Rock & Fluid Properties
The rock and fluid properties behind every reservoir calculation: core analysis, porosity and compressibility, permeability and Darcy's law, permeability averaging and heterogeneity, saturation and Archie's law, wettability, capillary pressure, relative permeability, oil, gas and water properties, tight and shale rock, rock mechanics, and special core analysis with rock typing.
PET-250 Year 2 3 credits 12 lessons · 3 h 49 min ▶ Video lessons coming soon
Offered by HSM University · Petroleum Engineering
This is the Canadian version of this course. See the American version.
What you'll learn
- Describe the core analysis workflow from coring to reservoir model, and calculate bulk volume, pore volume, porosity, grain density and fluid saturations from routine plug measurements.
- Distinguish total, effective, primary and secondary porosity, calculate porosity from a helium Boyle's law test, and explain pore volume compressibility.
- Apply Darcy's law to linear and radial flow, calculate permeability from laboratory gas tests, and apply the Klinkenberg correction.
- Average permeability for flow along and across layers and in radial systems, and quantify heterogeneity with the Dykstra-Parsons coefficient.
- Calculate formation factor and water saturation with Archie's equations, and determine the constants a, m and n from core electrical measurements.
- Explain interfacial tension, contact angle and wettability, and interpret Amott-Harvey and USBM wettability tests.
- Relate capillary pressure to pore throat size and height above the free water level, convert laboratory data to reservoir conditions, and apply the Leverett J-function.
- Describe relative permeability curves, fit Corey and Brooks-Corey models, and use fractional flow and mobility ratio to predict waterflood performance.
- Calculate oil and gas formation volume factors, solution gas-oil ratio and fluid compressibility from correlations and PVT data, and convert between reservoir and stock-tank volumes.
- Explain how pore size, adsorption, gas slip and stress sensitivity change rock property measurement and flow in tight and shale reservoirs.
- Calculate vertical stress, Biot effective stress and minimum horizontal stress, and explain how depletion changes stress and permeability.
- Select samples for special core analysis, apply quality control checks to core data, and classify rock types with flow zone indicator and Winland r35 methods.
Course content
12 lessons · 3 h 49 min total · final exam
- 1 Reservoir rock properties and core analysis 23 min · quiz
- 2 Porosity: types, measurement and compressibility 19 min · quiz
- 3 Permeability and Darcy's law 19 min · quiz
- 4 Averaging permeability and reservoir heterogeneity 19 min · quiz
- 5 Fluid saturation and Archie's law 18 min · quiz
- 6 Wettability and interfacial tension 18 min · quiz
- 7 Capillary pressure and transition zones 19 min · quiz
- 8 Relative permeability 18 min · quiz
- 9 Reservoir fluid properties 19 min · quiz
- 10 Tight and shale reservoirs 19 min · quiz
- 11 Rock mechanics for reservoir engineers 20 min · quiz
- 12 Special core analysis, data quality and rock typing 18 min · quiz
- E Final exam 20 questions
Requirements
Recommended background. You can start any course at any time.
Description
The rock and fluid properties behind every reservoir calculation: core analysis, porosity and compressibility, permeability and Darcy's law, permeability averaging and heterogeneity, saturation and Archie's law, wettability, capillary pressure, relative permeability, oil, gas and water properties, tight and shale rock, rock mechanics, and special core analysis with rock typing.
Part of the Engineering stream, typically taken in year 2.