Geological surface reconstruction from 3D point clouds

The numerical simulation of phenomena such as subsurface fluid flow or rock deformations are based on geological models, where volumes are typically defined through stratigraphic surfaces and faults, which constitute the geometric constraints, and then discretized into blocks to which relevant petrophysical or stress-strain properties are assigned. This paper illustrates the process by which it is possible to reconstruct the triangulation of 3D geological surfaces assigned as point clouds. These geological surfaces can then be used in codes dedicated to volume discretization to generate models of underground rocks. The method comprises the following: - Characterization of the best fitting plane and identification of the concave hull of the point cloud which is projected on it - Triangulation of the point cloud on the plane, constrained to the Planar Straight Line Graph constituted by the concave hull The algorithm, implemented in C ++ , depends exclusively on two parameters (nDig, maxCut) which allow one to easily evaluate the optimal refinement level of the hull on a case by case basis

Graphene-Based Membrane Technology: Reaching Out to the Oil and Gas Industry

This paper presents a critical review and the state of the art of graphene porous membranes, a brand-new technology and backdrop to discuss its potential application for efficient water desalination in low salinity water injection (LSWI). LSWI technology consists in injecting designed, adequately modified, filtered water to maximize oil production. To this end, desalination technologies already available can be further optimized, for example, via graphene membranes, to achieve greater efficiency in water-oil displacement. Theoretical and experimental applications of graphene porous membranes in water desalination have shown promising results over the last 5-6 years. Needless to say, improvements are still needed before graphene porous membranes become readily available. However, the present work simply sets out to demonstrate, at least in principle, the practical potential graphene membranes would have in hydrocarbon recovery processes

Capturing channelized reservoir connectivity uncertainty with amalgamation curves

During reservoir characterization all the geological uncertainties affecting the quantity and distribution of hydrocarbons should be captured to assess the risks affecting final recovery. In a typical modeling workflow the geological uncertainties are accounted for through the construction of a sufficiently large set of 3-D static models. Out of this set, a few representative models are selected and dynamically simulated so as to correlate the geological characteristics of the reservoir with its dynamic performance and to propagate the uncertainty onto the final recovery factors yet maintaining the computational run time acceptable. In channelized depositional environments, which are strongly heterogeneous, the selection approach must also account for channel connectivity, which plays a key role in the possibility of efficiently draining the reservoir for a reasonable number of wells. This study can be seen as a step forward in the assessment of the risks associated to the development of channelized reservoirs under the assumption that a way to express the concept of channel connectivity is channel amalgamation. Channel amalgamation is here defined through amalgamation curves which are numerically described using a set of indexes whose combination provide spatial information of channel intersections. These indexes were calculated for a full set of 3-D geological models and used to steer the selection of a representative model sub-set for subsequent fluid flow simulations. The validity of the index-based selection was verified on different sets of synthetic reservoir models through the evaluation of the representativeness of the model sub-set in reproducing the uncertainty of the original dataset. Eventually, the existence of a strong correlation between channel amalgamation and production performance was proved. From a practical perspective, the possibility to include channel amalgamation in the assessment of the geological models can considerably improve the representativeness of the selected models for uncertainty propagation thus reducing significantly the number of geological models to be considered

Estimation of skin from the interpretation of injection tests in fractured reservoirs

Injection/fall-off testing is one of the unconventional well test methodologies used to eliminate hydrocarbon flaring and thus gas emissions into the atmosphere. Except for fluid sampling, all of the main well testing targets can be achieved, while complying with the environmental regulations. However, the interpretation of injection tests in oil reservoirs is complicated by the presence of two immiscible mobile phases in the reservoir: the hydrocarbon originally in place and the injected fluid. As a result, the total fluid mobility is reduced and an additional pressure increment occurs, which affects the total skin with an additional bi-phase skin component. Furthermore, natural or induced fractures can be intercepted by the well, reducing the total skin but adding complexity to the test interpretation. Typically, the application of traditional analytical models to interpret injection tests only provides the total well skin while its mechanical component, due to permeability damage in the near wellbore zone, cannot be isolated. However, the mechanical skin is a fundamental well testing target because it is essential to estimate well productivity. In this paper, an effective correlation to determine the mechanical, the fracture and the bi-phase components of the skin in the case of injection tests is presented; this correlation was empirically derived with the aid of a numerical simulator. The equation expresses the total skin as a linear composition of the three skin components and is of general applicability; in mono-phase flow conditions or in the absence of fractures it reduces to well-known formulas available in the technical literature. By means of this equation the true permeability damage can be assessed and, in turn, well productivity calculated. Additionally, the total skin factor and thus the expected pressure increase during injection can be estimated when designing a well test. A real field case where the formula was successfully applied is presented in the paper

Estimation of skin in the interpretation of injection tests in fractured reservoirs

Injection/fall-off testing is one of the unconventional well test methodologies used to eliminate gas emissions into the atmosphere. Except for fluid sampling, all of the main well testing targets can be achieved, while complying with the environmental constraints. However, the interpretation of injection tests in oil reservoirs is complicated by the presence of two immiscible mobile phases in the reservoir: the hydrocarbon originally in place and the injected fluid. As a result, the total fluid mobility is reduced and an additional pressure increment occurs, which affects the total skin with a supplementary bi-phase skin component. Furthermore, natural or induced fractures can intercept the well, reducing the total skin but adding complexity to the interpretation. Typically, the application of traditional analytical models only provides the total well skin while its mechanical component, due to permeability damage in the near wellbore zone, cannot be isolated. However, the mechanical skin is a fundamental well testing target because it is essential to estimate the well productivity. An effective relationship to determine the mechanical, the fracture and the bi-phase components of the skin in the case of injection tests was empirically derived with the aid of a numerical simulator. The equation expresses the total skin as a linear composition of these three components and is of general applicability; in mono-phase flow conditions or in the absence of fractures it reduces to well-known formulas available in the technical literature. By means of this equation the true permeability damage can be assessed and, in turn, the well productivity calculated. Additionally, the total skin factor and thus the expected pressure increase during injection can be estimated when designing a well test. A real field case where the formula was successfully applied is presented in the pape

Estimation of skin from the interpretation of injection tests in fractured reservoirs

Injection/fall-off testing is one of the unconventional well test methodologies used to eliminate hydrocarbon flaring and thus gas emissions into the atmosphere. Except for fluid sampling, all of the main well testing targets can be achieved, while complying with the environmental regulations. However, the interpretation of injection tests in oil reservoirs is complicated by the presence of two immiscible mobile phases in the reservoir: the hydrocarbon originally in place and the injected fluid. As a result, the total fluid mobility is reduced and an additional pressure increment occurs, which affects the total skin with an additional bi-phase skin component. Furthermore, natural or induced fractures can be intercepted by the well, reducing the total skin but adding complexity to the test interpretation. Typically, the application of traditional analytical models to interpret injection tests only provides the total well skin while its mechanical component, due to permeability damage in the near wellbore zone, cannot be isolated. However, the mechanical skin is a fundamental well testing target because it is essential to estimate well productivity. In this paper, an effective correlation to determine the mechanical, the fracture and the bi-phase components of the skin in the case of injection tests is presented; this correlation was empirically derived with the aid of a numerical simulator. The equation expresses the total skin as a linear composition of the three skin components and is of general applicability; in mono-phase flow conditions or in the absence of fractures it reduces to well-known formulas available in the technical literature. By means of this equation the true permeability damage can be assessed and, in turn, well productivity calculated. Additionally, the total skin factor and thus the expected pressure increase during injection can be estimated when designing a well test. A real field case where the formula was successfully applied is presented in the paper

A novel approach to a quantitative estimate of permeability from resistivity log measurements

Description of the material. In this paper a novel methodology for the estimation of the formation permeability, based on the integration of resistivity modeling and near wellbore modeling, is presented. Results obtained from the application to a real case is shown and discussed. The well log interpretation process provides a reliable estimation of the main petrophysical parameters such as porosity, fluid saturations and shale content, but the formation permeability is traditionally obtained through laboratory tests on plugs, at the scale of centimeters, and through well test interpretation, at the scale of tens or hundreds of meters. However, log measurements, and in particular resistivity logs, are strongly affected by the presence of the near wellbore zone invaded by mud filtrate. In turn, the extension of the invaded zone depends on formation properties and, in particular, on permeability. As a consequence, the resistivity measured by the tools (the apparent resistivity) has to be properly corrected through a resistivity modeling process to obtain the true formation resistivity and the geometry and resistivity of the invaded zone. Resistivity profiles within the invaded zone are function of fluid properties, petrophysical properties and rock-fluid interaction properties. The novelty of the approach is to numerically simulate the mud invasion phenomenon and match the resistivity profile provided by resistivity modeling to estimate the formation permeability. In the proposed methodology the match of the resistivity profile is obtained by integrating the near wellbore simulator with an optimization algorithm. Application. This novel approach was applied to a heterogeneous shaly-sand oil-bearing reservoir in the Norwegian offshore area. The analyzed sequence was characterized by a high degree of variations in the layers’ thickness, from meters down to below tools’ vertical resolution. A complete set of wireline logs were acquired in the considered well; several cores were cut and routine and special core analyses performed. Results, Observations, and Conclusions. First, a conventional petrophysical characterization was achieved and the appropriate resistivity corrections were calculated. Then, the modeled resistivity was used as the input for the optimization algorithm so as to obtain a continuous quantitative estimation of permeability in the entire logged interval. The results were satisfactorily compared to core measurements: in both thick conventional layers and thinner beds the match was very accurate. Significance of subject matter. The new approach provided a robust permeability estimate also in un-cored intervals and, more generally, can be used to predict permeability in un-cored and un-tested wells