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Porosity

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- 1. Porosity • Learning Outcomes Reservoir Rocks & Fluid Properties
- 2. Porosity of Reservoir Rocks • Definition of Porosity • Classification of Porosity • Factors affecting Porosity • Applications of Porosity • Determination of Porosity Reservoir Rocks & Fluid Properties
- 3. Porosity Definition: Measure of pore space in porous media. Packing Sorting Grain Shape High Low
- 4. Reservoir Rocks & Fluid Properties
- 5. • Rock reservoir have pore that are connected and contain fluids (oil, gas, water) that can flow through the rock. • Reservoir rock looks solid to the naked eye, but a microscopic examination reveals the existence of tiny openings in the rock. • These spaces or tiny openings (typically up to 300 μm) in petroleum reservoir rocks are the one in which petroleum reservoir fluids are presents Reservoir Rocks & Fluid Properties 1 Porosity of Reservoir Rocks
- 6. Definition of Porosity • Porosity(φ) : the ratio of the pore volume in a rock to the bulk volume of that rock. Express in per cent. Mathematical form is: φ = Vp/Vb Reservoir Rocks & Fluid Properties
- 7. Porosity • Porosity is a measure of the void space in rock, hence, measures how much HC in rock • Porosity φ = Vp/Vb = (Vb-Vm)/Vb; Vb = Vp + Vm – theoretically, φ varies from 0% - 47.6% – In practice, φ varies between 3% and 37% • Porosity is a function of particle size distribution: – Framework materials (sandstone) – high φ – Interstitial materials (shaly-sand) – low φ Reservoir Rocks & Fluid Properties
- 8. Classification of Porosity Porosity can be classified into; 1. Original porosity 2. Induced porosity • Original porosity (primary) is formed during the deposition of rock materials, e.g. porosity between granular in sandstone, porosity among crystal and oolitic in limestone • Induced porosity (secondary) is developed by some geological process on the deposited rock material. E.g; Fractures, or vugs cavity usual occur in limestone (chemical reaction b/w CaCO3 and MgCl2) Reservoir Rocks & Fluid Properties
- 9. Porosity Sand grain Cement material Effective / connected porosity (25%) Ineffective Porosity (5%) Total Porosity (30%) Reservoir Rocks & Fluid Properties Deadend or cul-de- sac pore
- 10. Types of Porosity • 3 kinds porosity includes: – Effective porosity – Ineffective/ Isolated porosity – Total porosity • Effective porosity is the measure of the void space that is filled by recoverable oil and gas; or the amount of pore space that is sufficiently interconnected to yield its oil & gas for recovery. • φ = Vol. of interconnected pores + Vol. of deadend Total or bulk vol. of reservoir rock Reservoir Rocks & Fluid Properties
- 11. PORE-SPACE CLASSIFICATION • Total porosity, t = • Effective porosity, e = Total Pore Volume Bulk Volume Interconnected Pore Space Bulk Volume • Effective porosity – of great importance; contains the mobile fluid
- 12. COMPARISON OF TOTAL AND EFFECTIVE POROSITIES • Very clean sandstones : e t • Poorly to moderately well -cemented intergranular materials: t e • Highly cemented materials and most carbonates: e < t
- 13. Types of Porosity • Ineffective porosity is the ratio of the volume of isolated or completely disconnected pores to the total or bulk volume • φ = Vol. of completely disconnected pores Total or bulk volume • Total or absolute porosity is the ratio of the entire void spaces in the reservoir rock to the bulk volume of the rock • φ = Vol. of interconnected + Vol. of deadend or cul-de-sac pores + Vol. of isolated pore Total or bilk volume Reservoir Rocks & Fluid Properties
- 14. Applications of Porosity • What is the significance Porosity in engineering reservoir? • From the reservoir engineering point of view, porosity is probably one of the most important reservoir rock properties and its quantitative value is used in all reservoir engineering calculations ‘cos it represents the pore spaces that’s occupied by mobile fluids. • For common reservoir rock types, under average operating conditions, porosity values ranges; Porosity % 25~20 20~15 15~10 10~5 5~0 Reservoir Rocks & Fluid Properties Grade Very good good moderate poor no value Evaluating formation
- 15. Applications of Porosity Porosity data are used in these basic reservoir evaluations: 1. Volumetric calculation of fluids in the reservoir 2.Calculation of fluid saturations 3.Geological characterization of the reservoir Calculating hydrocarbon in a reservoir HCPV = Area x Thickness x φ x (1 – Sw) where: A = surface area of the reservoir h = thickness of the formation φ = porosity Swi= the percent of the pore volume occupied by the water Reservoir Rocks & Fluid Properties
- 16. Various packing of spheres: cubic & rhombohedral Reservoir Rocks & Fluid Properties cubic packing of spheres resulting in a least-compact arrangement with a porosity of 47.64% Rhombohedral packing of spheres resulting in a most-compact arrangement with a porosity of 26% Spherical size variation influences type & volume of solid porosity Porosity 36% Porosity 20% Effect of cement material
- 17. FACTORS THAT AFFECT POROSITY PRIMARY • Particle sphericity and angularity • Packing • Sorting (variable grain sizes) SECONDARY (DIAGENETIC) • Cementing materials • Overburden stress (compaction) • Vugs, dissolution, and fractures
- 18. Porosity Measurements • From definition of porosity, porosity of rock sample can be determined by measuring any two of these quantities: bulk volume pore volume grain volume • Sources of Porosity data: Core analysis – direct measurement Well logging analysis Well testing indirect measurement Reservoir Rocks & Fluid Properties
- 19. Porosity • Porosity from loggings: Sonic log t t 1 t Dt = sonic travel time recorded by log m f Dtm = sonic travel time for the matrix mineral grains (w/o porosity), (55, 47 and 43 microsec/ft for quartz, limestone and dolomite, respectively) Dtf = sonic travel time for fluid in the pore space = porosity, fraction Reservoir Rocks & Fluid Properties Density log b m f 1 b = bulk density recorded by log m = density of the matrix mineral grains (w/o porosity), (2.65, 2.71 and 2.87 gm/cc for quartz, limestone and dolomite, respectively) f = density of the fluid in the pore space
- 20. Determination of Porosity • Several methods: involves only the determination of two out of 3 (Vp, Vm, & Vb) • Bulk volume by the following methods – Coated sample immersed in water, or – Water-saturated sample immersed in water, or – Dry sample immersed in Hg method (no more Hg in the labs) • Grain volume: by Melcher- Nutting method in which the sample is crushed and its volume measured with a pychnometer Reservoir Rocks & Fluid Properties
- 21. Laboratory Measurement of Porosity • Under laboratory the following are measured; • Vp, pore volume directly measured indirectly • Vb, bulk volume directly measured indirectly • Porosity measurement – Vb, bulk volume directly measured Reservoir Rocks & Fluid Properties • Direct measure, Vb Common shaped sample (cylinder, or cubic) measured the dimensions and consider bulk volume A L
- 22. Porosity • Measurement of Vb, Irregular & regular sample shapes A L Two means explained here; - volumes faulted (volumetrically) - methodologies gravity (gravimetrically) To use above method must prevent fluid Reservoir Rocks & Fluid Properties penetration into the pore sample by: - coating with wax - saturating the core with same fluid - using mercury
- 23. Porosity • Measurement of Vb , Mercury volume displacement by the rock sample when completely immersed in the liquid Reservoir Rocks & Fluid Properties Hg Mercury volume addition after core sample is included in mercury is bulk volume.
- 24. Porosity • Measurement Vb , • Gravity method Reservoir Rocks & Fluid Properties Hg scale Scale A B A Wtk = dry core weight Wthg = mercury weight B Wtb = mercury weight and core that forced inside mercury Mercury weight faulted = (Wtb - (Wtk + Wthg)) Mercury volume faulted = Mercury weight faulted mercury density Core bulk volume = Mercury volume faulted
- 25. Porosity Porosity measurement • Vp, pore volume determination Fluid saturation inside rock Wtk = dry sample weight Wtt = saturated sample weight fluid Wtf = fluid weight in pore Reservoir Rocks & Fluid Properties = Wtt - Wtk H Vp = (Wtt - Wtk)/f 2O
- 26. Porosity • Determination of Vp details using Boyle’s Law Reservoir Rocks & Fluid Properties Helium tank Cylinder sample steel line sample P3 V3 T1 P1 V1 = P3 V3 V3 = V1 + Vl + Vs -Vc - Vg P1 V1 T1
- 27. Porosity • Determination of Vp details using Boyle’s Law P1 V1 = P2 V2 V2 = V1 + Vl + Vs – Vc V1 + Vl + Vs - Vc = V2 = (P1 V1 )/ P2 P1 V1 = P3 V3 V3 = V1 + Vl + Vs - Vc - Vg Vg = V1 + Vl + Vs - Vc - V3 Vg = (P1 V1 )/ P2 - (P1 V1 )/ P3 Vp = Vb - Vg Reservoir Rocks & Fluid Properties = Vp / Vb = (Vb - Vg)/ Vb V1 = Volume of cylinder helium reference in P1 & T1 Vl = Connector tube volume cylinder helium reference to cylinder sample Vs = Volume of empty cylinder sample Vc = Volume of cakra steel Vg = Volume of core sample
- 28. Uses of Porosity • Basic use is to calculate volumetrically the quantity of hydrocarbon (HC) in the rock – N = 7758 X As X H X φ X Soi – N= HC volume in the reservoir, res.bbl – As = surface area, acres – H= thickness of formation, ft – φ = porosity, fraction – Soi = initial oil saturation (1.0 – Swi), fraction • If N is divided by Bo, we will get the volume on surface. Since oil shrinks as it comes to the surface due to gas coming out, (Nsurface < Nreservoir) Reservoir Rocks & Fluid Properties
- 29. Example 1.1 – Porosity Calculation Determination of Vb – Coating Method • A = mass dry sample in air = 20.0 gm • B = mass dry sample coated with paraffin = 20.9 gm Sgparaffin = 0.9 • C = mass of coated sample immersed in H2O at 40oF = 10 gm (Sgwater= 1.0) • Mass of paraffin = B – A = 20.9 – 20.0 = 0.9 gm • Volume of paraffin = 0.9/0.9 = 1 cc • Mass of water displaced = B – C = 20.9 – 10.0 = 10.9 gm • Vol. of water displaced = mass of water/ρ of water = 10.9/1.0 = 10.9 cc • Bulk volume = volume of water displaced – volume paraffin • = 10.9 – 1.0 = 9.9 cc • Bulk volume of rock = 9.9 cc
- 30. Example 1.2 – Porosity Calculation • From Example 1.1 • Mass of dry sample in air = 20 gm • Bulk volume of sample = 9.9 cc • Grain volume of sample = (mass of dry sample in air)/ (sand-grain density) • = 20/2.67 = 7.5 cc • Total porosity = Øt = [(bulk vol. – grain vol.)/bulk volume] x 100 • = [(9.9 – 7.5)/9.9] x 100 = 24.2 per cent
- 31. Example 3 • A clean and dry core sample weighting 425g was 100% saturated with a 1.07 specific gravity brine. The new weight is 453g. The core sample is 12 cm long and 4 cm in diameter. Calculate the porosity of the rock sample. SOLUTION: The bulk volume of the core sample is: Vb = π(r)2 (12) = 150.80 cm3 The pore volume is: Vp = 1/џ (Vwet - Vdry) = 453 – 425 = 26.17 cm3 1.07 Reservoir Rocks & Fluid Properties
- 32. Cont… • Then; • Porosity of the core is: φ = Vp/Vb = 26.17 = 0.173 or 17.3% 150.80 Reservoir Rocks & Fluid Properties
- 33. Transform of lab porosity to formation porosity • φ =φ e−CPΔP • ΔP ：effective overburden pressure change • P C ：rock compressibility • φ：lab porosity Reservoir Rocks & Fluid Properties

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