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ABSTRACT Nonmiscible fluid displacement without salt exchange takes place when oil-base mud (OBM) invades connate water-saturated rocks. This is a favorable condition for the estimation of dynamic petrophysical properties, including saturation-dependent capillary pressure. We developed and successfully tested a new method to estimate porosity, fluid saturation, permeability, capillary pressure, and relative permeability of water-bearing sands invaded with OBM from multiple borehole geophysical measurements. The estimation method simulates the process of mud-filtrate invasion to calculate the corresponding radial distribution of water saturation. Porosity, permeability, capillary pressure, and relative permeability are iteratively adjusted in the simulation of invasion until density, photoelectric factor, neutron porosity, and apparent resistivity logs are accurately reproduced with numerical simulations that honor the postinvasion radial distribution of water saturation. Examples of application include oil- and gas-bearing reservoirs that exhibit a complete capillary fluid transition between water at the bottom and hydrocarbon at irreducible water saturation at the top. We show that the estimated dynamic petrophysical properties in the water-bearing portion of the reservoir are in agreement with vertical variations of water saturation above the free water-hydrocarbon contact, thereby validating our estimation method. Additionally, it is shown that the radial distribution of water saturation inferred from apparent resistivity and nuclear logs can be used for fluid-substitution analysis of acoustic compressional and shear logs.
- Europe (1.00)
- North America > United States > Texas (0.93)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.69)
- Geology > Mineral > Silicate (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.33)
- Europe > United Kingdom > North Sea > North Sea > Northern North Sea > South Viking Graben > Block 16/28 > Andrew Field (0.99)
- Europe > United Kingdom > North Sea > North Sea > Northern North Sea > South Viking Graben > Block 16/27a > Andrew Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Northern North Sea > South Viking Graben > Block 16/28 > Andrew Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Northern North Sea > South Viking Graben > Block 16/27a > Andrew Field (0.99)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Abstract This paper introduces a rock typing method for application in hydrocarbon-bearing shale (specifically source rock) reservoirs using conventional well logs and core data. Source rock reservoirs are known to be highly heterogeneous and often require new or specialized petrophysical techniques for accurate reservoir evaluation. In the past, petrophysical description of source rock reservoirs with well logs has been focused to quantifying rock composition and organic-matter concentration. These solutions often require many assumptions and ad-hoc correlations where the interpretation becomes a core matching exercise. Scale effects on measurements are typically neglected in core matching. Rock typing in hydrocarbon-bearing shale provides an alternative description by segmenting the reservoir into petrophysically-similar groups with k-means cluster analysis, which can then be used for ranking and detailed analysis of depth zones favorable for production. A synthetic example illustrates the rock typing method for an idealized sequence of beds penetrated by a vertical well. Results and analysis from the synthetic example show that rock types from inverted log properties correctly identify the most organic-rich sections better than rock types detected from well logs in thin beds. Also, estimated kerogen concentration is shown to be the most reliable property in an under-determined inversion solution. Field cases in the Barnett and Haynesville shale gas plays show the importance of core data for supplementing well logs and identifying correlations for desirable reservoir properties (kerogen/TOC concentration, fluid saturations, and porosity). Qualitative rock classes are formed and verified using inverted estimates of kerogen concentration as a rock-quality metric. Inverted log properties identify 40% more of a high-kerogen rock type over well-log based rock types in the Barnett formation. A case in the Haynesville formation suggests the possibility of identifying depositional environments as a result of rock attributes that produce distinct groupings from k-means cluster analysis with well logs. Core data and inversion results indicate homogeneity in the Haynesville formation case. However, the distributions of rock types show a 50% occurrence between two rock types over 90 ft vertical-extent of reservoir. Rock types suggest vertical distributions that exhibit similar rock attributes with characteristic properties (porosity, organic concentration and maturity, and gas saturation). The interpretation method considered in this paper does not directly quantify reservoir parameters and would not serve the purpose of quantifying gas-in-place. Rock typing in hydrocarbon-bearing shale with conventional well logs forms qualitative rock classes which can be used to calculate net-to-gross, validate conventional interpretation methods, perform well-to-well correlations, and establish facies distributions for integrated reservoir modeling in hydrocarbon-bearing shale.
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Cotton Valley Group Formation > Bossier Shale Formation (0.99)
- North America > United States > Texas > Ardmore - Marieta Basin > Newark East Field > Barnett Shale Formation (0.99)
- (6 more...)
Abstract Petrophysical interpretation of well logs acquired in organic shales and carbonates is challenging because of the presence of thin beds and spatially complex lithology; conventional interpretation techniques often fail in such cases. Recently introduced methods for thin-bed interpretation enable corrections for shoulder-bed effects on well logs but remain sensitive to incorrectly picked bed boundaries. We introduce a new inversion-based method to detect bed boundaries and to estimate petrophysical and compositional properties of multi-layer formations from conventional well logs in the presence of thin beds, complex lithology/fluids, and kerogen. Bed boundaries and bed properties are updated in two serial inversion loops. Numerical simulation of well logs within both inversion loops explicitly takes into account differences in the volume of investigation of all well logs involved in the estimation, thereby enabling corrections for shoulder-bed effects. The successful application of the new interpretation method is documented with synthetic cases and field data acquired in thinly bedded carbonates and in the Haynesville shale-gas formation. Estimates of petrophysical/compositional properties obtained with the new interpretation method are compared to those obtained with (a) nonlinear inversion of well logs with inaccurate bed boundaries, (b) depth-by-depth inversion of well logs, and (c) core/X-Ray Diffraction (XRD) measurements. Results indicate that the new method improves the estimation of porosity of thin beds by more than 200% in the carbonate field example and by more than 40% in the shale-gas example, compared to depth-by-depth interpretation results obtained with commercial software. This improvement in the assessment of petrophysical/compositional properties reduces uncertainty in hydrocarbon reserves and aids in the selection of hydraulic fracture locations in organic shale.
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Formation (0.99)
- (2 more...)
Petrophysical Properties of Unconventional Low-Mobility Reservoirs (Shale Gas and Heavy Oil) by Using Newly Developed Adaptive Testing Approach
Hadibeik, Hamid (The University of Texas at Austin) | Chen, Dingding (Halliburton Energy Services) | Proett, Mark (Halliburton Energy Services) | Eyuboglu, Sami (Halliburton Energy Services) | Torres-Verdín, Carlos (The University of Texas at Austin)
Abstract Pressure testing in very low-mobility reservoirs is challenging with conventional formation-testing methods. The primary difficulty is the over-extended build-up times required to overcome wellbore and formation storage effects. Possible wellbore overbalance or supercharge are additional complicating factors in determining reservoir pressure. This paper addresses the above technical complications and estimates petrophysical properties of low-mobility formations using a newly developed adaptive-testing approach. The adaptive-testing approach employs an automated pulse-testing method for very low-mobility reservoirs and uses short drawdowns and injections followed by short pressure stabilization periods. Measured pressure transients are used in an optimized feedback loop to automatically adjust subsequent drawdown and injection pulses to reach a stabilized pressure as quickly as possible. The automated pulse data is used to determine supercharge effects, formation pressure, and mobility via analytical models by analyzing the entire pressure sequence. A genetic algorithm estimates additional reservoir parameters, such as porosity and viscosity, and confirms results obtained with analytical models (reservoir pressure and permeability). The modeled formation pressure exhibits less than 1% difference with respect to true formation pressure, while the accuracy of other parameters depends on the number of unknown properties. As a quicker method to estimate reservoir properties, a direct neural-network regression of pulse-testing data was also investigated. Synthetic reservoir models for low-mobility formations (M < 1 μD/cp), which included the dynamics of water- and oil- based mud-filtrate invasion that produce wellbore supercharging were developed. These reservoir models simulated the pulse-testing methods, including an automated feedback-optimization algorithm that reduces the testing times in a wide range of downhole conditions. The reservoir models included both simulations of underbalanced and overbalanced drilling conditions and enabled the development of new field-testing strategies based on a priori reservoir knowledge. The synthetic modeling demonstrates the viability of the new pulse-testing method and confirms that difficult properties, such as supercharging, can be estimated more accurately when coupled with the new inversion techniques.
Abstract Rock typing in carbonate reservoirs is challenging due to high spatial heterogeneity and complex pore structure. In extreme cases, conventional rock typing methods such as Leverett's J-function, Winland's R35, and flow zone indicator are inadequate to capture the heterogeneity and complexity of carbonate petrofacies. Furthermore, these methods are based on core measurements, hence are not applicable to uncored reservoir zones. This paper introduces a new method for petrophysical rock classification in carbonate reservoirs that honors multiple well logs and emphasizes the signature of mud-filtrate invasion. The method classifies rocks based on both static and dynamic petrophysical properties. An inversion-based algorithm is implemented to simultaneously estimate mineralogy, porosity, and water saturation from well logs. We numerically simulate the process of mud-filtrate invasion in each rock type and quantify the corresponding effects on nuclear and resistivity measurements to derive invasion-induced well-log attributes, which are subsequently integrated into the rock classification. Under favorable conditions, the interpretation method advanced in this paper can distinguish bimodal from uni-modal behavior in saturation-dependent capillary pressure otherwise only possible with special core analysis. We successfully apply the new method to a mixed clastic-carbonate sequence in the Hugoton gas field, Kansas. Rock types derived with the new method are in good agreement with lithofacies described from core samples. The distribution of permeability and saturation estimated from well-log-derived rock types agrees with routine core measurements, with the corresponding uncertainty significantly reduced when compared to results obtained with conventional porosity-permeability correlations.
- North America > United States > Texas (1.00)
- North America > United States > Kansas > Finney County (0.49)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- North America > United States > California > Sacramento Basin > 2 Formation (0.99)
- North America > United States > Kansas > Panoma Field (0.94)
Inversion-based method for interpretation of logging-while-drilling density measurements acquired in high-angle and horizontal wells
Mendoza, Alberto (The University of Texas) | Ijasan, Olabode (The University of Texas) | Torres-Verdín, Carlos (The University of Texas) | Preeg, William E. | Rasmus, John (Schlumberger) | Radtke, R. J. (Schlumberger) | Stockhausen, Edward (Chevron ETC)
ABSTRACT We introduce a sector-based inversion method to improve the petrophysical interpretation of logging-while-drilling density measurements acquired in high-angle and horizontal wells. The central objective is to reduce shoulder-bed effects on the measurements. This approach is possible because of a recently developed technique to accurately and efficiently simulate borehole density measurements. The inversion-based interpretation method consists of first detecting bed boundaries from short-spacing detector or bottom-quadrant compensated density by calculating their variance, representative of the measurement inflection point, within a sliding window. Subsequently, a correlation algorithm calculates dip and azimuth from the density image. Depth shifts that vary azimuthally and depend on relative dip angle, together with the effective penetration length of each sensor, refine previously selected bed boundaries. Next, the inversion method combines sector-based density measurements acquired at all measurement points along the well trajectory to estimate layer-by-layer densities. In the presence of standoff, the method excludes upper sectors most affected by standoff to reduce inaccuracies due to borehole mud. To verify the reliability and applicability of the inversion method, we first use forward simulations to generate synthetic density images for a model constructed from field data. Results indicate that inversion improves the interpretation of azimuthal density data as it consistently reduces shoulder-bed effects. Inversion results obtained from field measurements are appraised by quantifying the corresponding integrated porosity-meter yielded by inversion methods in comparison to standard techniques that use simple cutoffs on field-processed compensated density. Integrated porosity-meter of inverted synthetic density measurements increases by 4.6% with respect to noninverted field measurements. Also, integrated porosity-meter obtained from inversion results that include only bottom sectors improved by 65.4% with respect to that calculated with field-compensated, bottom-quadrant density measurements.
- Geology > Geological Subdiscipline > Stratigraphy (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
ABSTRACT: Nuclear magnetic resonance (NMR) is widely used to assess petrophysical and fluid properties of porous rocks. In the case of fluid typing, two-dimensional (2D) NMR interpretation techniques have advantages over conventional one-dimensional (1D) interpretation as they provide additional discriminatory information about saturating fluids. However, often there is ambiguity as to whether fluids appraised with NMR measurements are mobile or residual. In some instances, high vertical heterogeneity of rock properties (e.g. across thinlybedded formations) can make it difficult to separate NMR fluid signatures from those due to pore-size distributions and fluids. There are also cases where conventional fluid identification methods based on resistivity and nuclear logs indicate dominant presence of water while NMR measurements indicate presence of water, hydrocarbon, and mud filtrate. Depending on drilling mud being used, and the radial extent of mud-filtrate invasion, the NMR response of virgin reservoir fluids can be masked by that of mud filtrate. In order to separate those effects, it is important to reconcile NMR measurements with electrical and nuclear logs for improved assessment of porosity and mobile hydrocarbon saturation. We quantify the exact radial zone of response of NMR measurements and corresponding fluid saturations with studies of mud-filtrate invasion that honor resistivity and nuclear logs. Examples of application examine field data acquired in thinly-bedded gas formations of the Wamsutter basin invaded with water-base mud, wherein residual hydrocarbon saturation is relatively high. Additionally, fluid identification and partial porosity calculations obtained from a T1-T2 map indicate that NMR measurements originate from a radial annulus approximately 5 inches into the formation where the pore space is predominantly saturated with water but in which gas saturation is still higher than residual saturation. It was also found that the uncertainty of total NMR porosity could be as high as 3 pu because of noise and thin-bed effects.
- Geology > Rock Type > Sedimentary Rock (0.94)
- Geology > Geological Subdiscipline (0.88)
- North America > United States > Wyoming > Sand Wash Basin (0.99)
- North America > United States > Wyoming > Greater Green River Basin > Wamsutter Basin > Wamsutter Field (0.99)
- North America > United States > Wyoming > Greater Green River Basin > Almond Formation (0.99)
- (2 more...)
Formation-Tester Pulse Testing in Tight Formations (Shales and Heavy Oil): Where Wellbore Storage Effects Favor the Determination of Reservoir Pressure
Hadibeik, Hamid (The University of Texas at Austin) | Proett, Mark (Halliburton Energy Services) | Chen, Dingding (Halliburton Energy Services) | Eyuboglu, Sami (Halliburton Energy Services) | Torres-Verdín, Carlos (The University of Texas at Austin) | Pour, Rooholah A. (The University of Texas at Austin)
Abstract Tight formation testing when mobilities are lower than 0.01 mD/cP poses significant challenges because the conventional pressure transient buildup testing becomes impractical as a result of the large buildup stabilization time. This paper introduces a new automated pulse test method for testing in tight formations that significantly reduces testing time and makes the determination of formation pressure and permeability possible. A pulse test is defined as a drawdown followed by an injection test, and the source is shut in to record the pressure transient. Based on pressure data during the shut-in period, the next drawdown or injection test is designed, such that the flow rate is a fraction of the initial pulse rate, followed by another shut-in test. This procedure continues until the difference in pressure at the beginning and at the end of the shut-in period is reduced to within a specified limit of pressure change; then, an extended transient is recorded to a stabilized shut-in pressure. The overall advantage is to reduce the pressure stabilization time by implementing an adaptive pressure feedback loop in the system. The method can be applied to a straddle packer test using conventional drillstem testing tools or formation testers, using either straddle packers or probes. The effects of wellbore storage and fluid compressibility are found to reduce the pressure drop and positive pressure pulse in the drawdown and injection tests, respectively; they also affect the decay rate to the asymptote of the shut-in pressure response. Consequently, the combined pulse test method with the pressure feedback system and wellbore storage effect reduces the reservoir pressure testing time in tight formations. The automated pulse-test method has been successfully validated with consideration of the effects of wellbore storage and overbalance pressure in tight gas and heavy oil formations. In addition, the effects of invasion with water- and oil-based mud filtrate were considered in the modeling. The method uses successive pressure feedbacks and automated pulses to yield a pressure to within 0.5% range of the initial reservoir pressure while decreasing the wait time by a factor of 10 for a packer type formation tester. To account for various tool options and storage effects, the packer-type, oval probe, and standard probe-type formation testers have been simulated in various tight formation conditions. The method enables a rapid appraisal of pressure measurements in comparison to conventional testing. Simulations also indicate that the analytical spherical model can be used to analyze a pulse test, even when encountering multi-phase compositional fluid effects.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.72)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.41)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Nebraska > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Kansas > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Colorado > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)