For many years, geologists and engineers have used volumetric methods to quantify or estimate hydrocarbon volume contained in reservoirs. The economic producibility of the reservoirs, also depend on the flow characteristics. The overall level of uncertainty of the estimation depends on the uncertainty of the parameters that determine the oil volume such as porosity and the reservoir characteristics such as pay thickness. However, uncertainty of estimation increases when estimating hydrocarbon in place for complex fluids systems (i.e. heavy oil) since mobility can have an adverse effect on fluid movement. Determination of net pay cut-offs should be based on parameters that include flow and storage capacity.Considering the requirement to establish a relationship between petrophysical cut-offs and rock types to estimate hydrocarbon in place, five different cases were used to quantify net pay parameters of the reservoir in the Cerro Negro field, Venezuela. The workflow that was applied: 1. Identification of petrophysical rock types (PRT) from porosity and permeability data using core-based and log-derived petrophysical analysis, 2. Definition of the relationship between PRT and facies 3. Determination of pay cut-offs for reservoir and each PRT using conventional and contemporary methodologies, 4. Comparison of the conventional and contemporary methodologies results, 5. Estimation of pay cut-offs impact on the prediction of rock types and reservoir petrophysical properties in the estimation of volumetric. This study demonstrates that the definition of PRT distribution is controlled by pore throat size instead of facies. From the six rock types defined in the field just three rock types (1, 2, and 3) are oil producing rock reservoir. The OOIP results vary significantly over a range of 500 MMstb, depending on which of the parameters are used as pay cut-offs. In conclusion, estimating OOIP by applying petrophysical rock typing is an improved way to decrease uncertainty than OOIP estimation by reservoir unit. The results demonstrated that the choice of good pay cut-offs was the key to reduce the uncertainty in the estimation of the OOIP in the Cerro Negro field.

Important hydrocarbon accumulations occur in tight rocks in Colombian areas. Those tight reservoirs consist of clean sandstones with matrix porosities in the 3% to 4% range, relatively complex mineralogy and naturally fractured. The success of achieving a representative formation evaluation relies on obtaining accurate porosity, oil, gas, water saturations, natural fractures detection and good estimates on reservoir permeability. Resistivity-based approaches are difficult to apply since reservoir conductivity is not only influenced by fluid type, but also by salinity (typically low in our reservoirs), variable tortuosity (mostly high in the matrix and very low in fractures) and very high formation resistivity (above 1,000 ohms.m). In addition, a combination of low pores volumes and a matrix not properly assessed, leads to high errors in the porosity determination with conventional logs (in a 3 – 4 p.u. reservoir, the porosity error computation can be as high as 50%). Uncertainties in porosity estimates also translates to uncertainties during saturation assessment. Further challenges are found when attempting the saturation computation from resistivity logs. The tight sands are drilled with Oil Based Muds, creating a logging environment where only induction logs are possible. However, since the resistivity range in these rocks is above 1000 ohm.m range, the induction measurements are out of range in many of the target zones. Alternative formation evaluation methods for assessing fluids saturations, like magnetic resonance, sigma and carbon-oxygen logs cannot be applied below 10 porosity units; whereas dielectric measurements strongly depend on accurate porosity computations for deriving the hydrocarbon volume. Some of these reservoirs, are also deep (in the 17,000 ft range) and close to foothills, where wellbore stability issues and narrow mud weight windows used for drilling, translates into higher risks for open-hole logging via logging while drilling or wireline conveyance, all of it detrimental to data acquisition in open hole. Therefore, the case studies presented in this paper were assessed in cased hole conditions. In this paper, we present a solution that cover tight matrix and natural fractures assessment, at a level not previously achieved. At the tight matrix level, we carry out advanced nuclear spectroscopy with a new pulsed neutron device, that carry out simultaneous time domain and energy domain measurements. A new resistivity and salinity independent methodology for obtaining Gas saturation from a new measurement in the industry known as "Fast Neutron Cross Section" (FNXS), oil saturation from the total organic carbon (TOC) log, mineral volumes solved from formation elemental concentrations from energy domain, and porosity from hydrogen index obtained from the spectroscopy time domain, is presented. At natural fracture level, we make use of a Borehole Acoustic Reflection Service for deep natural fracture detection and spatial orientation analysis, done at cased hole conditions. The main advantages of the new method for obtaining porosity, mineralogy, salinity-independent hydrocarbon saturation in tight matrix and natural fracture assessment behind casing are: 1) conversion of dry weight total carbon to oil saturation, and fast neutron cross section to gas saturation done through a simultaneous inversion by solving matrix-porosity-fluids volumes into an elemental analysis, proven to work at low porosities rocks; 2) independency of salinity and reservoir tortuosity effects; 3) clay and/or other lithology effects is quantified and taken into account; 4) faster logging speeds and improve tools combinability in bigger holes while ensuring full reservoir assessment in small holes; 5) operational time reduction. The spectroscopy logging is carried out in single acquisition pass at 150 to 350-feet per hour (ft/hr), whereas sonic acquisition is done at 400 ft/hr in a single pass as well.