• Petroleum Reservoir Engineering Physical Properties Pdf File Size
• Applied Petroleum Reservoir Engineering
• Petroleum Reservoir Engineering Physical Properties Pdf Files

Petroleum Production. 1001 Solved Engineering Fundamentals Problems Michael Lindeburg Pdf, Editorial Team Member Journal For Petroleum Engineering And Technology 2012, Pe Preparation Course Structural By Variablepitch346, Petroleum Reservoir Engineering Physical Properties Pdf Printer Dedalcancer, D4 Petroleum Engineering.

Petrophysics (from the Greek πέτρα, petra, 'rock' and φύσις, physis, 'nature') is the study of physical and chemical rock properties and their interactions with fluids.^[1]

A major application of petrophysics is in studying reservoirs for the hydrocarbon industry. Petrophysicists are employed to help reservoir engineers and geoscientists understand the rock properties of the reservoir, particularly how pores in the subsurface are interconnected, controlling the accumulation and migration of hydrocarbons.^[1] Some of the key properties studied in petrophysics are lithology, porosity, water saturation, permeability and density. A key aspect of petrophysics is measuring and evaluating these rock properties by acquiring well log measurements – in which a string of measurement tools are inserted in the borehole, core measurements – in which rock samples are retrieved from subsurface, and seismic measurements. These studies are then combined with geological and geophysical studies and reservoir engineering to give a complete picture of the reservoir.

1. Petroleum engineering.pdf. REGIONS Output Control For a report to the PRT file use: • RPTREGS in REGIONS section • RPTSOL (FIP=1. 2 or 3) in SOLUTION section • RPTSCHED (FIP=1. 2 or 3) in SCHEDULE section For 3D viewable output use: • INIT in GRID section • RPTRST (FIP) in SCHEDULE section.
2. Reservoir simulation Petroleum Engineering Electives Integrated Reservoir Modeling High Performance Drilling Design and Operational Practices. Correlation of physical properties of petroleum reservoir fluids including laboratory and empirical methods. PVT report interpretation and application of equations of state.

While most petrophysicists work in the hydrocarbon industry, some also work in the mining and water resource industries. The properties measured or computed fall into three broad categories: conventional petrophysical properties, rock mechanical properties, and ore quality.

Petrophysical studies are used by petroleum engineering, geology, mineralogy, exploration geophysics and other related studies.

Conventional petrophysical properties[edit]

Most petrophysicists are employed (SS) to compute what are commonly called conventional (or reservoir) petrophysical properties. These are:

Lithology: A description of the rock's physical characteristics, such as grain size, composition and texture.^[2] By studying the lithology of local geological outcrops and core samples, geoscientists can use a combination of log measurements, such as natural gamma, neutron, density and resistivity, to determine the lithology down the well.

Porosity:${\displaystyle \varphi }$ (Anti=tattilization)The percentage of a given volume of rock that is pore space and can therefore contain fluids.^[3] This is typically calculated using data from an instrument that measures the reaction of the rock to bombardment by neutrons or by gamma rays but can also be derived from sonic and NMR logging.

Water saturation: The fraction of the pore space occupied by water.^[4] This is typically calculated using data from an instrument that measures the resistivity of the rock and is known by the symbol ${\displaystyle S_w}$.

Permeability: The quantity of fluid (usually hydrocarbon) that can flow through a rock as a function of time and pressure, related to how interconnected the pores are. Formation testing is so far the only tool that can directly measure a rock formation's permeability down a well.^{[citation needed]} In case of its absence, which is common in most cases, an estimate for permeability can be derived from empirical relationships with other measurements such as porosity, NMR and sonic logging.

Thickness of rock with enough permeability to deliver fluids to a well bore. This property is often called “Net reservoir rock.” In the oil and gas industry, another quantity “Net Pay” is computed which is the thickness of rock that can deliver hydrocarbons to the well bore at a profitable rate.

Reservoir models are built upon their measured and derived properties to estimate the amount of hydrocarbon present in the reservoir, the rate at which that hydrocarbon can be produced to the Earth's surface through wellbores and the fluid flow in rocks. In the water resource industry, similar models are used to compute how much water can be produced to the surface over long periods of time, without depleting the aquifer.

Rock mechanical properties[edit]

Some petrophysicists use acoustic and density measurements of rocks to compute their mechanical properties and strength. They measure the compressional (P) wave velocity of sound through the rock and the shear (S) wave velocity and use these with the density of the rock to compute the rocks' compressive strength, which is the compressive stress that causes a rock to fail, and the rocks' flexibility, which is the relationship between stress and deformation for a rock. Converted-wave analysis is also used to determine subsurface lithology and porosity.

These measurements are useful to design programs to drill wells that produce oil and gas. The measurements are also used to design dams, roads, foundations for buildings, and many other large construction projects. They can also be used to help interpret seismic signals from the Earth, either man-made seismic signals or those from earthquakes.

Ore quality[edit]

Bore holes can be drilled into ore bodies (for example coal seams or gold ore) and either rock samples taken to determine the ore or coal quality at each bore hole location or the wells can be wireline logged to make measurements that can be used to infer quality. Some petrophysicists do this sort of analysis. The information is mapped and used to make mine development plans.

Methods of analysis[edit]

Petroleum Reservoir Engineering Physical Properties Pdf File Size

Coring and core analysis is a direct measurement of petrophysical properties. In the petroleum industry rock samples are retrieved from subsurface and measured by core labs of oil company or some commercial core measurement service companies. This process is time consuming and expensive, thus can not be applied to all the wells drilled in a field.

Well Logging is used as a relatively inexpensive method to obtain petrophysical properties downhole. Measurement tools are conveyed downhole using either wireline or LWD method.

An example of wireline logs is shown in Figure 1. The first “track”, shows the natural gamma radiation level of the rock. The gamma radiation level “log” shows increasing radiation to the right and decreasing radiation to the left. The rocks emitting less radiation have more yellow shading. The detector is very sensitive and the amount of radiation is very low. In clastic rock formations, rocks that have smaller amounts of radiation are more likely to be coarser grained and have more pore space, rocks with higher amounts of radiation are more likely to have finer grains and less pore space.^[5]

The second track over in the plot records the depth below the reference point which is usually the Kelly bush or rotary table in feet, so these rocks are 11,900 feet below the surface of earth.

In the third track, the electrical resistivity of the rock is presented. The water in this rock is salty and the salt in the water causes the water to be electrically conductive such that lower resistivity is caused by increasing water saturation and decreasing hydrocarbon saturation.^[6]

The fourth track, shows the computed water saturation, both as “total” water (including the water bound to the rock) in magenta and the “effective water” or water that is free to flow in black. Both quantities are given as a fraction of the total pore space.

The fifth track shows the fraction of the total rock that is pore space, filled with fluids. The display of the pore space is divided into green for oil and blue for movable water. The black line shows the fraction of the pore space which contains either water or oil that can move, or be “produced.” In addition to what is included in blackline, the magenta line includes the water that is permanently bound to the rock.

The last track is a representation of the solid portion of the rock. The yellow pattern represents the fraction of the rock (excluding fluids) that is composed of coarser grained sandstone. The gray pattern represents the fraction of rock that is composed of finer grained “shale.” The sandstone is the part of the rock that contains the producible hydrocarbons and water.

Rock volumetric model for shaly sand formation[edit]

Symbols and Definitions:

Applied Petroleum Reservoir Engineering

The following definition and petrophysics model are a typical shaly sand formation model which assumes:1. Shale is composed of silt, clay and their bounded water which will not flow. 2. Hydrocarbon are stored only in pore space in sand matrix.

ΦT – Total porosity (PHIT), which includes the pore space in sand and shale.

Sw – Total water saturation, the fraction of the pore space occupied by water.

Φe – Effective shale corrected porosity which includes only the pore space in sand. The pore space in shale which is filled with bounded water is excluded.

Swe – Effective shale corrected water saturation. The volumetric fraction of Φe which is occupied by water.

Vsh – Volumetric fraction of shale. This includes medium to very fine silt plus clay and the shale bound water.

Φsh – Shale porosity. Volumetric fraction of pore space in shale. These pore space is filled with bounded water by definition.

Key equations:

(1-Φe-Vsh) + Vsh + Φe*Swe + Φe*(1-Swe) = 1

Sandstone matrix volume + shale volume + water volume in sand + hydrocarbon volume in sand = total rock volume

Φe = ΦT – Vsh *Φsh

See also[edit]

References[edit]

1. ^ ^abTiabb, D. & Donaldson, E.C. (2004). Petrophysics. Oxford: Elsevier. p. 1. ISBN0-7506-7711-2.
2. ^'Lithology'. Earthquake Glossary. US Geological Survey. Retrieved 29 October 2010.
3. ^'Porosity', Schlumberger Oilfield Glossary. Retrieved 12 October 2018.
4. ^'Water saturation', Schlumberger Oilfield Glossary. Retrieved 12 October 2018.
5. ^Poupon, A.; Clavier, C., Dumanoir, J., Gaymard, R., Misk, A. (1970). 'Log Analysis of Sand-Shale SequencesA Systematic Approach'. Journal of Petroleum Technology. 22 (7): 867–881. doi:10.2118/2897-PA.CS1 maint: Multiple names: authors list (link)
6. ^Brown, G. A. (June 1986). A Mathematical Comparison of Common Saturation Equations. SPWLA twenty-seventh annual logging symposium. 1986-T.

• Guéguen, Yves; Palciauskas, Victor (1994), Introduction to the Physics of Rocks, Princeton University Press, ISBN978-0-691-03452-2
• Mavko, Gary; Mukerji, Tapan; Dvorkin, Jack (2003), The Rock Physics Handbook, Cambridge University Press, ISBN978-0-521-54344-6
• Santamarina, J. Carlos; Klein, Katherine A.; Fam, Moheb A. (2001), Soils and Waves: Particulate Materials Behavior, Characterization and Process Monitoring, John Wiley & Sons, Ltd., ISBN978-0-471-49058-6
• Tiab, Djebbar; Donaldson, Erle C. Petrophysics Theory and Practice of Measuring Reservoir Rock and Fluid Transport Properties (3rd ed.). Oxford: Gulf Professional Pub. ISBN978-0-12-383848-3.
• Raquel, S.; Benítez, G.; Molina, L.; Pedroza, C. (2016). 'Neural networks for defining spatial variation of rock properties in sparsely instrumented media'(PDF). Boletín de la Sociedad Geológica Mexicana. 553. Retrieved 12 October 2018.

External links[edit]

Petroleum Reservoir Engineering Physical Properties Pdf Files

1. Yang S et al (2004) Reservoir physics. Petroleum Industry Press, BeijingGoogle Scholar
2. Sylvain JP (1958) Oil reservoir engineering. McGraw-Hill, New YorkGoogle Scholar
3. Saeid M, William AP, James GS (2006) Handbook of natural gas transmission and processing. Gulf Professional Publishing, HoustonGoogle Scholar
4. William DM (1990) The properties of petroleum fluids. Penn Well Books, OklahomaGoogle Scholar
5. Balsaraf VM (2009) Applied chemistry, vol 2. I.K. International Pvt Ltd., DelhiGoogle Scholar
6. Norman JH (1991) Dictionary of petroleum exploration, drilling and productionGoogle Scholar
7. Frank J, Mark C, Mark G (2008) Hydrocarbon exploration and production. Elsevier, AmsterdamGoogle Scholar
8. Danesh A (1998) PVT and phase behavior of petroleum reservoir fluids. Elsevier, AmsterdamGoogle Scholar
9. James GS (2011) An introduction to petroleum technology, economics, and politics. Wiley, New YorkGoogle Scholar
10. Tarek A (2009) Working guide to reservoir rock properties and fluid flow. Gulf Professional Publishing, HoustonGoogle Scholar
11. Abdus S, Ghulam MI, James LB (2008) Practical enhanced reservoir engineering: assisted with simulation software. Penn Well Books, OklahomaGoogle Scholar
12. GB/T 26979-2011 (2011) The classification of natural gas pool. General administration of quality supervision, inspection and quarantine of People’s Republic of China and national standardization administration of ChinaGoogle Scholar
13. Whitson CH, Brule MR (2000) Phase behavior. SPE monograph. J20. Society of Petroleum Engineers, RichardsonGoogle Scholar
14. Speight JG (2007) The chemistry and technology of petroleum, 4th edn. CRC Taylor & Francis Group, Boca RatonGoogle Scholar
15. Satinder C (2010) Heavy oils: reservoir characterization and production monitoring. SEG BooksGoogle Scholar
16. Enrico F (2012) Thermodynamics. Courier Corporation. ISBN 978-0-486-13485-7Google Scholar
17. William CL, Gary JP (2005) Standard handbook of petroleum and natural gas engineering. Gulf Professional Publishing, HoustonGoogle Scholar
18. He GS, Tang H (2011) Reservoir physics. Petroleum Industry Press, BeijingGoogle Scholar
19. Ye Z (2007) Principle of enhanced oil recovery. Petroleum Industry Press, BeijingGoogle Scholar
20. Marshall BS (1951) Volumetric and phase behavior of oil field hydrocarbon systems: PVT for engineers. California Research CorpGoogle Scholar
21. Bloomer OT et al (1953) Institute of Gas Technology. Research Bulletin J22Google Scholar
22. Brown OT et al (1947) Natural gas and the volatile hydrocarbon, NGAAGoogle Scholar
23. Paul G (2001) Reservoir fluid. http://docs.ma3hd.net/dtail.php?search=Paul+Glover+RESER-VOIR+FLUID&type=pdf&file=http://www2.g
24. http://iptibm1.ipt.ntnu.no/~jsg/undervisning/naturgass/parlaktuna/Chap3.pdf
25. Brown GG, Katz DL et al (1948) Natural gasoline and volatile hydrocarbons, Tulsa, OKGoogle Scholar
26. Tarek A (2010) Reservoir engineering handbook. Gulf Professional Publishing, HoustonGoogle Scholar
27. Tester JW, Modell M (1997) Thermodynamics and its applications. Prentice Hall, Englewood Cliffs. ISBN 0-13-915356-XGoogle Scholar
28. Goodstein D (1985) Critical phenomena and phase transitions. In: States of matter, 1st edn. General Publishing Company, Ltd.Google Scholar
29. Standing MB, Katz DL (1942) Density of natural gases. AIME Trans 146(01):140–149Google Scholar
30. McCain W (1990) The properties of petroleum fluids. PennWell Publishing Company, Tulsa, OK.Google Scholar
31. Trube AS (1957) Compressibility of natural gases. AIME Trans 210Google Scholar
32. He GS (2011) Reservoir physics. Petroleum Industry Press, BeijingGoogle Scholar
33. Carr NL, Kobayashi R, Burrows DB (1954) Viscosity of hydrocarbon gases under pressure. AIME Trans 264Google Scholar
34. Darrell E, Steven DG (2010) General chemistry. Cengage LearningGoogle Scholar
35. Kotyakhov FI (1958) Основы физики нефтяного пласта (Foundation of Reservoir Physics). Petroleum Industry Press, ChinaGoogle Scholar
36. Stewart M, Arnold K (2008) Gas-liquid and liquid-liquid separators. Gulf Professional Publishing, HoustonGoogle Scholar
37. Francis SM, Richard ET (1995) Oilfield processing of petroleum: crude oil. Penn Well Books, OklahomaGoogle Scholar
38. Standing MB (1981) Volumetric and phase behavior of oil hydrocarbon systems, 9th edn. SPE, DallasGoogle Scholar
39. Djebbar T, Erle CD (2011) Petrophysics: theory and practice of measuring reservoir rock and fluid transport properties. Gulf Press, HoustonGoogle Scholar
40. Dodson CR, Standing M (1944) Pressure-volume-temperature and solubility relations for natural gas-water mixtures. In: Drilling and production practice. American Petroleum InstituteGoogle Scholar
41. Muskat M (1949) Physical principles of oil production, 1st edn. Mc-Graw-Hill Book Company, Inc., New YorkGoogle Scholar
42. John JC (2010) Acid gas injection and carbon dioxide sequestration. Wiley, New YorkGoogle Scholar
43. Natural Gasoline Association of America (1957) Natural Gasoline Association of America’s (NGAA) equilibrium ratio data bookGoogle Scholar
44. Szilas AP (1986) Production and transport of oil and gas: gathering and transportation. Elsevier, AmsterdamGoogle Scholar
45. William DM (1990) The properties of petroleum fluids. Penn Well Books, OklahomaGoogle Scholar
46. Standing MB (1947) A pressure-volume-temperature correlation for mixtures of California oils and gases. Drill and Prod Prac, API (275)Google Scholar
47. Vasquez M, Beggs D (1980) Correlations for fluid physical properties prediction. JPT, June, pp 968–970Google Scholar
48. Sutton RP, Farshad FF (1984) Evaluation of empirically derived PVT properties for Gulf of Mexico crude oils. SPE paper 13172, presented at the 59th annual technical conference, Houston, Texas.Google Scholar
49. Beal C (1946) The viscosity of air, water, natural gas, crude oil and its associated gases at oil field temperatures and pressureGoogle Scholar
50. Beggs HD, Robinson JR (1975) Estimating the viscosity of crude oil systems. JPT, September, pp 1140–1141Google Scholar
51. Glaso O (1980) Generalized pressure-volume-temperature correlations. JPT, May, pp 785–795Google Scholar
52. Khan SA et al ( 1987) Viscosity correlations for Saudi Arabian crude oils. SPE 15720Google Scholar
53. Ahmed TH (1989) Hydrocarbon phase behavior. Gulf Publishing, HoustonGoogle Scholar
54. Chew J, Connally Jr (1959) A viscosity correlation for gas-saturated crude oils. Trans AIME 216:23–25Google Scholar
55. Standing MB (1977) Volumetric and phase behavior of oil field hydrocarbon systems. Dallas: Society of Petroleum Engineers, pp 125–126Google Scholar
56. William CL (2009) Working guide to reservoir engineering. Gulf Professional Publishing, HoustonGoogle Scholar
57. Petrosky GE, Farshad F (1993) Pressure-volume-temperature correlations for Gulf of Mexico crude oils. SPE Paper 26644, presented at the 68th annual technical conference of the SPE in Houston, TexasGoogle Scholar
58. McCain J, William D, Rollins et al (1988) Coefficient of isothermal compressibility of black oils at pressures below the bubblepoint. Source: SPE Formation Evaluation 3(3):659–662. ISSN: 0885923XGoogle Scholar
59. Jacques H (1988) Fundamentals of gas reservoir engineering. Elsevier, AmsterdamGoogle Scholar
60. Dake LP (1978) Fundamentals of reservoir engineering. Elsevier, AmsterdamGoogle Scholar
61. Amyx J, Bass D, Whitney R (1960) Petroleum reservoir engineering. McGraw-Hill Book Company, New YorkGoogle Scholar
62. Clark NJ (1969) Elements of petroleum reservoir. SPEGoogle Scholar