Abstract: Systems and methods include a computer-implemented method for determining relative productivity. A thorium-uranium ratio for a region of interest is determined by a diagenesis-calibrated rock quality (DCRQ) system using exploration and production (E&P) data. A percentage of siltstone in a lithology matrix for the region of interest is determined using the E&P data. A difference between a neutron porosity and a sandstone density porosity for the region of interest is determined using the E&P data. A rock testability index for the region of interest is determined. Relative productivity for the region of interest is determined using i) the thorium-uranium ratio, ii) the percentage of siltstone in the lithology matrix, iii) the difference between the neutron porosity and the sandstone density porosity, and iv) the rock testability index. Drilling parameters for use in upcoming drilling operations for wells in the region of interest are determined using the relative productivity.

Abstract: Systems and methods include a method for determining perforation cluster points of a reservoir. A rock type of a geological formation of a reservoir is determined using petrophysical data. The transmissible sublayers of the reservoir are determined by grouping the petrophysical data into different subset transmissible layers based on cut-off criteria. Net transmissible reservoir footage for the transmissible sublayers are generated based on averages of parameters for minimum and maximum measured depths. Potential stages for the reservoir are determined using a conditional formatting on the transmissible reservoir footage. Potential perforation cluster points selected based on the potential stages for the reservoir are received from input of an engineer.

Abstract: Systems and methods include a method for determining perforation cluster points of a reservoir. A rock type of a geological formation of a reservoir is determined using petrophysical data. The transmissible sublayers of the reservoir are determined by grouping the petrophysical data into different subset transmissible layers based on cut-off criteria. Net transmissible reservoir footage for the transmissible sublayers are generated based on averages of parameters for minimum and maximum measured depths. Potential stages for the reservoir are determined using a conditional formatting on the transmissible reservoir footage. Potential perforation cluster points selected based on the potential stages for the reservoir are received from input of an engineer.

Abstract: Methods for determining a rock testability index (RTI) include receiving petrophysical data of a geological formation at a particular rate. The petrophysical data is measured at each depth of a plurality of depths from a surface of the Earth. For each depth of the plurality of depths, an RTI is determined for the geological formation. The RTI indicates a probability of success for performing a hydrocarbon fluid formation test at each depth. The RTI is generated by normalizing a rock type of the geological formation. The RTI is adjusted based on a correspondence of the petrophysical data to hydrocarbon productivity. A display device generates a visual representation of the RTI at the particular rate. The visual representation indicates a potential hydrocarbon productivity of the geological formation.

Abstract: A downhole gas detection tool includes a housing; a first test module that includes a first fluid test chamber operable to fluidly couple to an annulus of a wellbore to receive a first portion of a wellbore fluid, the first test module further including an acoustic fluid sensor to measure a fluid acoustic velocity and attenuation of the first portion of the wellbore fluid received in the first fluid test chamber, and a fluid resistivity sensor to measure a fluid resistivity of the first portion of the wellbore fluid received in the first fluid test chamber; and a second test module including a second fluid test chamber operable to fluidly couple to the annulus of the wellbore to receive a second portion of the wellbore fluid, and a pressure-temperature (PT) sensor to measure at least one of a pressure or a temperature of the second portion of the wellbore fluid.

Abstract: A downhole gas detection tool includes a housing; a first test module that includes a first fluid test chamber operable to fluidly couple to an annulus of a wellbore to receive a first portion of a wellbore fluid, the first test module further including an acoustic fluid sensor to measure a fluid acoustic velocity and attenuation of the first portion of the wellbore fluid received in the first fluid test chamber, and a fluid resistivity sensor to measure a fluid resistivity of the first portion of the wellbore fluid received in the first fluid test chamber; and a second test module including a second fluid test chamber operable to fluidly couple to the annulus of the wellbore to receive a second portion of the wellbore fluid, and a pressure-temperature (PT) sensor to measure at least one of a pressure or a temperature of the second portion of the wellbore fluid.