Multidisciplinary Reservoir Characterization Research Articles

Forecast for thermal water use from Upper Jurassic carbonates in the Munich region (South German Molasse Basin)

A numerical thermo-hydraulic 3D model of the geothermal Upper Jurassic Aquifer (Malm) in the Munich region was developed based on a multidisciplinary reservoir characterization. The mutual hydraulic and thermal interference of 13 deep geothermal plants with 28 wells, pressure and temperature changes of the aquifer, and the total geothermal potential of the reservoir were investigated. Long-term (50 years) simulations forecast temperature decreases which only occur in the close vicinity of the individual reinjection wells, and mostly minor hydraulic interference in adjacent wells. Operators can use the 3D finite-element model, for the sustainable management of the thermal reservoir after updating the input by additional well data.

Sweet spot identification in underexplored shales using multidisciplinary reservoir characterization and key performance indicators: Example of the Posidonia Shale Formation in the Netherlands

Sweet spot identification in underexplored shale gas basins needs to be based on a limited amount of data on shale properties in combination with upfront geological characterization and modelling, because actual production data is usually absent. Multidisciplinary reservoir characterization and integration of modelling approaches can aid initial site selection for exploratory drilling and de-risk exploration efforts. In this study, the potential of hydrocarbon production across underexplored shale basins is analyzed using key performance indicators. A mean indicator is defined as the harmonic mean of three performance indicators that describe the potential for hydrocarbon generation, storage, and flow stimulation. The performance indicators are based on a limited number of local shale properties, i.e. vitrinite reflectance, porosity, depth, thickness, sorbed gas content and brittleness index. Values for the indicators are calculated relative to prospective North American shales (Marcellus, Bakken, Haynesville and Barnett), so that the mean indicator can be used to rank the prospectivity of an underexplored shale relative to hydrocarbon producing shales. The mean performance indicator is also used to map out the potential for gas production in the underexplored Posidonia Shale Formation in the West Netherlands Basin. The analysis shows that the performance indicator is lower for the Posidonia than for the North American Shales, mainly due to low maturity and brittleness. Local maxima of the indicator correlate with local maxima in vitrinite reflectance and depth. Besides the low potential for flow stimulation, the potential for hydrocarbon generation and storage capacity of the Posidonia are comparable to oil-window thermal-maturity Barnett Shale. Upfront simulations of hydraulic fracture properties and gas production in the Posidonia Shale Formation are in rough agreement with observed average gas flow for Barnett wells in non-core areas that are oil mature. It shows that key performance indicators can be applied to underexplored shales to quantify prospectivity and map out sweet spots across shale basins.

A multi-scale approach to improve reservoir characterization and forecasting: the Albacora Field (deep-water offshore Brazil) study

The Upper Albian Namorado Sandstone is one of the reservoirs of the Albacora Field, located in the Campos Basin, deep-water offshore Brazil. It is a sand-rich turbidite system where the most important controls on permeability are calcite cementation, thin beds of non-reservoir lithologies and some north–south trending faults. A major multidisciplinary reservoir characterization project was conducted to improve the reservoir description using all available data. In this paper, we focus on how the effect of rock heterogeneities were represented in the fluid flow model and on the performance obtained from this model. The basic idea was to define a hierarchical model of facies established on the basis of three main work scales: porous systems (thin sections and core sample scale); composite facies (whole core and log scale); and seismic facies (interwell to field scale). An up-scaling technique, based on the geopseudo concept, was used to generate the effective petrophysical properties for the fluid-flow simulation model. A Markov–Bayes geostatistical simulation method was applied in facies stochastic modelling. The sophisticated model that was built allowed very fast history matching.

Shooting direction and crosswell seismic data acquisition

Four crosswell seismic surveys were acquired in the Glenn Pool Field of northeastern Oklahoma as part of a multidisciplinary reservoir characterization project. The acquisition goal was to generate data suitable for tomographic traveltime inversion. Acquisition parameters and shooting geometry were selected by conducting a parameter test at the site. Following the parameter test, the first survey resulted in high quality data showing clear first arrivals, low ambient noise, some reflection events, and strong source‐generated tube waves. The second survey involved a different receiver well and encountered high ambient noise levels. The noise was strong enough to prohibit first‐arrival picking for much of the data. On‐site analysis of the second survey revealed tube waves emanating from a perforated interval in the receiver well. This well was shut in and was not flowing fluid or gas at the surface. We interpret the source of ambient tube waves as borehole‐to‐formation fluid flow (circulation) associated with the perforations. Since this image plane was important for characterization of the reservoir, the survey was reshot (third survey) by reversing sources and receivers in the two wells. The resulting high‐quality data indicates that shooting direction can be an important factor in crosswell seismic acquisition. This experience influenced acquisition of a previously planned fourth survey so that the ambient noise problem would be avoided.

Integrated, Multidisciplinary Reservoir Characterization, Modeling and Engineering Leading to Enhanced Oil Recovery from the Midway-Sunset Field, California: ABSTRACT

The Pru Fee property is developed in a heavy oil, Class III (slope and basin clastic sand), reservoir of the Midway-Sunset field, San Joaquin Basin, California. Wells on the property were shut-in with an estimated 85% of the original oil remaining in place because the reservoir failed to respond to conventional cyclic steaming. Producibility problems are attributed to the close proximity of the property to the margin of the field. Specific problems include complex reservoir geometry, thinning pay, bottom water, and dipping beds. These problems are likely common at the margins of the Midway-Sunset and other Class III reservoirs. This project forms the first step in returning the property to production and explores strategies that might be applied elsewhere. Reservoir characterization, modeling, and engineering methods are integrated to design, simulate, and implement a pilot steam flood. A new drillhole provides good quality, core through the pay zone and a full suite of geophysical logs. Correlations between geological and petrophysical data are used to extrapolate reservoir conditions from older logs and yield a 3-dimensional petrophysical model. Numerical results illustrate how each producibility problem might influence production and provide a framework for designing the pilot steam flood. This first phase illustrates howmore » a multidisciplinary team can use established technologies in developing the detailed petrophysical, geological, and numerical models needed to enhance oil recovery from marginal areas of Class III reservoirs.« less

Integrated Multidisciplinary Reservoir Characterization of a Deltaic System-1: Architecture and Lithofacies of the Cretaceous-Age Ferron Sandstone, East-Central Utah: ABSTRACT

Integrated Multidisciplinary Reservoir Characterization of a Deltaic System-1: Architecture and Lithofacies of the Cretaceous-Age Ferron Sandstone, East-Central Utah: ABSTRACT

Integrated Multidisciplinary Reservoir Characterization of a Deltaic System - 2: Developing a Petrophysical Model for Reservoir Simulation Using Data From the Ferron Sandstone, Utah: ABSTRACT

Integrated Multidisciplinary Reservoir Characterization of a Deltaic System - 2: Developing a Petrophysical Model for Reservoir Simulation Using Data From the Ferron Sandstone, Utah: ABSTRACT

Multidisciplinary Reservoir Characterization and Simulation Study of the Weyburn Unit

Summary Reservoir characterization is important to EOR and numerical simulation studies, especially for complex naturally fractured reservoirs with low-permeability matrix rock. Solvent movement and volumetric sweep are controlled by fracture distribution and connectivity and by matrix permeability variation. All these factors were considered in our reservoir characterization and simulation study. The reservoir characterization was so effective that, in a 63-well simulation study, 70% of the wells were history matched on the first simulation runs without modification to the original geologic/petrophysical data. This can be attributed to the team approach of using geological, reservoir engineering, and petrophysical input. Introduction The Weyburn Unit, in the southeastern corner of Saskatchewan, has produced medium-gravity crude oil from the fractured, low-permeability Midale beds of the Mississippian Charles formation since its discovery in 1954. Even though the Weyburn Unit has been on waterflood for more than 26 years, a significant target for EOR, horizontal wells, and waterflood optimization remains. The Weyburn field is located ~130 km southeast of Regina, Sask. (Fig. 1). The productive portion of the field covers ~180 km2. The field currently has 627 producing wells and 162 water injection wells on ~24-ha spacing. The Midale beds of the Weyburn field were produced by primary depletion from discovery until 1964, when an inverted nine spot waterflood scheme was implemented. Since 1985, both horizontal and vertical infill drilling programs have been undertaken to optimize waterflood performance. The Midale beds of the Mississippian Charles formation were deposited on a shallow carbonate shelf in the Williston basin. The reservoir is informally subdivided into the upper Marly and the lower Vuggy zones (Fig. 2). The Marly is a chalky intertidal dolostone with occasional limy or limestone interbeds. Porosity in the dolostones ranges from 16% to 38%, with an average of about 26%. Matrix permeability within this reservoir horizon ranges from 1 to >100 md, with an average of <10 md.