing light oil In gas beaiing formation the error on Vsh could be quite large On the other hand, i f a reliable value of shale content can be estimated independently of the Neutron and Density logs (Gamma Ray, or SP, or Resistivity), q5N and C$D can be corrected Then: - if ph is known the clean sand charts (such a s those of fig and 5) can be used to derive q5 and Srh; - i f ph is not known the chart of fig can be used to estimate q5 and ph d If that same formation contains hydrocarbons, both the Neutron and Density readings will be affected Let us assume ph = 55 and Srh = 40% From (24) we find, for P = (fresh mud): Complex lithologies: determination of q5 and p,, the apparent Neutron porosity then is 26 - 015 = 245 or 24.5% In wate'r bearing mixtures of sand, limestone and dolomite, with no shale, the porosity and approximate grain density can be derived from a cross-plot of pb versus q5N, such a s that of fig which corresponds to pf = (chart 42 of the Schlumberger Paris Chart Book of 1966) For example, for C$N = 26% and pb = 2.34, the From (27) Apb = - 1.07 X 25 X 40 (.S- 033) =-.05 the bulk density reading is 05 gr/cc too low, and is equal to: 2.1 2.34 - 05 = 2.29 2.2 The point for q5N = 24.5% and pb = 2.29 on the chart of fig falls exactly on the line corresponding to pure limestone, and indicates an apparent porosity of 24.5% 2.3 f 2.4 2.5 Due to the effect of the residual hydrocarbons, then, the estimated porosity is very slightly in error, and the estimated grain density is appreciably off, 2.71 instead of 2.79 At low porosities the hydrocarbon effect would be negligible 2.6 2.7 2.8 From this example, it can be concluded that in formations containing light oil, when the porosities range from medium to high, the residual hydrocarbons are not likely to have much effect on the porosity determination, but lithology cross-plots cannot be satisfactorily interpreted without taking into account the effect of the residual hydrocarbons The correction for residual hydrocarbons, needed for a correct determination of the lithology can be made only if ph is known and if an R x o log is available to give an approximate value of Sr, porosity ) 2.9 30 10 20 30 40 50 COMPLEX LITHOLOGY FIGURE THE LOG ANALYST 11 A STATISTICAL STUDY O F THE FORMATION FACTOR RELATION by JAMES E CAROTHERS Phillips Petroleum Co., Bartlesville, Oklahoma Sandstone A1 A1 A1 * Data Point (793 samples) % POROSITY FIGURE 13 Y ST ~ i: i I I : : EDITOR'S NOTE: T h i s study is the culmination of a s t a t i s t i c a l evaluation on what may b e the most extensive collection of formation factor-porosity-permeability data published to date The empirical relations computed from t h e formation factor and the porosity and/or permeability d a t a should find widespread application in log analysis Such relations should prove especially useful in a r e a s having the same lithology a n d age as those analyzed of formation factor to porosity is evident T h i s method of averaging and plotting is used in this report It must be recognized that the differences in formation factor measurements due to permeability are natural differences, and averaging may not b e advantageous when a group of samples from one formation are to b e considered However, when samples are from a broad coverage in area, and time periods, i t is f e l t that t h e s e differences are more random and averaging will give a better generalized relationship T h e results of a statistical study of measured formation factor d a t a are presented T h e b a s i c data measurements are from analyses made in the Phillips Petroleum Company Reservoir Engineering Laboratory, and from other sources A total of 981 measurements were used; 793 in sandstones and 188 in carbonates Figure is the plot of all 793 sandstone formation factors versus porosity values It can b e s e e n that the abundance of data h a s obscured a single line relationship When t h e s e data were averaged and plotted, as in Figure 2, a definite relationship is observed T h i s plot s u g g e s t s that a general formation factor-porosity relation of: Differences in formation factor measurements for a given porosity are due to at least three factors: permeability of the sample, error in porosity measurement, and error in resistivity measurement Averaging all formation factors for a given porosity range minimizes t h e s e differences When t h e s e averaged values are plotted a t the midpoint of the porosity range, a very good relationship 10- e- l 1 , 1 should b e used in sandstones 01- a- ITHOU)GYi I4- sa- Sandstone \o \ 'ORMATION: A l l LREA A1 I Average F by fl Class ?\ Y m POROSITY Ye POROSITY FIGURE FIGURE 14 SEPTEMBER - OCTOBER, 1968 -/j I I I I I I l l 1 1 I I l ITHOLOGYl Sandstone J ~ o u ) G ySand ~ s t one GE: Cretaceous MMATION: All ,a: REA: REA -F ORMATIOIY: A l l 41 Averaqo F by Eocene o @ Class -wk 1.66 41 I Average F by -F= @ Class " 1.5 1.57 f FIGURE FIGURE As the above relation includes the effects of shaly s a n d s as well as calcareous s a n d s , and as each of t h e s e h a s a predicted effect on the resistivity measurement, two more general relations are suggested Averaging a l l points which have values higher than, and a l l points which have values lower than the F Data from Cretaceous, Eocene, and Pennsylvanian s a n d s are presented in Figures 4, 5, and E a c h of t h e s e plots agrees with t h e general s a n d s t o n e relation T h e Eocene sand h a s a change in relationship indicated below 15% T h i s change is a l s o noted in t h e Gulf Coast Oligocene and in most of t h e low porosity limestones 1.45 =61.45 California sands, which a r e generally shaly, are shown in Figure Again there is agreement with the general shaly s a n d relation (Figure 3) relation, we can assume that the higher s l o p e represents calcareous s a n d s while the lower s l o p e represents shaly s a n d s Figure is a plot of t h e s e suggested relationships F =- 1.45 T h e only sand plotted which did not agree with the above relations was the Gulf Coast Oligocene, shown on Figure Samples from t h i s formation ranged from 3-38% porosity Lithology descriptions of the samples indicated both calcareous and shaly sands Note t h e strong indication of a change in the relationship in the porosity range below 15% Calcareous Sand $1.33 F 1.65 =- Shaly Sand $1.33 THE LOG ANALYST 15 % POROSITY Ye POROSITY FIGURE FIGURE O \\\ ITHOLOGYI Limestone DRMATION: A l l herage F by @ Class i I Ye POROSITY O a T O I OOTOO1oo Ye POROSITY FIGURE FIGURE 16 SEPTEMBER - OCTOBER, 1968 I I % POROSITY % POROSITY FIGURE 11 8780- Limestone Pennsylvania ITHOLOGYI Limestone DRMATIffl: L-KC Marv MMATlON: Undcf i ned REA Kansas RE& ITHOLOGYi 4- 8- N C e n t r a l Texas 1- t H iL Yo POROSITY Yo POROSITY FIGURE 13 FIGURE 12 17 THE LOG ANALYST ,n I I R e l i a b l e formation factor measurements in carbonate rocks were not as plentiful as t h o s e in sandstone Figure represents t h e averaged d a t a for 188 points Most of t h e s e d a t a points represent limestone s a m p l e s , with intergranular texture However, a number of t h e points a r e dolomitic and/or, vugular in structure In t h i s figure two straight l i n e relations a r e presented T h e r e is very l i t t l e difference between t h e apparent b e s t fit of t h e data; F=- F i g u r e s 10, 11, 12, and 13 a r e p l o t s of t h e averaged d a t a for Creatceous, J u r a s s i c , Pennsylvanian, and Devonian carbonates T h e r e is less general agreement in t h e relationships from e a c h individual plot to t h e gene r a l carbonate relation P e r h a p s t h i s is due t o wide differences in rock fabric F i g u r e 14 is a summary of t h e four general equations found i n s a n d s t o n e s It w a s noted that with t h e exception of t h e Gulf C o a s t Oligocene s a n d s , all formation factorporosity relations plotted s u g g e s t that “a” i n t h e Archie relation is greater than 1.0 through t h e range of porosit i e s normally encountered in well l o g a n a l y s e s 85 62.14 a n d a forced fit of t h e d a t a ; F =- 62.04 A nomograph h a s been constructed, F i g u r e 15, to s o l v e t h e Archie relation, I t should also b e noted that there is an apparent c h a n g e i n t h e relation below approximately 10% when i t i s d e s i r e d to vary both “a” and “m” While preparing t h e d a t a for t h e a b o v e study, i t w a s noted that s a m p l e s from t h e s a m e core with identical porosity measurements would h a v e different permeab i l i t i e s and formation factors It w a s also noted that in almost every case formation factor i n c r e a s e d with a d e c r e a s e in permeability F i g u r e 16 is a plot of formation factor-permeability measurements from t h e s e samples E a c h c o r e is identified with connected points and labled with percent porosity and lithology F o r v a l u e s above 10 millidarcies permeability there is an indicated relation between formation factor, permeability, and lithology F o r limestone t h e permeability-formation factor relation i s : K= 4.0 x lo8 F3.65 F o r s a n d s t o n e t h e permeability-formation factor relation is: More d a t a a r e needed to confirm t h e s e observations FIGURE 14 18 SEPTEMBER - OCTOBER, 1968 F - Formation 3ooo - - 2500 NOMOGRAPH FOR SOLVING F= I Porosity 2000 A Brn Ixx) -0 I' -loo0 100- 900 800 700 Y 600 xx) 00 -m 40 -3.0 m , I5 350 300 2% 200 J I50 loo lo 90 - 6- - 80 70 60 5- - 50 4- - 40 8l -3- - 30 A 2- 35 - 25 20 € '05 l.5- IS 10 r _PHILLIPS PETROLEUM COMPANY R.L.Woods J.E.Corothers _ 3.5 - FIGURE 15 I THE LOG ANALYST 19 FORMATION FACTOR- PERMEABILITY RELATION '3s Samples from sane f o r m a t i o n having i d e n t i c a l p o r o s i t y and ithology PERMEABILITY- MD FIGURE 16 ABOUT THE AUTHOR J a m e s E Carothers received h i s B.S degree from the University of Houston in 1950, majoring i n Geology He h a s been a n employee of the Exploration & Production Department of Phillips Petroleum Company s i n c e 1945, having served on the exploration staff a s a n exploration and development geolo g i s t and a s a well logging specialist H e is currently Senior Formation Evaluation Specialist i n Phillips' home office in Bartlesville, Oklahoma Mr Carothers is a member of S P E and the T u l s a Geological Society He is a charter member of SPWLA and is currently V i c e President-Membership of t h i s Society 20 SEPTEMBER - OCTOBER, 1968 ... electronic density and t h e reading of t h e Formation Density log For most of t h e e l e m e n t s and compounds found in sedimentary formations C i s very c l o s e to one, a s shown in t a b... the following simple formula: (13) Formation Density log Ch = + INFLUENCE O F HYDROCARBON DENSITY rIH ( 19) Taking (14) into account, we get: a On Neutron log c, In formula (2) above (Neutron equation)... problem and consider a c l e a n hydrocarbon bearing formation T h e fluid in t h e investigated z o n e i s made up of Srh % of hydrocarbon and (1 - Srh) % of mud filtrate Equations (7) and (6)