Predicting Source Rock Quality Using GR Wireline Response and Umaa vs. pmaa Crossplots in the Lewis Shale, Green River Basin, Wyoming
Abstract: Evaluating source-rock quality using wireline logs is a practical and economic tool for reservoir characterization. Wireline data of the Lewis Shale in the Green River Basin, Wyoming was analyzed to determine if source-rock quality indicators could be found. Gamma-ray tool response to uranium was found to be a good predictor of total organic carbon (TOC) values. The viability of using U maa vs. ρ maa crossplots as a method to evaluate source-rock quality is less certain, as TOC signatures are overwhelmed by ho… Show more
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Sonic log data and core measurements are often used to develop models of in-situ stress profiles and rock elastic properties for use in hydraulic fracture design treatments in unconventional reservoirs. "Unconventional" reservoirs, for the purposes of this paper, include shale-gas, coalbed methane, and tight-gas projects. In unconventional reservoirs, many of the assumptions underlying rock property estimation and stress profiling in conventional reservoirs may not apply. In fact, the result of using conventional approaches may be an incorrect and often misleading stress profile. Fracture geometry predicted using conventionally derived rock properties and stresses might also be inaccurate. Methods of deriving rock properties from log and core measurements and the effect of various parameters on resulting moduli and stress estimates are examined. The paper also discusses the effects of rock anisotropy and inhomogeneity on static and dynamic properties. The impact of organic materials and trapped gas on sonic logs and conventional mechanical properties interpretation and the use of synthetic sonic logs are also presented. For static and dynamic measurements on core samples, the effects of the condition of recovered core and applied laboratory procedures on measurement results are also considered. Potential errors resulting from the use of inappropriate mechanical properties for stress profiling and fracture geometry prediction can be significant. The paper identifies common pitfalls in core and log interpretation. A recommended procedure to determine useful and accurate rock mechanical properties for stress profile prediction and fracture design is presented. Introduction Full-waveform sonic logs and core measurements are commonly used to derive "calibrated" models of in-situ stress profiles. The results are used as input to hydraulic fracture design simulators, which are used to determine optimum perforation placement, job size, pump rate, fluid and proppant requirements, and other design variables for optimum reserve recovery. The methods used to determine rock mechanical properties and stresses assume that the raw input measurements are valid and that the conditions of measurement are appropriate to conditions during hydraulic fracturing. In unconventional reservoirs, these assumptions may not be valid. Because of the potential for large reserves, there is an increasing interest in unconventional reservoirs. For the purpose of this discussion, unconventional reservoirs are considered to be tight and ultra-tight gas sands (less than 0.01 md effective permeability), gas-shales, and coalbed methane (CBM) reservoirs. These reservoirs have several characteristics in common: They all have low, very low, or nearly immeasurable "matrix" permeability. They may be self-sourcing and can contain organic carbon within the hydrocarbon maturation window, and may be actively generating hydrocarbons at the time of discovery and development. Many have abnormal pore pressures, relative to a hydrostatic gradient. Many occur in regions with significant tectonic stress or strain overprints, hence anisotropic stress fields. Production from these reservoirs is commonly enhanced through the presence of some kind of fracture or micro-fracture network. These complexities affect the behavior of core and log measurements. Interpretation of core and log data may require different paradigms and assumptions than those commonly applied in more conventional reservoir systems. Using conventional assumptions when dealing with measurements in unconventional reservoirs can lead to significant errors in the derived rock mechanical properties and estimated stress profile. These errors can lead to incorrect predictions of fracture containment and overall geometry, conductivity, and post-frac performance.
Sonic log data and core measurements are often used to develop models of in-situ stress profiles and rock elastic properties for use in hydraulic fracture design treatments in unconventional reservoirs. "Unconventional" reservoirs, for the purposes of this paper, include shale-gas, coalbed methane, and tight-gas projects. In unconventional reservoirs, many of the assumptions underlying rock property estimation and stress profiling in conventional reservoirs may not apply. In fact, the result of using conventional approaches may be an incorrect and often misleading stress profile. Fracture geometry predicted using conventionally derived rock properties and stresses might also be inaccurate. Methods of deriving rock properties from log and core measurements and the effect of various parameters on resulting moduli and stress estimates are examined. The paper also discusses the effects of rock anisotropy and inhomogeneity on static and dynamic properties. The impact of organic materials and trapped gas on sonic logs and conventional mechanical properties interpretation and the use of synthetic sonic logs are also presented. For static and dynamic measurements on core samples, the effects of the condition of recovered core and applied laboratory procedures on measurement results are also considered. Potential errors resulting from the use of inappropriate mechanical properties for stress profiling and fracture geometry prediction can be significant. The paper identifies common pitfalls in core and log interpretation. A recommended procedure to determine useful and accurate rock mechanical properties for stress profile prediction and fracture design is presented. Introduction Full-waveform sonic logs and core measurements are commonly used to derive "calibrated" models of in-situ stress profiles. The results are used as input to hydraulic fracture design simulators, which are used to determine optimum perforation placement, job size, pump rate, fluid and proppant requirements, and other design variables for optimum reserve recovery. The methods used to determine rock mechanical properties and stresses assume that the raw input measurements are valid and that the conditions of measurement are appropriate to conditions during hydraulic fracturing. In unconventional reservoirs, these assumptions may not be valid. Because of the potential for large reserves, there is an increasing interest in unconventional reservoirs. For the purpose of this discussion, unconventional reservoirs are considered to be tight and ultra-tight gas sands (less than 0.01 md effective permeability), gas-shales, and coalbed methane (CBM) reservoirs. These reservoirs have several characteristics in common: They all have low, very low, or nearly immeasurable "matrix" permeability. They may be self-sourcing and can contain organic carbon within the hydrocarbon maturation window, and may be actively generating hydrocarbons at the time of discovery and development. Many have abnormal pore pressures, relative to a hydrostatic gradient. Many occur in regions with significant tectonic stress or strain overprints, hence anisotropic stress fields. Production from these reservoirs is commonly enhanced through the presence of some kind of fracture or micro-fracture network. These complexities affect the behavior of core and log measurements. Interpretation of core and log data may require different paradigms and assumptions than those commonly applied in more conventional reservoir systems. Using conventional assumptions when dealing with measurements in unconventional reservoirs can lead to significant errors in the derived rock mechanical properties and estimated stress profile. These errors can lead to incorrect predictions of fracture containment and overall geometry, conductivity, and post-frac performance.
The geomechanical properties of an unconventional reservoir or shale, especially the minimum in-situ stress and fracture gradients, are important for several applications such as mud weight optimization and completion design. Two common methods of direct stress testing are using a wireline formation tester (WFT) with straddle packers and surface-pressure-based fracture injection tests (FITs).Microfracturing was performed at several depths using a WFT in tight clastic and shale oil formations in a well in west Texas. In the same well, microfracturing was also performed using the FIT method, and hence, the two results could be compared. Imaging logs show many drilling-induced fractures in the target intervals, but formation testing with straddle packers did not provide any successful pressure measurements or formation fluid samples because of the low permeability and lack of a natural fracture network in the near-wellbore region. However, fractures were successfully induced in multiple zones by using the WFT microfracturing tool, and the results compare favorably with the geomechanical logs. Downhole quartz pressure gauges used with the microfracturing are very sensitive and can be used to calibrate surface-pressure-based FITs. Microfractures can be induced with less than a few gallons of drilling mud, and the pressure response is observed downhole without any frictional losses or time lag. In addition, the closure time derived from microfracturing is much shorter than the surface FIT-based closure time; however, microfracturing entails additional rig time.In-situ stresses control the orientation and propagation direction of hydraulic fractures. Microfractures are tensile fractures that open in the direction of least resistance. These fractures are also affected by hoop stress in the near-wellbore region, drilling induced fractures, and borehole breakouts. Results indicate that stress gradients, which vary widely across the basin and lithofacies, are controlled by local and regional stresses. The stress gradients derived from microfractures are compared to sonic-log derived gradients and indicate that a symbiotic relation exists in calibrating and quality controlling sonic logs, image logs, and microfracture testing.Intervals with drilling-induced fractures that extend beyond 3 feet tend to give lower stress gradients from microfracture testing and these zones should be avoided for microfracturing. Existing natural open fractures reduce the ability of the WFT tool to seal against the borehole and to create and propagate a fracture in the formation. The location of unaltered formation should be promptly identified for testing prior to entry into the borehole. This may entail having wellsite interpreters as data transmission speeds can pose a constraint while uploading and interpreting image logs offsite. Sonic-log-derived models for stress gradients can be calibrated with pore pressure and overbalance from WFT. Stress gradients generated from microfracture testing can be used to calibrate parameters such as Biot's c...
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