Browsing by Subject "Reservoir description"

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Reservoir description with well-log-based and core-calibrated petrophysical rock classification
(2013-08) Xu, Chicheng; Torres-Verdín, Carlos
Rock type is a key concept in modern reservoir characterization that straddles multiple scales and bridges multiple disciplines. Reservoir rock classification (or simply rock typing) has been recognized as one of the most effective description tools to facilitate large-scale reservoir modeling and simulation. This dissertation aims to integrate core data and well logs to enhance reservoir description by classifying reservoir rocks in a geologically and petrophysically consistent manner. The main objective is to develop scientific approaches for utilizing multi-physics rock data at different time and length scales to describe reservoir rock-fluid systems. Emphasis is placed on transferring physical understanding of rock types from limited ground-truthing core data to abundant well logs using fast log simulations in a multi-layered earth model. Bimodal log-normal pore-size distribution functions derived from mercury injection capillary pressure (MICP) data are first introduced to characterize complex pore systems in carbonate and tight-gas sandstone reservoirs. Six pore-system attributes are interpreted and integrated to define petrophysical orthogonality or dissimilarity between two pore systems of bimodal log-normal distributions. A simple three-dimensional (3D) cubic pore network model constrained by nuclear magnetic resonance (NMR) and MICP data is developed to quantify fluid distributions and phase connectivity for predicting saturation-dependent relative permeability during two-phase drainage. There is rich petrophysical information in spatial fluid distributions resulting from vertical fluid flow on a geologic time scale and radial mud-filtrate invasion on a drilling time scale. Log attributes elicited by such fluid distributions are captured to quantify dynamic reservoir petrophysical properties and define reservoir flow capacity. A new rock classification workflow that reconciles reservoir saturation-height behavior and mud-filtrate for more accurate dynamic reservoir modeling is developed and verified in both clastic and carbonate fields. Rock types vary and mix at the sub-foot scale in heterogeneous reservoirs due to depositional control or diagenetic overprints. Conventional well logs are limited in their ability to probe the details of each individual bed or rock type as seen from outcrops or cores. A bottom-up Bayesian rock typing method is developed to efficiently test multiple working hypotheses against well logs to quantify uncertainty of rock types and their associated petrophysical properties in thinly bedded reservoirs. Concomitantly, a top-down reservoir description workflow is implemented to characterize intermixed or hybrid rock classes from flow-unit scale (or seismic scale) down to the pore scale based on a multi-scale orthogonal rock class decomposition approach. Correlations between petrophysical rock types and geological facies in reservoirs originating from deltaic and turbidite depositional systems are investigated in detail. Emphasis is placed on the cause-and-effect relationship between pore geometry and rock geological attributes such as grain size and bed thickness. Well log responses to those geological attributes and associated pore geometries are subjected to numerical log simulations. Sensitivity of various physical logs to petrophysical orthogonality between rock classes is investigated to identify the most diagnostic log attributes for log-based rock typing. Field cases of different reservoir types from various geological settings are used to verify the application of petrophysical rock classification to assist reservoir characterization, including facies interpretation, permeability prediction, saturation-height analysis, dynamic petrophysical modeling, uncertainty quantification, petrophysical upscaling, and production forecasting.
Stratigraphy, sedimentology and petrophysics of transgressive tight gas sandstones, Almond Formation, Wyoming
(2017-08-04) Merletti, German Diego; Steel, R. J.; Torres-Verdín, Carlos; Fisher, William L; Olariu, Cornel; Ketcham, Richard A; Melick, Jesse J
With the recent increase in development of unconventional reservoirs, the ability to predict rock quality from sedimentary and petrophysical models has become paramount to the development of tight gas sandstones. In this way, a refined understanding of the primary sedimentary, stratigraphic and diagenetic controls on rock quality permits more reliable hydrocarbon distribution prediction and more economical drilling programs. The Almond Formation in southwest Wyoming is characterized by three depositional facies associations (DFA); shoreface, delta and fluvial/coastal plain, which present three distinctive porosity-permeability trends. Differences between petrophysical facies are primarily driven by diagenetic (cementation and grain dissolution) effects on different framework grain compositions. Depositional textural variation, such as grain size and sorting is minimal in all DFAs. This research focuses on building an understanding of the transgressive deposits by studying the variability of sandbody types, comparing and contrasting their reservoir architecture in a setting with a well-documented back-stepping stacking pattern. Construction of a high-resolution chronostratigraphic framework, in 1,450 wells over 6,200 km², revealed the evolution of fundamental fine-scale architectural elements. Detailed analysis and integration of cores and well logs along a spectrum of sandbodies document stratigraphic evolution from longshore accretion to seaward progradation associated with progressively increased infill of a shrinking lagoon. End members sandstone geometries include: 1) narrow, finger-like sandstone morphologies with well-developed lagoonal facies and; 2) broad, strandplain-type sandbodies with coastal plain-dominated back-barrier. This research also addresses a problematic aspect of tight gas reservoirs: the prediction of rock-quality-dependent water saturation (SW) models with depth. Primary drainage and imbibition saturation-height models (SHM) were developed from special core analysis and integrated with porosity and permeability logs to verify the SW state of reservoirs. Assuming that reservoirs were fully charged with hydrocarbons, the drainage SHM is key for flagging departures from the expected rock-quality-dependent water saturation. Observations in tens of wells show that the reference resistivity-derived saturation can be predominantly fitted by primary drainage SHM. However, some upper Almond shoreface bars that have anomalously high SW can be fitted with primary imbibition saturation functions. These fitting exercises indicate that some Upper Almond reservoirs imbibed due to trap tilting or leaking through outcrops.