Difference between revisions of "User:Rizqi Fadlilah/Sandbox"

Revision as of 17:04, 30 June 2015

PREFACE

Reservoir rock have many lithologies like sandstones, limestones, granitic, tuff, and shale. Reservoir filled by hydrocarbon on fracture or pores. All reservoir hydrocarbon content connate water . some reservoir content connate water in the micropore that content 10-60% from the pores volume.

Information about scale factor needed to conceptualized reservoir. Scale factor can differences by microscopic; relates to pores and sand grains, macroscopic; relates to conventional core-plug scale, megascopic relates to the scale of grid-blocks in simulation models, and gigascopic relates to regional scale.

Homogeneity and heterogeneity

Homogeneity factor consist uniform material. Homogeneity factor is similar depositional environment, grain distribution is relatively similar, and similar kind of intensity diagenesa. While the heterogeneity factors is changes in depositional environment, sedimentary material, grain size distribution, and facies, also different type and intensity of diagenesis processes.

Pore structure and geometry

Pore structure varies with the size, shape, and composition of natural grains, as well as fractures. Geometry ranging from <1 micron to 100 micron . Pore characteristic will determine oil recovery method.

Reservoir pressure

Fluid in reservoir have hydrostatic pressure that associated reservoir system. Pressure from overburden rock also press the pore and increase the fluid pressure.

Temperature reservoir

Temperature at some depth comes from gradient geothermal and it is directly proportional to the depth.

Reservoir boundary

Reservoir bounded by impermeable layers and fluid contact. Field boundaries is ensured through the well but based on well data; electric logs, well flow testing, and repeat formation tester (RFT). Boundary of water and hydrocarbon zones is reduced gradually. This saturation interval resulted in the transition zone. This zone is used as perforation zone in production well.

Physical properties of rocks

Porosity (Phi) 5, permeability (k) mD, fluid saturation (S) %, capiler pressure (Pc) Psi, compressibility (C) Psi^-1, resistivity (R) ohm.

Porosity

Porosity is the amount of free space compared to the bulk volume of rock. Porosity affects the ability of the rock to keep the fluid inside the pores of the rock. The pores can be interconnected and isolated. The pores are interconnected referred to as the effective porosity. Total porosity of rock is a combination of pore volume and pore volume isolated interconnected. While porosity very small called microporosity. Connate water is stored in this microporosity.

Formula for absolute porosity $\phi _{ab}={\frac {{\text{Volume}}\ text{of}\ text{total}\ text{pores}}{{\text{Total}}\ text{rocks}\ text{volume}}}$

Formula for effective porosity $\phi _{t}ext{eff}={\frac {{\text{Volume}}\ text{of}\ text{interconnected}\ text{pores}}{{\text{Total}}\ text{volume}\ text{of}\ text{rocks}}}$

Pore distribution inside the reservoir rocks

Permeability

Permeability is the ability of the rock to drain fluid (hydraulic conductivity) through the pores of the rock. The bigger the pore throat more easily drain the fluid. Unit permeability is miliDarcy.

Absolute permeability (Ka)

Absolute permeability retrieved from conventional core analysis or by the approach through equations based on log analysis. Empirical equation that can be used is :

Effective permeability (Kef)

Measurements can be made directly at the reservoir scale well test analysis. Direct measurement is only valid on the condition that a constant fluid saturation. In the analysis of special core analysis laboratory with a known value of relative permeability. Relative permeability equation for Corey Model is:

With effective permeability is : ${\text{K}}_{t}ext{ef}={{\text{K}}_{t}ext{r}\times {\text{K}}_{t}ext{a}}$

Fluid saturation (S)

A fraction of the level of pore space is filled by a fluid. ${\text{S}}_{t}ext{f}{\text{(fraksi)}}=frac{{\text{V}}_{t}ext{v}}{{\text{V}}_{t}ext{p}}$

Capillarity

Capillarity is the power of pressure between the two types of fluid immissicible. Based on capillarity power will be able to determine the level of the fluid content wettability of rock. The cut off limit wettability is θ = 90°.

@@ Line 1: / Line 1: @@
-<big>'''<big>Preface</big><big></big>'''</big><big></big>
-Coal Bed Methane (CBM) is unconventional natural gas which come from coal. CBM can be used as energy alternative beside hidrocarbon. Coal that used as source CBM provides 25% world energy. CBM resources predicted about 9000 TCF, mainly in North America (3000 TCF) and other country former Soviet Union (4000 TCF).
+'''PREFACE'''<big><big><big></big></big></big>
-	CBM fistly used around coal mining. Coal mines can simultaneoustly produce methane and consume it by generating electricity. The electricty can be used to operate many instrument in around coal mining. Then electicity from CBM can be selling to power supplier for cost recovery in coal mines.
-==Origin of Coal==
+Reservoir rock have many lithologies like sandstones, limestones, granitic, tuff, and shale. Reservoir filled by hydrocarbon on fracture or pores. All reservoir hydrocarbon content connate water . some reservoir content connate water in the micropore that content 10-60% from the pores volume.
-[[File:Figure_1_sequence_coalification.JPG|200px|thumb|right|Figure 1 Sequence Coalification. Adopted from Carlson<ref>Carlson et al. 2008. ''Physical Geology: Earth Revealed''. New York: The McGraw-Hill Companies.</ref>]]
-Coal is sedimentary rock which rich organic material that compaction with coalification process. Coal construct in environment with low oxygen content, such as swamp or bogs. Coal easily known because has black colour. Furthermore, if saw under microschope will be seen remain plant that not fully decay, such as leaves and root.
-Initially coal formation construct when acumulation plant remains with an-oxic condition, so plant can not decaying. The environment that poor with oxygen is swamp. Instead, the plants are attacked by bacteria that partly decompose th organic material and liberate oxygen and hydrogen. When that elemen come out, the percentage of carbon increase. Bacteria cannot fully decompose organic material because they are destroyed by acids liberated from plants.<ref>Lutgens et al. 2012. ''Essential of Geology''. USA: Pearson Prentice Hall</ref>
+Information about scale factor needed to conceptualized reservoir.  Scale factor can differences by microscopic; relates to pores and sand grains, macroscopic; relates to conventional core-plug scale, megascopic relates to the scale of grid-blocks in simulation models, and gigascopic relates to regional scale.
-Plant remains acumulation built a peat which plant material easily known. Then peat slowly change to lignite (brown coal), which is early stage of coal formation. Because burial condition, it make pressure and temperature increase. This increases make chemical reaction, this reaction making coal losing water and gas and increasing carbon concentration. Lignite then become bituminus coal which have higher carbon concentration. If pressure and temperature increase coal bituminus become antracite, black coal with higest carbon concentration.
+==Homogeneity and heterogeneity==
+Homogeneity factor consist uniform material. Homogeneity factor is similar depositional environment, grain distribution is relatively similar, and similar kind of intensity diagenesa. While the heterogeneity factors is changes in depositional environment, sedimentary material, grain size distribution, and facies, also different type and intensity of diagenesis processes.
-Coal classified by degree of coalification (increasing organic carbon content) in terms coal rank (Table 1). Lignite and sub bituminus are low rank coal with low carbon content. Bituminus is midde rank and the higgest rank coal are known as antracite which has highest carbon concentration. <ref>Nichols, Gary. 2009. ''Sedimentology and Stratigraphy''. United Kingdom: A John Wiley & Son, Ltd</ref>
+==Pore structure and geometry==
-[[File:Table 1 carbon and gas content in coal.JPG|600px|thumbnail|center|Table 1 Carbon ang gas Content In Coal. Adapted from Carlson<ref>Carlson et al. 2008. ''Physical Geology: Earth Revealed''. New York: The McGraw-Hill Companies.</ref>]]
+Pore structure varies with the size, shape, and composition of natural grains, as well as fractures. Geometry ranging from <1 micron to 100 micron . Pore characteristic will determine oil recovery method.
-==Gas in CBM==
+==Reservoir pressure==
-Most CBM has been produced by microbial, thermal, or possibly catalytic degradation of organic material present in coal. CBM is mainly composed of methane (CH4) with variable additions of carbon dioxide (CO2), elemental nitrogen (N2), and heavier hydrocarbon, such as ethane (C2H6), and trace of propane (C3H8) and butanes (C4H10).<ref>Thakur et al. 2014. ''Coal Bed Methane – from Prospect to Pipeline''.Elsevier</ref>
-==CBM Storage==
+Fluid in reservoir have hydrostatic pressure that associated reservoir system. Pressure from overburden rock also press the pore and increase the fluid pressure.
-Trap mecanism of CBM different with gas conventional. In gas conventional, gas trap in porosity of rock. But in CBM, methane trap in microporosity of coal. This microporosity have capasity to store gas six times more than conventional gas. This microporosity created when coal began coalification process. When temperature and pressure of coal increase, matrix in coal decrease create micro pore that trap methane. The increase fracture also making fracture or cleats in coal, so making permeability in coal (Figure 2).
-[[File:Figure 2 trap mechanism.JPG|500px|thumbnail|center|Figure 2 Trap Mechanism. Adapted from Al-Jubari<ref>Al-Jubary et al. 2009. ''Oilfield Review Summer 2009''.21: Schlumberger</ref>]]
-==CBM Production==
+==Temperature reservoir==
-Methane which trapped in microporosity can be production by dewatering. Dewatering is process to displace methane with using water. Methane pulled to well bore with decreasing formation pressure. Water than moving into well bore with methane inside of water. And then water and methane separated, methane will be save in storage and water will be injected again to subsurface. CBM has slow rate production. To increase production usually stimulated with hidrolic fracture to increase permeability of coal (Figure 3).
-[[File:Figure 3 cbm production.JPG|500px|thumbnail|center|Figure 3 Coal Bed Methane Production. Adapted from Al-Jubari<ref>Al-Jubary et al. 2009. ''Oilfield Review Summer 2009''.21: Schlumberger</ref>]]
-==Future CBM==
+Temperature at some depth comes from gradient geothermal  and it is directly proportional to the depth.
-CBM in future has many economic potential. It can be used to generate electricity. Not only around the coal mining site but also can be pipelined for utility and industrial use. Electricity can be selling to power supplier to be piped to other town. Some of CBM potential is already realized.
+==Reservoir boundary==
-==References==
+Reservoir bounded by impermeable layers and fluid contact. Field boundaries is ensured through the well but based on well data; electric logs,  well flow testing, and repeat formation tester (RFT). Boundary of water and hydrocarbon zones is reduced gradually. This saturation interval resulted in the transition zone.  This zone is used as perforation zone in production well.
-{{Reflist}}
-==Source==
+==Physical properties of rocks==
-Al-Jubary et al. 2009. ''Oilfield Review Summer 2009''. 21: Schlumberger.
-Carlson et al. 2008. ''Physical Geology: Earth Revealed''. New York: The McGraw-Hill Companies.
+Porosity (Phi) 5, permeability (k) mD, fluid saturation (S) %, capiler pressure (Pc) Psi, compressibility (C) Psi^-1, resistivity (R) ohm.
-Iskhakov, Ruslan. 2013. ''Coal Bed Methane''. Publised on http://large.stanford.edu/. Accesed June 28th, 2015.
+==Porosity==
+Porosity is the amount of free space compared to the bulk volume of rock. Porosity affects the ability of the rock to keep the fluid inside the pores of the rock. The pores can be interconnected and isolated. The pores are interconnected referred to as the effective porosity. Total porosity of rock is a combination of pore volume and pore volume isolated interconnected. While porosity very small called microporosity. Connate water is stored in this microporosity.
-Lutgens et al. 2012. ''Essential of Geology''. USA: Pearson Prentice HallTM.
+Formula for absolute porosity
+<math>\phi_{ab} = \frac{\text{Volume} \ text{of} \ text{total} \ text{pores}}{\text{Total} \ text{rocks} \ text{volume}}</math>
-Nichols, Gary. 2009. ''Sedimentology and Stratigraphy''. United Kingdom: A John Wiley & Son, Ltd.
+Formula for effective porosity
+<math>\phi_text{eff} = \frac{\text{Volume} \ text{of} \ text{interconnected} \ text{pores}}{\text{Total} \ text{volume} \ text{of} \ text{rocks}}</math>
+[[File:Pore distribution.png|400px|thumbnail|center|Pore distribution inside the reservoir rocks]]
-Thakur et al. 2014. ''Coal Bed Methane – from Prospect to Pipeline''. Elsevier
+==Permeability==
+Permeability is the ability of the rock to drain fluid (hydraulic conductivity) through the pores of the rock. The bigger the pore throat more easily drain the fluid. Unit permeability is miliDarcy.
+* Absolute permeability (Ka)
+Absolute permeability retrieved from conventional core analysis or by the approach through equations based on log analysis. Empirical equation that can be used is :
+[[File:Formula1.jpg|250px|thumbnail|center]]
+* Effective permeability (Kef)
+Measurements can be made directly at the reservoir scale well test analysis. Direct measurement is only valid on the condition that a constant fluid saturation. In the analysis of special core analysis laboratory with a known value of relative permeability. Relative permeability equation for Corey Model is:
+[[File:Formula2.jpg|250px|thumbnail|center]]
+With effective permeability is : <math>\text{K}_text{ef} = {\text{K}_text{r} \times \text{K}_text{a}}</math>
+==Fluid saturation (S)==
+A fraction of the level of pore space is filled by a fluid.<math>\text{S}_text{f} \text{(fraksi)} = frac{\text{V}_text{v}}{\text{V}_text{p}}</math>
+==Capillarity==
+Capillarity is the power of pressure between the two types of fluid immissicible. Based on capillarity power will be able to determine the level of the fluid content wettability of rock. The cut off limit wettability is θ = 90°.