Changes

==Summation of fluids method==

==Summation of fluids method==

[[Porosity]] and fluid saturations are usually determined by the ''summation of fluids method''<ref name=pt05r82>Jenkins, R. E., 1987, Typical core analysis of different formations, in Bradley, H. B., ed., Petroleum Engineering Handbook: Richardson, TX, Society of Petroleum Engineers.</ref>. This inexpensive and rapid procedure determines sample bulk volume and fluid volumes in the pore system. Total fluid volume is considered to be the pore volume. These data permit estimation of porosity and individual fluid saturations<ref name=pt05r9 />).

[[Porosity]] and fluid saturations are usually determined by the ''summation of fluids method''<ref name=pt05r82>Jenkins, R. E., 1987, Typical core analysis of different formations, in Bradley, H. B., ed., Petroleum Engineering Handbook: Richardson, TX, Society of Petroleum Engineers.</ref>. This inexpensive and rapid procedure determines sample bulk volume and fluid volumes in the pore system. Total fluid volume is considered to be the pore volume. These data permit estimation of porosity and individual fluid saturations<ref name=pt05r9 />).

==Residual fluid saturation==

==Residual fluid saturation==

At depth, reservoir rock contains some combination of liquid and gaseous hydrocarbons and water. The exact fluids present and their relative abundance depends on the type of reservoir (gas, condensate, or oil) and the degree to which it is charged. The fluid distribution at or near the surface is quite different from that under reservoir conditions. These changes are due to drilling processes, gas expansion, and handling errors<ref name=pt05r22>Bass, D. M., 1987, Properties of reservoir rocks, in Bradley, H. B., ed., Petroleum Engineering Handbook: Richardson, TX, Society of Petroleum Engineers.</ref><ref name=pt05r38 />.

At depth, reservoir rock contains some combination of liquid and gaseous hydrocarbons and water. The exact fluids present and their relative abundance depends on the type of reservoir (gas, condensate, or oil) and the degree to which it is charged. The fluid distribution at or near the surface is quite different from that under reservoir conditions. These changes are due to drilling processes, gas expansion, and handling errors<ref name=pt05r22>Bass, D. M., 1987, Properties of reservoir rocks, in Bradley, H. B., ed., Petroleum Engineering Handbook: Richardson, TX, Society of Petroleum Engineers.</ref><ref name=pt05r38 />.

Water saturations determined on sidewall cores from gas condensate zones are generally 10 to 15% higher than values from conventional cores. In oil zones, the water saturation from sidewall cores may be 5 to 10% higher relative to conventional core values (Figure 1).

Water saturations determined on sidewall cores from gas condensate zones are generally 10 to 15% higher than values from conventional cores. In oil zones, the water saturation from sidewall cores may be 5 to 10% higher relative to conventional core values ([[:file:overview-of-routine-core-analysis_fig1.png|Figure 1]]).

 

[[file:overview-of-routine-core-analysis_fig1.png|thumb|{{figure number|1}}Comparison of water saturation data<ref name=pt05r82 /> from sidewall and conventional cores shows that sidewall core values are almost always higher than conventional core values. Sample values from gas condensate zones are 10 to 15% higher, while values from oil zones are 5 to 10% higher.]]

 

The agreement between sidewall and conventional core residual oil saturations varies with oil characteristics. When oil gravity is in the range of 35° to 40° API, sidewall core oil saturation values are slightly lower than those obtained by conventional core analysis. As oil gravity and viscosity increase, sidewall core oil saturations become 10 to 20% lower than conventional core saturations<ref name=pt05r38 />. In gas condensate zones, sidewall cores have measured oil saturations that are equal to or a few percent higher than conventional core values (Figure 2).

[[file:overview-of-routine-core-analysis_fig2.png|thumb|{{figure number|2}}Comparison of saturation data<ref name=pt05r82 /> indicate that sidewall cores from gas condensate zones may have measured oil saturation values that are 2% higher than conventional core samples. In oil zones the relationship is less clear. The agreement between oil saturation values In sidewall and conventional cores may vary with such oil characteristics as API gravity.]]

The agreement between sidewall and conventional core residual oil saturations varies with oil characteristics. When oil gravity is in the range of 35° to 40° API, sidewall core oil saturation values are slightly lower than those obtained by conventional core analysis. As oil gravity and viscosity increase, sidewall core oil saturations become 10 to 20% lower than conventional core saturations<ref name=pt05r38 />. In gas condensate zones, sidewall cores have measured oil saturations that are equal to or a few percent higher than conventional core values ([[:file:overview-of-routine-core-analysis_fig2.png|Figure 2]]).

==Porosity==

==Porosity==

In samples having a porosity greater than 30%, sidewall core porosity is 1 to 2% lower than conventional analysis porosity. This results from slight compaction that occurs during coring. Medium and low porosity percussion sidewall samples, especially from highly cemented rocks, display porosity that is much too high due to fracturing and grain shattering. The deviation between measured porosity and true porosity becomes greater as the actual porosity decreases. Uncertainty caused by systematic variation in sidewall core porosity relative to plug analysis values can be minimized by development of correlations between sidewall core and conventional core values<ref name=pt05r38 />. (For more on porosity, see the chapter on “Porosity” in Part 5.)

In samples having a porosity greater than 30%, sidewall core porosity is 1 to 2% lower than conventional analysis porosity. This results from slight compaction that occurs during coring. Medium and low porosity percussion sidewall samples, especially from highly cemented rocks, display porosity that is much too high due to fracturing and grain shattering. The deviation between measured porosity and true porosity becomes greater as the actual porosity decreases. Uncertainty caused by systematic variation in sidewall core porosity relative to plug analysis values can be minimized by development of correlations between sidewall core and conventional core values<ref name=pt05r38 />. (For more on porosity, see the chapter on “Porosity” in Part 5.)

==[[Permeability]]==

==[[Permeability]]==

Whole core permeability can be reduced by as much as 50 to 80% by the invasion of drilling mud solids into the pore system or the build-up of powdered rock on the core surface. The relative reduction in permeability appears to decrease as the actual value decreases. Whole core samples may require sand blasting prior to permeability measurement to deal with the surficial buildup of powdered rock. No method is available to address the permeability reduction caused by drilling mud fines that have penetrated the pore system. These fines may cause whole core permeability to be significantly lower than conventional permeability. Plug samples from the center of the core do not suffer from surface plugging, and the effects of drilling fines invasion is minimized<ref name=pt05r90 />.

Whole core permeability can be reduced by as much as 50 to 80% by the invasion of drilling mud solids into the pore system or the build-up of powdered rock on the core surface. The relative reduction in permeability appears to decrease as the actual value decreases. Whole core samples may require sand blasting prior to permeability measurement to deal with the surficial buildup of powdered rock. No method is available to address the permeability reduction caused by drilling mud fines that have penetrated the pore system. These fines may cause whole core permeability to be significantly lower than conventional permeability. Plug samples from the center of the core do not suffer from surface plugging, and the effects of drilling fines invasion is minimized<ref name=pt05r90 />.

Low permeability, hard formations (''k'' k > 20 md), friable, or unconsolidated sandstones are usually reduced by 60% or more over those measured on conventional core plug (Figure 3). Partial blocking of the pore system by drilling mud solids and by compression and grain movement resulting from bullet impact are responsible<ref name=pt05r155 />. (For details of calculating permeability form core samples, see “Permeability” in Part 5.)

Low permeability, hard formations (''k'' k > 20 md), friable, or unconsolidated sandstones are usually reduced by 60% or more over those measured on conventional core plug ([[:file:overview-of-routine-core-analysis_fig3.png|Figure 3]]). Partial blocking of the pore system by drilling mud solids and by compression and grain movement resulting from bullet impact are responsible<ref name=pt05r155 />. (For details of calculating permeability form core samples, see “Permeability” in Part 5.)

 

==See also==

==See also==