Journal of Petroleum Technology June 2012 : Page 28

TECHNOLOGY UPDATE Advanced Workflow Package for Shale Assets Developed Dan Buller, Halliburton The growth in unconventional resource plays in the past several years has pro-duced a burgeoning need for new soft-ware tools for organic shales. Geoscien-tists need tools to help them understand complex hydrocarbon generation, stor-age capacity, and migration paths in source rock reservoirs, enabling them to flag and map optimized pay. Engineers need tools to help them define optimum techniques to deliver the most shale gas and oil to the market and enable them to build the best reservoir models to exploit these resources. And for unconventional resource development to proceed as it should, these tools must work together in a common framework. An advanced integrated petrophysi-cal evaluation software package, based on a calibrated workflow, was recent-ly developed by Halliburton for organ-ic shales. The concept behind it was to bring all the requisite pieces of an explo-ration shale play analysis into a single vantage point for an asset team. This is critical when very few vertical explora-tion wells are used to define the econom-ics of these resource plays before full-scale horizontal development begins. The software’s workflow modules encompass the following capabilities: total organic carbon (TOC) and organic maturity estimation; fluid and minerals evaluation; advanced saturation model-ing; mechanical properties and brittle-ness; 3D stress and stress orientation; permeability; and pay analysis. type, the level of thermal maturity must be established. To solve for kerogen, the TOC measured by core pyrolysis can be calibrated to logs, using eight industry accepted correlations. Organic maturi-ty, VR o , is measured by actual vitrinite reflectance or calculated from pyroly-sis-derived T max (temperature between 300°C and 600°C that generates peak hydrocarbons from existing kerogen). This maturity value is used to make the final TOC calibration and predict hydro-carbon type. Fluid and Minerals Evaluation The heart of the volumetric analysis is its probabilistic solver. Total porosity in organic shales can only be resolved by logs when relative amounts of geochem-ically derived minerals are measured and combined with the TOC calculation. Minimum requirements for this type of analysis include a triple combo log, neu-tron capture spectroscopy, and natural gamma spectroscopy. The software uses a probabilistic error minimization meth-odology to determine formation fluid and mineral volumes. The idea is to construct theoretical logs that closely replicate actual logs. Tool response equations are expressed in terms of fluid and mineral volumes and their corresponding tool response parameters. Most response equations are linear. Some, such as neutron, con-ductivity, and certain acoustic equa-tions, are nonlinear. The inclusion of additional evaluation tools, such as the dipole sonic travel time curves DTC (compressional velocity) and DTS (shear velocity), helps add coherence to the analysis, as long as the correct acous-tic equations are used for harder rock-clay shales. The analyst first constructs a “dry” rock model, which consists of the response equations, parameters, and constraints available for the input tools and includes TOC. The key to the entire analysis is solving only for those miner-als that are actually found by core x-ray diffraction (or alternatively x-ray fluores-cence). Key constraints relating relative abundances of the different types of clay mineralogy to one another, and to the base matrix silica or calcite, help com-plete the dry rock model. When a good match of all measured log inputs for the dry rock model case has been achieved, the “wet” rock model case, which uses available resistivity inputs, is applied. While all conventional saturation models are supported in soft-ware, the Simandoux model has worked best in matching GRI core gas satura-tions because of its more robust handling of clay water response. Even with the best saturation equation, cementation “m” and saturation “n” constants must be adjusted lower to match core because only a portion of the internal pore sur-face has seen water as a wetting phase. Internal kerogen porosity has either oil or gas as a wetting phase, as it has never been exposed to water. Microfractures internal to the matrix, where migrating oil and gas have escaped internal kero-gen containment, are also nonwater wet. This explains why conventional water saturation equations will fail unless cali-brated to core. TOC Estimation and Organic Maturity To define the resource volume, one needs to determine an accurate volume of organic kerogen present in the rock. To determine potential hydrocarbon Advanced Saturation Modeling: NMR and Dielectric Volumes All organic shales exhibit both water and hydrocarbon wetting phases as a result of the varied porosity systems present in the rock. This makes it appropriate 28 JPT • JUNE 2012

Technology Update • Advanced Workflow Package for Shale Assets Developed

Dan Buller, Halliburton

The growth in unconventional resource plays in the past several years has produced a burgeoning need for new software tools for organic shales. Geoscientists need tools to help them understand complex hydrocarbon generation, storage capacity, and migration paths in source rock reservoirs, enabling them to flag and map optimized pay. Engineers need tools to help them define optimum techniques to deliver the most shale gas and oil to the market and enable them to build the best reservoir models to exploit these resources. And for unconventional resource development to proceed as it should, these tools must work together in a common framework. An advanced integrated petrophysical evaluation software package, based on a calibrated workflow, was recently developed by Halliburton for organic shales. The concept behind it was to bring all the requisite pieces of an exploration shale play analysis into a single vantage point for an asset team. This is critical when very few vertical exploration wells are used to define the economics of these resource plays before fullscale horizontal development begins. The software’s workflow modules encompass the following capabilities: total organic carbon (TOC) and organic maturity estimation; fluid and minerals evaluation; advanced saturation modeling; mechanical properties and brittleness; 3D stress and stress orientation; permeability; and pay analysis. TOC Estimation and Organic Maturity To define the resource volume, one needs to determine an accurate volume of organic kerogen present in the rock. To determine potential hydrocarbon type, the level of thermal maturity must be established. To solve for kerogen, the TOC measured by core pyrolysis can be calibrated to logs, using eight industry accepted correlations. Organic maturity, Vro, is measured by actual vitrinite reflectance or calculated from pyrolysis-derived Tmax (temperature between 300°C and 600°C that generates peak hydrocarbons from existing kerogen). This maturity value is used to make the final TOC calibration and predict hydrocarbon type. Fluid and Minerals Evaluation The heart of the volumetric analysis is its probabilistic solver. Total porosity in organic shales can only be resolved by logs when relative amounts of geochemically derived minerals are measured and combined with the TOC calculation. Minimum requirements for this type of analysis include a triple combo log, neutron capture spectroscopy, and natural gamma spectroscopy. The software uses a probabilistic error minimization methodology to determine formation fluid and mineral volumes. The idea is to construct theoretical logs that closely replicate actual logs. Tool response equations are expressed in terms of fluid and mineral volumes and their corresponding tool response parameters. Most response equations are linear. Some, such as neutron, conductivity, and certain acoustic equations, are nonlinear. The inclusion of additional evaluation tools, such as the dipole sonic travel time curves DTC (compressional velocity) and DTS (shear velocity), helps add coherence to the analysis, as long as the correct acoustic equations are used for harder rockclay shales. The analyst first constructs a “dry” rock model, which consists of the response equations, parameters, and constraints available for the input tools and includes TOC. The key to the entire analysis is solving only for those minerals that are actually found by core x-ray diffraction (or alternatively x-ray fluorescence). Key constraints relating relative abundances of the different types of clay mineralogy to one another, and to the base matrix silica or calcite, help complete the dry rock model. When a good match of all measured log inputs for the dry rock model case has been achieved, the “wet” rock model case, which uses available resistivity inputs, is applied. While all conventional saturation models are supported in software, the Simandoux model has worked best in matching GRI core gas saturations because of its more robust handling of clay water response. Even with the best saturation equation, cementation “m” and saturation “n” constants must be adjusted lower to match core because only a portion of the internal pore surface has seen water as a wetting phase. Internal kerogen porosity has either oil or gas as a wetting phase, as it has never been exposed to water. Microfractures internal to the matrix, where migrating oil and gas have escaped internal kerogen containment, are also nonwater wet. This explains why conventional water saturation equations will fail unless calibrated to core. Advanced Saturation Modeling: NMR and Dielectric Volumes All organic shales exhibit both water and hydrocarbon wetting phases as a result of the varied porosity systems present in the rock. This makes it appropriate To apply resistivity independent saturation measurements, such as nuclear magnetic resonance (NMR) and dielectric porosity. These allow direct measurements of total fluid-filled porosity (NMR T1 time constant dimension) and total water-filled porosity (dielectric).The difference between the two is typically unflushed oil and gas that is picked up in TOC pyrolysis data as an S1 free hydrocarbon volume. It should be noted that the accuracy of the dielectric water porosity measurement depends on determining the mineralogy and water salinity. The NMR porosity data is best viewed in a T1 dimension, as that time constant spreads out the measured porosity spectrum to twice the extent of that seen in conventional T2 porosity measurements. This allows a much more detailed analysis of the ultrasmall pores in the lowest part of the spectrum. Recent laboratory data show that in ultrasmall pores, gas exists in a restricted diffusion environment and will be detected earlier in a normal water signal range and not later in a T1 bulk signal. Even with that, a T1 measurement gives the analyst a much more robust spectrum in which an enhanced spectral BVI technique can be used to discriminate clay- and capillary- bound water from small amounts of free fluid. The wet rock volumetric analysis can directly use all the discriminated NMR and dielectric porosity measurements. Clay-bound water can be constrained to what is seen from NMR. Total water can be constrained by a total dielectric porosity. A solved oil or gas volume can be constrained to the difference observed between NMR and dielectric porosities. Mechanical Properties and Brittleness Conventional vertical Young’s modulus and Poisson’s ratio are calculated from DTC and DTS dipole sonic data and are calibrated to static rock properties using surface core stress tests and analysis from small volume diagnostic fracture injection tests (DFIT) in cased vertical exploration wells. After final calibration to the DFIT analysis, the program determines fracture initiation pressure, fracture closure pressure, and closure stress gradient. Since 2008, we have used the concept of shale “brittleness,” a simple ratio between Young’s modulus and Poisson’s ratio, as a technique to predict induced fracture complexity and enhanced surface area contact. It has been used extensively as a powerful fracture fluid system design tool and to aid in sweet-spot identification.This same technique is implemented as “pseudobrittleness” and is color palette calibrated to core-measured brine hardness. Using directly measured DTC and DTS values, calibrated synthetic DTC and DTS curves can be generated from mineralogy and effective porosity data. These calibrated models can be used on future wells in which the operator may not have actual sonic data but still needs an accurate mechanical properties prediction. The prediction of mechanical properties from mineralogy data also allows the calibration of a “mineral brittleness” to the conventional “pseudobrittleness.” This allows mineralogy from advanced cuttings analysis techniques or neutroninduced spectroscopy logs to be used for mechanical proxy measurements. 3D Stress and Stress Orientation Laminated clay-rich shales often exhibit large differences between vertical and horizontal elastic properties. This anisotropy is quantified in a 3D stress analysis requiring a fast shear, slow shear, and Stoneley shear from an oriented x-y dipole sonic tool. The computed 3D closure stress is a much better predictor of true fracture geometry when used in current and future 3D fracture modeling software. The orientation of the fast shear azimuth will always be in the direction of maximum principal stress, which is orthogonal to the optimum horizontal well direction. Permeability This software uses a linear regression technique to match core-measured GRI matrix shale permeability. This can be several orders of magnitude less than permeability estimated from a DFIT analysis but is often used as a shale quality indicator. The DFIT effective permeability can be used to calibrate Timur or Coates model system matched permeabilities, or one of two new regression permeabilities with better dynamic range. Fracture simulators require an estimate of fluid leakoff that uses such permeabilty estimates. Pay Analysis The software allows the analyst and asset team up to six criteria for flagging and counting net pay. Typical criteria used include effective porosity, effective water saturation, pseudobrittleness, and closure stress. Either gas or oil, or both, can be volumetrically solved and cumulative reserves are output alongside flagged net pay. If core canister isotherm data is supplied, free vs. sorbed gas volumes are also calculated in this module. The ShaleXpert tool is then used to develop a final composite analysis (Fig. 1) that brings together all the different workflow modules in a display that aids in primary sweet-spot identification, shows in-place reserve estimates, and delivers everything required for an optimized fracture stimulation design. In this process, it can also generate individual quality-control plots and logs from any of its workflow components, so all processes are transparent to the end user. JPT

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