CORING METHODSPorosity, permeability, grain density, and mineralogy of reservoir rocks are important elements in a reservoir description. We can estimate these properties from well logs or measure them from rock samples in the laboratory. The rock samples are obtained by cutting a piece of rock from the well bore; the process is called coring. Conventional cores are cut using a specialized subassembly at the bottom of the drill string. This consists of a coring drill bit (usually a diamond bit), a core barrel to hold the recovered core, and fingers in the core barrel to hold the core in place while the coring assembly is pulled out of the hole. At the surface, the core is retrieved from the core barrel and placed in transport boxes, which are transported to a laboratory for further study.If coring while drilling is impractical, small cores can be taken on wireline using a sidewall core gun or a sidewall rotary coring tool. The sidewall core gun uses black powder explosives to fire a steel bullet into the rock adjacent to the tool. The hollow bullet captures a small piece of rock that is pulled to the surface by the tool. Such guns can recover up to 48 samples in one trip in the hole. Depth control is monitored using a gamma ray log to correlate to previous logs run in the well.The rotary coring tool uses an electrically driven diamond bit to drill a small core from the formation adjacent to the tool. Several cores can be taken at different depths before the tool is brought to the surface.

Coring assembly on bottom of drill string and coring bit Rotary core drill on wireline Sidewall core gun with steel bullets Core slab, core plug, full diameter, and whole core definition Core photo of slabbed core

Taking core plugs for horizontal and vertical rock properties requires care and attention to dipping beds, fractures, lithology variations, and porosity heterogeneity. Do NOT high-grade the selection of core plugs by choosing only good porosity points - this will not provide useful information to control petrophysical evaluations, reserves, productivity or other performance calculations.CORE POROSITY DEFINITIONSPorosity is an intrinsic property of reservoir rocks and indicates the storage capacity of the reservoir. It is used as a primary indicator of reservoir quality, and along with a few other factors, to calculate hydrocarbon volume in place, and recoverable reserves. Petrophysicists use core porosity values to help calibrate porosity derived from well log data.Bulk Volume of a Rock = Grain Volume + Pore Volume 1: Vb = Vg + VpPorosity = Pore Volume / Bulk Volume 2: PHIt = Vp / Vb

OR: Porosity = (Bulk Volume - Grain Volume) / Bulk Volume 3: PHIt = (Vb - Vg) / VbNote that "V" in this Chapter stands for Volume, not Velocity. These volumes are usually reported in cubic centimeters (cc).The properties Vb, Vg, and Vp can be measured in the lab on full diameter core or on smaller core plugs drilled from the whole core, or from sidewall percussion or sidewall rotary cores. Whole core is best in heterogeneous reservoirs and in low porosity reservoirs. MEASURING BULK VOLUME (Vb)There are 3 ways to measure bulk volume: s. direct measurement of the dimensions of a regular solid b. fluid displacement using Archimedes Principle c. fluid displacement using calibrated container (pycmometer)DIRECT MEASUREMENT: Bulk Volume = Pi * Length * Radius squared 4: Vb = PI * L * D^2 / 4 This method is less accurate due to the roughness of the surfaces of the solid and imperfections in shape.ARCHIMEDES METHODThis technique utilizes the Archimedes principle of mass displacement in a liquid (buoyancy): a. The core is first cleaned, dried, and weighed in air (WTdry) b. The core sample is then saturated with a wetting fluid and weighed (WTsat) (the core may be coated with paraffin to prevent evaporation) c. The sample is then submerged in the same fluid and its submerged weight is measured (WTsub) d. The bulk volume is the difference between the last two weights divided by the density of the fluid. e. The porosity is the difference between the first two weights divided by the density of the fluid.

Bulk Volume = (Weight in air (saturated) - Weight submerged) / Density of Fluid 5: Vb = (WTair - WTsub) / DENSfl 6: Vg = (WTdry - WTsub) / DENSfl 7: Vp = (WTsat - WTdry) / DENSfl 8: PHIt = (WTsat - WTdry) / (WTsat - WTsub) = Vp / VbBulk Density = Saturated Weight / Bulk Volume 9: BulkDens = WTsat / VbIf clays are present and sample is maintained at a high humidity (not over dried), this last equation gives PHIe, not PHIt.Laboratory measurements using this technique are very accurate.

CALIBRATED DISPLACEMENT METHODThe bulk volume can be determined also by the volume of the displaced fluid. Fluids that are normally used are water, which can easily be evaporated afterwards, and mercury, which normally does not enter the pore space in a core sample due to its non-wetting capability and its large interfacial tension against air.Bulk Volume = Volume of Displaced Fluid = Weight Displaced Fluid / Density Displaced Fluid10: Vb = WTdisp / DENSfl

Laboratory measurements using this technique are very accurate.EXAMPLE: WTdry = dry weight in air = 16.0 gm WTsat = weight of saturated sample in air = 20.0 gm WTcoated = weight of dry sample coated with paraffin = 20.9 gm (density of paraffin = 0.9 gm/cc) WTsub = weight coated sample immersed in water at 70 F = 10 gm (density of water = 1.0 gm/cc)Determine bulk volume Weight of paraffin = WTcoated - WTsar = 20.9 - 20.0 = 0.9 gm Density of Parrafin = 0.9 gm/cc Volume of paraffin = WTpar / DENSpar = 0.9 / 0.9 = 1.0 cc Weight of water displaced = WTcoated - Wtsub = 20.9 - 10.0 = 10.9 gm Volume of water displaced = 10.9 / 1.0 = 10.9 cc Volume of water minus displaced-volume of paraffin = 10.9 - 1.0 = 9.9 cc Bulk volume of rock = 9.9 cc

MEASURING GRAIN VOLUME (Vg)There are 3 ways to measure grain density in the lab: a. assume a grain density, compare to dry weight b. displaced fluid method c. Boyle's LawASSUMED GRAIN DENSITY Determine Vg from the dry weight of the sample and the rock grain density (2.65 gm/cc for quartz grains). This method is not very accurate if grain density varies due to varying mineralogy. Grain Volume = Dry Sample Weight / Grain Density 11: Vg = WTdry / DENSMADISPLACED FLUID METHODA more accurate approach is to use the displaced fluid volume. First the core plug is measured to obtain its bulk volume, as described earlier Then the sample is crushed to eliminate all porosity and weighed (WTgr). A glass tube filled with water, called a pycnometer to confuse novices, is weighed (W1), then the crushed rock is placed in the tube (still filled with water), and weighed again WT2). The difference in weights gives the volume of displaced fluid.Displaced Volume = Crushed Sample Weight + Water-filled tube Weight - Combined Weight 12: Vdisp = (WT2 - WT1)

Grain Volume = Displaced Volume / Water Density 13: Vg = Vdisp / DENSwater

Porosity = (Bulk Volume - Grain Volume) / Bulk Volume 14: PHIt = (Vb - Vg) ' VbIf clays are present and sample is maintained at a high humidity (not over dried), this last equation gives PHIe, not PHIt.Grain Density = Dry Weight in Air / Grain Volume 15: GrainDens = WTdry / VgEXAMPLE: WTdry = Weight of dry crushed sample in air = 16.0 gm, WT1 = Weight of pycnometer filled with water at 70 F = 65.0 gm WT2 = Weight of pycnometer filled with water and crushed sample = 75.0 gmCalculate grain volume Volume of water displaced = 16.0 + 65.0 - 75.0 = 6.0 gm Grain Volume = 6.0 / 1.0 = 6.0 ccCalculate porosity Bulk volume of the sample = 9.9 cc, from previous example Total porosity = (9.9 - 6.0) / 9.9 = 0.394 fractional porosity (39.4%)

BOYLE'S LAW METHODAn alternate grain volume method makes use of Boyles Law. This gas transfer technique involves the injection and decompression of gas (Helium, CO2, or N2) into the pores of a fluid-free (vacuum), dry core sample. Either the pore volume or the grain volume can be determined, depending upon the instrumentation and procedures.To determine grain volume using ideal gas law at constant temperature: a. connect two cells of known volume, Vcell1 and Vcell2 b. close valve between cells, apply pressure P1 to cell 1 c. place dry core sample in cell 2, seal and evacuate cell 2 d. open valve and measure pressure P2

Boyle's Law apparatus to measure grain volume Vg 16: V2 = P1 * Vcell1 / P2Since V2 = Vcell1 + Vcell2 - Vg And Vtotal = Vcell1 + Vcell2Then 17: Vg = Vt - VfMEASURING PORE VOLUMEIn previous sections pore volume Vp was derived from volumetric methods based on weight and density. Semi-direct measurement of porosity can also be attempted.BOYLE'S LAW METHODPore volume measurements can be done by using the Boyles Law model, where the sample is placed in a rubber sleeve holder that has no void space around the periphery of the core and on the ends. Such a holder is called the Hassler holder, or a hydrostatic load cell. Helium or one of its substitutes is injected into the core plug through the end stem.

Boyle's Law apparatus for determining porosity 18: V2 = P1 * Vcell1 / P2Since V2 = Vcell1 + PHIeThen 19: Vp = V2 - Vcell1FLUID SUMMATIONS METHODThis technique is used to measure the volume of gas, oil and water present in the pore space of a fresh or preserved (peel-sealed) core of known bulk volume. The volumes of the extracted oil, gas, and water are added to obtain the pore volume and hence the core porosity.DEAN-STARK CORE ANALYSIS METHODThis method is used in poorly consolidated rocks such as tar samds and involves disaggregating the samples and weighing their constituent components. Samples are usually frozen or wrapped in plastic to preserve the contents during transport. In the lab, the still frozen cores are slabbed for photography and description, then samples are selected and weighed.Samples are then heated and crumbled to drive off water, and weighed again. The weight loss gives the water weight. Solvents are used to remove oil or tar. The sample is weighed again and the weight loss is the weight of oil. The matrix rock is separated into clay and mineral components by flotation, dried and weighed again, giving the weight of clay and weight of the mineral grains. 20: WTwtr = WTsample - WTheated 21: WTtar = WTheated - WTminerals&clayBy dividing each weight by its respective density and adjusting each result for the total weight of the sample, the volume fraction of each is obtained. Porosity is the sum of water plus oil volume fractions Because the bound water in the clay is driven off by the drying sequences, this porosity is the total porosity. 22: VOLwtr = WTwtr / DENSwtr / WTsample 23: VOLtar = WTtar / DENStar / WTsample 24: PHIcore = VOLwtr + VOLtar

TAR MASS FROM CORE LISTINGSIf not provided on the core listing, the equivalent value of tar mass from core analysis is derived from porosity, oil saturation, and an assumed oil density: 25: Wtar = PHIcore * Star * DENStar 26: Wwtr = PHIcore * Swtr * DENSwtr 27: Wrock = (1 PHIcore) * GR_DENScoreWhere: Star = tar volume relative to pore volume Swtr = water volume relative to pore volume PHIcore = volume of water + valume of tar Wtar = tar mass fraction Wwtr = water mass fraction Wrockcore = rock mass fractionPHIcoreStarSwtrVol TarVol WtrGR_ DENWT TarWT SandWT WtrWT RockTar Mass WtarWtr Mass WwtrRock Mass Wrock

fracfracfracfracfrackg/m3fracfracfrac

0.3060.3010.6990.0920.2142.6500.0921.8390.2122.1430.0430.0990.858

0.2710.2360.7640.0640.2072.6500.0641.9320.2072.2030.0290.0940.877

0.2790.3060.6940.0850.1942.6500.0851.9110.1932.1890.0390.0880.873

0.2440.3040.6960.0740.1702.6500.0742.0030.1682.2460.0330.0750.892

0.2980.2170.7830.0650.2332.6500.0651.8600.2332.1580.0300.1080.862

0.2730.2980.7020.0810.1922.6500.0811.9270.1912.1990.0370.0870.876

If saturations (or pore volume) are known, as well as core porosity, all other terms can be calculated. Some core analysis reports do the math for you, some do not.Since GR_DENScore represents a mixture of quartz and shale, this value should vary with shale volume. However shale volume is never reported on core analysis, so the composite grain density from the rock sample is used. If grain density is not recorded in the core analysis, we must assume a constant of 2650 Kg/m3 or lower.

FLUID VOLUMES FROM CORE LISTINGSIf not provided on the core listing, the equivalent value of tar volumes from core analysis are derived from porosity, tar mass fraction, and an assumed oil density: 27: Star = Wtar / (PHIcore * DENStar) 28:Swtr = Wwtr / (PHIcore * DENSwtr)OR 29: Swtr = 1.00 - StarWhere: Star = tar volume relative to pore volume Swtr = water volume relative to pore volume PHIcore = volume of water + valume of tar Wtar = tar mass fraction Wwtr = water mass fractionPHIcoreStarSwtrVol TarVol WtrGR_ DENWT TarWT SandWT WtrWT RockTar Mass WtarWtr Mass WwtrRock Mass Wrock

fracfracfracfracfrackg/m3fracfracfrac

0.3060.3010.6990.0920.2142.6500.0921.8390.2122.1430.0430.0990.858

0.2710.2360.7640.0640.2072.6500.0641.9320.2072.2030.0290.0940.877

0.2790.3060.6940.0850.1942.6500.0851.9110.1932.1890.0390.0880.873

0.2440.3040.6960.0740.1702.6500.0742.0030.1682.2460.0330.0750.892

0.2980.2170.7830.0650.2332.6500.0651.8600.2332.1580.0300.1080.862

0.2730.2980.7020.0810.1922.6500.0811.9270.1912.1990.0370.0870.876

If tar mass fraction and water mass fraction are known, as well as core porosity, all other terms can be calculated. Some core analysis reports do the math for you, some do not.

POROSITY FROM MICRO CT SCANSPorosity is directly calculated from high resolution digital images such as those shown below.This calculation is the ratio of the number of voxels that fall into the pore space (black and dark-gray) to the total number of voxels in a 3D image.The task of separating the pores from grains in such 3D objects is called image segmentation. The main technical challenge in image segmentation is the gradual transition from dark to light shade of gray at the edges of the pore space. Proprietary image-processing algorithms are used, which include statistical analysis of the gray-scale images.As a result, the pore space is accurately separated from the mineral matrix and the porosity is computed. Source: www.ingrainrocks.com.

Clean sand 39% Tight sand 5% Poorly sorted 12% Silty Shale 8% Black = Porosity, Grey = Matrix Grains, White = Heavy Minerals

SAMPLE CORE ANALYSIS REPORT

Samples of core analysis and core description plots, with a few of the posible histograms and crossplots that can be made.02181815W4#23708731011NOTE: Accumap has Kvert in K90 Column

S#TopBaseLenKmaxK90KvertPorosGrDenBkDenSoilSwtrLithology

feetfeetfeetmDmDmDFracKg/m3Kg/m3fracfrac

13499.193500.170.98742.00.0180.00.283000.1290.448SS VF-F

23500.173501.160.981196.00.0694.00.297000.1230.450SS VF-F

33501.163502.171.02622.00.0266.00.276000.1110.520SS VF-F

43502.173503.160.98223.00.050.50.271000.1290.479SS VF-F

53503.163503.880.72837.00.0171.00.278000.1100.504SS VF-F PY

63503.883504.570.69407.00.0113.00.287000.1180.466SS VF-F

73504.573504.670.100.00.000 000SH

83504.673505.260.59514.00.0365.00.253000.1510.398

93505.263505.490.23100.00.02.60.201000.1340.358SS VF-F SH INC

103505.493505.980.49401.00.0120.00.254000.1430.268SS VF-F SHBKS

113505.983506.960.98478.00.0302.00.282000.1310.471SS VF-F

123506.963507.880.92431.00.0100.00.243000.1560.399SS VF-F CARB INC

133507.883508.470.59777.00.0556.00.277000.1190.389SS VF-F

143508.473508.870.39831.00.0383.00.275000.1360.422SS VF-F CARB BK

153508.873509.881.02413.00.0262.00.281000.1320.440SS VF-F

163509.883510.870.98604.00.0425.00.277000.1310.323SS VF-F SH INC

173510.873511.881.02320.00.035.10.229000.1460.422SS VF-F SH INC

183511.883512.870.98616.00.0437.00.239000.1030.354SS VF-F

193512.873513.790.92259.00.062.00.261000.0730.418SS VF-F

203513.793514.380.59320.00.026.80.219000.0960.441

213514.383515.070.69431.00.082.50.236000.1190.387SS VF-F

223515.073515.160.100.00.0SH PY

233515.163516.181.02969.00.0628.00.270000.0440.492SS VF-F

243516.183516.770.59837.00.0634.00.280000.0420.501SS VF-F

253516.773517.460.69556.00.0201.00.273000.0500.531SS VF-F CARB INC

263517.463518.280.82706.00.0338.00.262000.0460.487SS VF-F

273518.283519.070.79502.00.0377.00.238000.0790.494SS VF-F CARB INC

283519.073519.990.921136.00.0183.00.263000.0630.501SS VF-F

293519.993520.580.59825.00.0291.00.265000.0520.563

303520.583521.460.891346.00.0706.00.274000.0550.516SS VF-F

313521.463522.481.02389.00.0102.00.246000.0640.450SS VF-F/M CARB INC

323522.483523.470.98165.00.011.90.219000.0580.408SS VF-F/M CARB INC

333523.473524.481.02586.00.066.00.219000.0820.411

343524.483525.470.981035.00.0395.00.244000.0510.391SS VF-F

353525.473526.481.02514.00.0187.00.199000.0730.360

363526.483527.470.98526.00.089.00.205000.0460.481SS VF-M

373527.473528.160.691375.00.0208.00.216000.0420.548SS VF-M PY CARB

383528.163528.880.72287.00.095.00.207000.0660.462

Arithmetic Averages0.78618.80.0240.70.2530.00.00.0950.443

CORE PERMEABILITY BASICSPermeability is an intrinsic property of a reservoir rock that indicates the flow capacity of the reservoir. Reservoir engineers use permeability, reservoir pressure, and a few other parameters to estimate oil and gas productivity. Petrophysicists use core permeability values to help calibrate permeability derived from well log data.The Darcy flow equation defines permeability, and after some rearrangement, is used to calculate permeability from laboratory measurements. 1: Q = K * A * (P1 - P2) / (u * L)Where: Q = flow rate K = permeability A = area P1 - P2 = pressure drop L = path length u = mobility

Definitions used in Darcy flow equationTo measure the permeability in the lab, dry gas is usually used (air, N2, and He) in permeability determination because of its convenience, availability, and to minimize fluid-rock reaction. The measurement of the permeability should be restricted to the low (laminar/viscous) flow rate region, where the pressure remains proportional to flow rate within the experimental error. At low pressures, we assume the gases follow the ideal gas law.Permeability measured with a single fluid in the rock is called absolute or intrinsic permeability (Ka). It is often measured using dry air, giving rise to the term "air permeability" (Kair). Nitrogen and carbon dioxide are also used. When water is used as the single fluid, the result is called "liquid permeability" (Kliq). Air perm is usually a little higher than liquid perm. The Klinkenberg correction is used to reduce air perm to an equivalent liquid perm.Effective permeability is the permeability of a rock to one fluid in a two phase system. For example, the effective permeability of oil in an oil-water system (Ko) will be less than absolute permeability. In the same rock and fluid system, the effective permeability of water (Kw) could be higher or lower than Ko. Relative permeability is the ratio of the effective permeability of a fluid at a given saturation to some base permeability. Base permeability is typically defined as absolute permeability (Ka), air permeability (Kair), or effective permeability to non-wetting phase at irreducible wetting phase saturation, for example Ko @ Sw = SWir. Because the definition of base permeability varies, the definition used must always be confirmed before applying relative permeability data noted along with tables and figures presenting relative permeability data.

LAB PROCEDURE FOR MEASURING AIR PERMEABILITY Cut core plugs from whole core or use sample from whole core Clean core and extract reservoir fluids, then dry the core Flow a fluid through core at several flow rates Record inlet and outlet pressures for each

Laboratory apparatus for measuring permeability using air and Darcy's Law

LAB PROCEDURE FOR MEASURING LIQUID PERMEABILITY Measure inlet and outlet pressures (P1 and P2) at several different flow rates Graph ratio of flow rate to area (q/A) versus the pressure function (P1 - P2) / L For laminar flow, data follow a straight line with slope of k/ At very high flow rates, turbulent flow is indicated by a deviation from straight line

Finding permeability with liquid or high rate gas flowKLINKENBERG EFFECTKlinkenberg discovered that permeability measurements made with air as the flowing fluid showed different results from permeability measurements made with a liquid as the flowing fluid. Air permeability is always greater than the permeability obtained when a liquid is the flowing fluid. On the basis of the laboratory experiments, liquids had a zero velocity at the sand grain surface, while gases exhibited some finite velocity at the sand grain surface (slippage). This slippage results in a higher flow rate for the gas at a given pressure differential. Klinkenberg also found that, for a given porous medium, as the mean pressure increased,, the calculated permeability decreasedKlinkenberg developed a method to correct gas permeability measured at low mean flowing pressure to equivalent liquid permeability. A plot of measured permeability versus 1/Pm is extrapolated to the point where 1/Pm = 0 (Pm = infinity). This permeability approximates the liquid permeability. 2: Pm = (P1 + P2) / 2 3: Kg = KL + C * (1 / PM)The factor C varies with permeability so it must be determined for each core plug. There are generalized iterative equations to solve for C, but they are not widely used.PERMEABILITY FROM MICRO-CT SCANSPermeability is traditionally measured in the laboratory on regularly shaped rock samples by forcing a fluid through the rock and recording the resulting fluid flux and pressure drops. CT Scanning complements and vastly expands laboratory permeability data sets by numerically simulating fluid flow through a direct digital representation of a real pore space obtained by high-resolution 3D imaging. Such imaging and simulations can be rapidly and massively conducted on physical samples of irregular shapes and sizes that are impossible to handle in the conventional laboratory. The pore volume and pore size determined from the CT Scan are manipulated mathematically by simu;ating the Navier-Stokes equation using the Lattice-Boltzman Method, as shown below.

The slow viscous flow needed for such permeability estimates is simulated using the lattice Boltzmann method (LBM). LBM mathematically mimics the Navier-Stokes equations of viscous flow by treating the fluid as a set of particles with certain interaction rules. Its great advantage over directly solving the equations of flow is that it directly handles the boundary conditions on a complex realistic pore surface. The outcomes are consistent datasets of permeability versus porosity correlations and pore geometries for various rock types, including tight gas sandstone, carbonates, and friable tar sands.The absolute permeability is computed in a manner analogous to a laboratory measurement: a pressure head or body force is directly applied to a digital sample. The resulting fluid flux is then computed and permeability is calculated according to the Darcy's equation. Source: www.ingrainrocks.com.

SAMPLE CORE ANALYSIS REPORT02181815W4#23708731011NOTE: Accumap has Kvert in K90 Column

S#TopBaseLenKmaxK90KvertPorosGrDenBkDenSoilSwtrLithology

feetfeetfeetmDmDmDFracKg/m3Kg/m3fracfrac

13499.193500.170.98742.00.0180.00.283000.1290.448SS VF-F

23500.173501.160.981196.00.0694.00.297000.1230.450SS VF-F

33501.163502.171.02622.00.0266.00.276000.1110.520SS VF-F

43502.173503.160.98223.00.050.50.271000.1290.479SS VF-F

53503.163503.880.72837.00.0171.00.278000.1100.504SS VF-F PY

63503.883504.570.69407.00.0113.00.287000.1180.466SS VF-F

73504.573504.670.100.00.000 000SH

83504.673505.260.59514.00.0365.00.253000.1510.398

93505.263505.490.23100.00.02.60.201000.1340.358SS VF-F SH INC

103505.493505.980.49401.00.0120.00.254000.1430.268SS VF-F SHBKS

113505.983506.960.98478.00.0302.00.282000.1310.471SS VF-F

123506.963507.880.92431.00.0100.00.243000.1560.399SS VF-F CARB INC

133507.883508.470.59777.00.0556.00.277000.1190.389SS VF-F

143508.473508.870.39831.00.0383.00.275000.1360.422SS VF-F CARB BK

153508.873509.881.02413.00.0262.00.281000.1320.440SS VF-F

163509.883510.870.98604.00.0425.00.277000.1310.323SS VF-F SH INC

173510.873511.881.02320.00.035.10.229000.1460.422SS VF-F SH INC

183511.883512.870.98616.00.0437.00.239000.1030.354SS VF-F

193512.873513.790.92259.00.062.00.261000.0730.418SS VF-F

203513.793514.380.59320.00.026.80.219000.0960.441

213514.383515.070.69431.00.082.50.236000.1190.387SS VF-F

223515.073515.160.100.00.0SH PY

233515.163516.181.02969.00.0628.00.270000.0440.492SS VF-F

243516.183516.770.59837.00.0634.00.280000.0420.501SS VF-F

253516.773517.460.69556.00.0201.00.273000.0500.531SS VF-F CARB INC

263517.463518.280.82706.00.0338.00.262000.0460.487SS VF-F

273518.283519.070.79502.00.0377.00.238000.0790.494SS VF-F CARB INC

283519.073519.990.921136.00.0183.00.263000.0630.501SS VF-F

293519.993520.580.59825.00.0291.00.265000.0520.563

303520.583521.460.891346.00.0706.00.274000.0550.516SS VF-F

313521.463522.481.02389.00.0102.00.246000.0640.450SS VF-F/M CARB INC

323522.483523.470.98165.00.011.90.219000.0580.408SS VF-F/M CARB INC

333523.473524.481.02586.00.066.00.219000.0820.411

343524.483525.470.981035.00.0395.00.244000.0510.391SS VF-F

353525.473526.481.02514.00.0187.00.199000.0730.360

363526.483527.470.98526.00.089.00.205000.0460.481SS VF-M

373527.473528.160.691375.00.0208.00.216000.0420.548SS VF-M PY CARB

383528.163528.880.72287.00.095.00.207000.0660.462

Arithmetic Averages0.78618.80.0240.70.2530.00.00.0950.443

Core data listing for Shaly Sand Example

CORE Fluid saturationsSaturation of a particular fluid is the proportion of that fluid compared to the porosity: 1: Swtr = Vwtr / PHI 2: Soil = Voil / PHI 3: Sgas = Vgas / PHI 4: Swtr + Soil + Sgas = 1.00In the laboratory, it is easier to measure weight (mass) than volume, although both are often recorded. 5: Fluid weight = Weight water + Weight oil + Weight gasOR 6: Fluid weight = DENSwtr * Vwtr + DENSoil * Voil + DENSgas * VgasOR 7: Fluid weight = PHI * (DENSwtr * Swtr + DENSoil * Soil + DENSgas * Sgas)

Saturations determined from core analysis are full of problems, but the measurements can be useful for certain situations. The problems are related to the fact that usually cores are flushed, at least to some degree, by mud filtrate during the coring process. This means that much of the hydrocarbon is removed and replaced by mud filtrate. Formation water in the core is also altered by invasion. In water based muds, a tritium tracer can be used while coring. This allows the lab to select samples with the least invasion, based on the tritium remaining in the core.Plastic sleeve coring or wrapping of the core upon retrieval reduces gas loss and water evaporation. Properly handled and measured in the lab, both residual oil and water saturations can be useful qualitatively, and often even quantitatively. In an oil zone, the residual water saturation from core may reflect the irreducible water saturation in the zone, or at least the actual saturation in a transition or depleted zone. The residual oil represents the saturation to expect after an efficient water flood or aquifer drive.Cores taken in oil based mud give a better view of irreducible water, as these muds do not displace the water. However, gas expansion still distorts the oil volume.ines are log analysis.

Bakken Tight Oil example showing core porosity (black dots), core oil saturation (red dots). core water saruration (blue dots), and permeability (red dots). Note excellent agreement between log analysis and core data. Separation between red dots and blue water saturation curve indicates significant moveable oil, even though water saturation is relatively high. Log analysis porosity is from the complex lithology model and lithology is from a 3-mineral PE-D-N model using quartz, dolomite and pyrite.The main use for core analysis oil saturation is to estimate minimum possible residual oil saturation, and to assist in locating gas-oil and oil-water contacts. Gas and water zones have low residual oil, unless they were once oil zones (recently or in earlier geologic time). Oil saturation from core analysis is quite useful in tar sand and sometimes in heavy oil evaluations, where flushing is minimal. Cores are stored in boxes on shelves in warehouses. In hot climates, I have seen oil leaking from core to core, making the presence of oil in a core somewhat equivocal.

CORE saturation measurementsA common method for direct measurement of saturation in a core sample is the distillation retort method. Core samples are heated, fluids are vaporized and condensed into a graduated glass receptacle. This is a rapid method to determine oil and water volumes. Unfortunately, high temperature (1100 F) may destroy the sample and drives off clay bound water (CBW). Clay bound water may be estimated by observation of water volume versus time - pore water is recovered first and clay bound water later, as the temperature increases..

In a core drilled with water base mud, the oil volume is divided by the porosity to obtain a residual oil saturation. Similarly, a water saturation is determined but the sum of Soil + Swtr will not equal 1.00 due to evaporation of water prior to the measurement. In an oil based core, the sum of fluid volumes gives total porosity (PHIt). In both cases, coking and cracking of the oil reduces oil volume, resulting in low estimated oil saturation. Core lab companies scale the recovered oil by a factor to account for this. The scale factor (KSF) varies from about 1.08 for light oil to 1.28 for heavy oil. Final results are calculated from: 8: Swtr = (Vwtr - CBW) / PHIe 9: Soil = (Voil * KSF) / PHIePHIe is usually determined by an independent lab method from a very nearby core sample.The solvent extraction method is somewhat similar. The core sample is held in a thimble above a source of solvent, which is heated. The solvent vapour mobilizes the water, dissolves the oil, and all are condensed, recovered, and measured. The method gives an accurate water saturation, can be done as part of the core cleaning process, and is non-destructive. The method is slow and can take several days. Oil saturation is determined by an indirect method, as follows: 10: Swtr = Vwtr / PHIe 11: Voil = ((WTinit - WTdry) - Vwtr * DENSwtr) / DENSoil 12: Soil = Voil / PHIeOnly in rare cases will Soil + Swtr = 1.00 - the balance is Sgas, usually air that entered the core during transport and storage.SAMPLE CORE ANALYSIS REPORT 02181815W4R#27771780118Revised Analysis - Soil and Swtr from Original Analysis

S#TopBaseLenKmaxK90KvertPorosGrDenBkDenSoilSwtrLithology

feetfeetfeetmDmDmDfracKg/m3Kg/m3fracfrac

13499.193500.170.98370.0316.0264.00.255285023780.1290.448SS VF

23500.173501.160.98445.0425.0326.00.248268022630.1230.450SS VF

33501.163502.171.02764.0751.0231.00.248267022560.1110.520SS VF

43502.173503.160.98445.0417.0127.00.234267022790.1290.479SS VF

53503.163503.880.72479.0411.084.00.241270022900.1100.504SS VF PRY

63503.883504.570.69860.0790.0172.00.242268022730.1180.466SS VF

73504.573504.670.100.10.1SHALE

83504.673505.260.590.10.10.1510.398RUBBLE

93505.263505.490.23486.0402.0261.00.246267022590.1340.358SS VF SH INC

103505.493505.980.49355.0326.08.30.207264023010.1430.268SS VF SHBKS

113505.983506.960.98376.0192.032.20.240265022540.1310.471SS VF

123506.963507.880.92250.0245.017.60.218264022820.1560.399SS VF CARB INC

133507.883508.470.59491.00.10.10.2370.1190.389SS VF

143508.473508.870.39304.00.10.10.2190.1360.422SS VF CARB BK

153508.873509.881.02309.0288.0127.00.230285024250.1320.440SS VF

163509.883510.870.98845.0340.0135.00.237266022670.1310.323SS VF SH INC

173510.873511.881.02298.0287.075.30.218265022900.1460.422SS VF SH INC

183511.883512.870.98139.00.10.10.208265023070.1030.354SS VF

193512.873513.790.92139.00.10.10.1740.0730.418SS VF

203513.793514.380.590.10.10.0960.441RUBBLE

213514.383515.070.6965.10.10.10.2570.1190.387SS VF

223515.073515.160.100.10.1SHALE

233515.163516.181.021050.0385.0385.00.254267022460.0440.492SS VF

243516.183516.770.59385.0471.0471.00.220266022950.0420.501SS VF

253516.773517.460.69835.0183.0183.00.237267022740.0500.531SS VF CARB INC

263517.463518.280.82901.0644.0644.00.238265022570.0460.487SS VF

273518.283519.070.79438.0103.0103.00.240269022840.0790.494SS VF CARB INC

283519.073519.990.921430.0278.0278.00.251266022430.0630.501SS VF

293519.993520.580.590.10.10.0520.563RUBBLE

303520.583521.460.891050.0951.0951.00.258257021650.0550.516SS VF

313521.463522.481.02382.061.561.50.210269023350.0640.450SS M P/SCARB INC

323522.483523.470.98570.048.948.90.186268023680.0580.408SS M P/SCARB INC

333523.473524.481.020.10.10.0820.411RUBBLE

343524.483525.470.983149.0321.0321.00.209259022580.0510.391SS VF

353525.473526.481.020.10.10.0730.360RUBBLE

363526.483527.470.98285.048.818.80.170269024030.0460.481SS M P/S

373527.473528.160.69193.00.10.10.169277024710.0420.548SS M P/S CARB

383528.163528.880.720.10.10.0660.462RUBBLE

Arithmetic Averages0.78602.9228.6140.20.227267922970.0950.443

Use the oil saturation (Soil) data in this core analysis example to find the oil - water contact.