IRIS Pol. Torinohttps://iris.polito.itIl sistema di repository digitale IRIS acquisisce, archivia, indicizza, conserva e rende accessibili prodotti digitali della ricerca.Thu, 23 Sep 2021 09:52:30 GMT2021-09-23T09:52:30Z10311A novel approach to a quantitative estimate of permeability from resistivity log measurementshttp://hdl.handle.net/11583/2518498Titolo: A novel approach to a quantitative estimate of permeability from resistivity log measurements
Abstract: 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.
Tue, 01 Jan 2013 00:00:00 GMThttp://hdl.handle.net/11583/25184982013-01-01T00:00:00ZHarmonic Pulse Testing for Well and Reservoir Characterizationhttp://hdl.handle.net/11583/2693838Titolo: Harmonic Pulse Testing for Well and Reservoir Characterization
Abstract: For decades, well tests have been widely used in the oil industry for evaluation of well productivity and reservoir properties, which provide key information for field development and facilities design. In conventional well tests equilibrium conditions are required in the reservoir before the test. Furthermore, a single well only can be produced at a time, inducing one or more pressure draw-down periods followed by a final pressure build-up which are the object of the interpretation. Harmonic testing has been developed as a form of well testing that can be applied during ongoing production or injection operations, as a pulsed signal is superimposed on the background pressure trend. Thus no interruption of well and reservoir production is needed before and during the test. If the pulsed pressure and rate signal analysis is performed in the frequency domain, a strong similarity exists between the derivative of the harmonic response function versus the harmonic period and the pressure derivative versus time, typical of conventional well testing. Thus the interpretation of harmonic well tests becomes very straightforward.
In this paper, we present the derivation of type curves for the most commonly encountered well and reservoir scenarios and we validate the type-curves developed for horizontal wells against real data of a harmonic test performed on a gas storage well in Italy.
Sun, 01 Jan 2017 00:00:00 GMThttp://hdl.handle.net/11583/26938382017-01-01T00:00:00ZA New 3-D Numerical Model to Effectively Simulate Injection Testhttp://hdl.handle.net/11583/1848631Titolo: A New 3-D Numerical Model to Effectively Simulate Injection Test
Abstract: Paper of SPE Europec/EAGE 2008
Tue, 01 Jan 2008 00:00:00 GMThttp://hdl.handle.net/11583/18486312008-01-01T00:00:00ZSuperposition, Convolution, Deconvolution, and Laplace: Pressure and Rate
Transient Analysis Revisited with Some New Insightshttp://hdl.handle.net/11583/2742571Titolo: Superposition, Convolution, Deconvolution, and Laplace: Pressure and Rate
Transient Analysis Revisited with Some New Insights
Abstract: Objectives/Scope: Rate and pressure transient analysis is considered a routine process that has been
developed and refined over many years. The underlying assumptions of linearity justify the use of
superposition (in time and space), convolution and deconvolution. The reality of non-linearities are handled
on a case by case basis depending on their source (fluid, well or reservoir). Shale gas wells are subject to
significant non-linearity over their producing life.
We review some of the fundamental equations that govern pressure and rate transient behavior, introduce
several new techniques which are suited to the analysis of data from producing wells and apply them to a
synthetic example of a shale gas well.
Methods, Procedures, Process: First, we use simple calculus to show how the convolution integral is
derived from standard multi-rate superposition. Then, from the convolution integral, we derive an equation
that describes the pressure response due to a step-ramp rate (i.e. an instantaneous rate change from initial
conditions followed by a linear variation in rate). It results in a combination of the pressure change due
to a constant rate and it's integral. Applying superposition to this equation allows any rate variation to be
approximated by a sequence of ramps with far fewer points than those required to achieve the same level
of accuracy using standard constant step rate superposition.
Second, we re-write multi-rate superposition functions allowing for stepwise linear variable rate which,
when applied to flowing data and used to calculate the pressure derivative, can result in a much smoother
response and hence an overall improvement in the analysis of rate and pressure transients recorded from
producing wells.
Third, we review the use of the Laplace transform and how it can be applied to discrete data with a view
to deconvolving rate transient data.
Finally, we demonstrate how data de-trending can remove the impact of long term non-linearities and
apply the methods mentioned above to a synthetic dataset based on a typical shale gas well production
profile.
Results, Observations, Conclusions: We illustrate the advantages of the newly introduced superposition
functions compared to conventional analysis methods when applied to the pressure transients of wells
flowing at variable rate.
As an example, we have simulated the production of two shale gas wells over twenty years. Both have
the same production profile, but one includes pressure dependent permeability. At various intervals during
the life of the well, we introduce a relatively short well test which imposes a small variation in rate but
does not include a shut-in. We de-trend the rate transients and then apply the techniques described above to
analyse the resulting data. The interpretation allows us to identify non-linearities that may be influencing
well productivity over time and to obtain a better understanding of the physics of shale gas production.
The mathematics documented in the paper provides a useful overview of how convolution, superposition,
deconvolution and Laplace transforms provide the means to analyse pressure and rate transients for linear
systems.
Data de-trending removes the impact of long term non-linearities on shorter transient test periods.
Novel/Additive Information: We develop and demonstrate some new and improved techniques for rate and
pressure transient analysis, and we illustrate how these can provide insight into the non-linearities affecting
shale gas production.
Tue, 01 Jan 2019 00:00:00 GMThttp://hdl.handle.net/11583/27425712019-01-01T00:00:00ZA novel approach to a
quantitative estimate of
permeability from resistivity
log measurementshttp://hdl.handle.net/11583/2742572Titolo: A novel approach to a
quantitative estimate of
permeability from resistivity
log measurements
Abstract: 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.
Mon, 01 Jan 2018 00:00:00 GMThttp://hdl.handle.net/11583/27425722018-01-01T00:00:00ZStudy of reservoir production
uncertainty using channel
amalgamationhttp://hdl.handle.net/11583/2630635Titolo: Study of reservoir production
uncertainty using channel
amalgamation
Abstract: The characterization of a reservoir’s internal architecture is a major challenge, especially during the
reservoir appraisal phase when the information is limited. At this stage, all the uncertainties affecting
the quantity and distribution of hydrocarbons in the reservoir should be captured and accounted
for in the evaluation of the final recovery to properly assess the viability of any development plan.
A typical modeling workflow accounting for geological uncertainties consists in creating a large set
of 3-D geological (static) models, selecting a few representative realizations out of this set based on
the calculated hydrocarbons originally in place and simulating future production from the selected
reservoir models for fixed well count and locations so as to propagate the uncertainty onto the final
recovery factors. However, in channelized reservoirs connectivity plays a key role in the possibility of
efficiently draining the reservoir with a reasonable number of wells, thus the subset of representative
realizations should be selected not only based on the hydrocarbons originally in place but also
based on the connectivity among the channels. To this end, an index quantifying the channel static
connectivity was defined in the literature but it is demonstrated in this paper that this index fails to
account for the internal architectural layout of the reservoir, namely amalgamation, which reflects
the quality of the connectivity between channels. Thus, a new index is proposed by the authors to
quantify channel amalgamation and steer the selection of representative geological models for
subsequent fluid flow simulations. This new index was calculated for a series of synthetic channelized
3-D static models characterized by different degrees of channel sinuosity. Each model was then
dynamically simulated under the same production constraints and the final hydrocarbon recovery
was obtained. Eventually, the existence of a relation between channel amalgamation and production
performance was assessed to prove the validity of the proposed index as a sampling criterion.
The results confirmed that channel amalgamation, more than static connectivity, affects reservoir
performance thus can be a better indicator to capture reservoir uncertainty. Nonetheless, the use
of a global indicator still presents limits in the description of the internal geological setting of the
reservoirs and this has implications in achieving an accurate selection of a subset of equiprobable
models. Only by introducing information related to the spatial distribution of amalgamation these
limits could be overcome in the future.
Thu, 01 Jan 2015 00:00:00 GMThttp://hdl.handle.net/11583/26306352015-01-01T00:00:00ZApplicability of Newton-based Optimization Method Merged with the Monte Carlo Approach to Log Interpretationhttp://hdl.handle.net/11583/1949094Titolo: Applicability of Newton-based Optimization Method Merged with the Monte Carlo Approach to Log Interpretation
Tue, 01 Jan 2008 00:00:00 GMThttp://hdl.handle.net/11583/19490942008-01-01T00:00:00ZEstimation of skin in the interpretation of injection tests in fractured reservoirshttp://hdl.handle.net/11583/2507309Titolo: Estimation of skin in the interpretation of injection tests in fractured reservoirs
Abstract: 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 paper.
Tue, 01 Jan 2013 00:00:00 GMThttp://hdl.handle.net/11583/25073092013-01-01T00:00:00ZConsiderations on energy transitionhttp://hdl.handle.net/11583/2812471Titolo: Considerations on energy transition
Abstract: In the future, we will experience a continuously increasing energy demand mostly due to the continuous growth of the world population.Today we use fossil fuels (coal, oil and gas) in order to cover the society's basic needs. This involves significant CO2 emissions that contribute to the climate change by contributing to the increase of the global temperature. A great number of countries through international agreements are working on energy transition towards renewable energy resources targeting to a sustainable future. In reality though the path the world has to follow is still long and the transition towards a green future cannot be immediate. Some of the most populated countries still rely on coal as their main energy source while oil is still the most frequently used fuel in transportation. Furthermore, the passage to new energy sources would mean new facilities and new distribution networks that are not economically possible for many countries. In this energy transition natural gas can play an important role as the mid-point between traditional fossil fuels and renewable energy sources. It produces lower emissions than coal and oil, the facilities for its extraction and transportation already exist in many countries and can support the energy consumption needs of the modern society. In combination with CO2 capture and sequestration applications it can provide a realistic (greener) transition towards a fossil-fuel free future.
Tue, 01 Jan 2019 00:00:00 GMThttp://hdl.handle.net/11583/28124712019-01-01T00:00:00ZEstimation of skin from the interpretation of injection tests in fractured reservoirshttp://hdl.handle.net/11583/2633990Titolo: Estimation of skin from the interpretation of injection tests in fractured reservoirs
Abstract: 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.
Thu, 01 Jan 2015 00:00:00 GMThttp://hdl.handle.net/11583/26339902015-01-01T00:00:00Z