Abstracts of the Tenth Symposium
Reservoir
Fluids Identification Using Vp/Vs
Crossplot
by
Hamada,
G.M., Faculty of Engineering, Cairo University, Giza, Egypt,
Sonic
travel time of compressional wave is generally used as porosity tool for given
lithology. Introducing shear wave travel time is very helpful in determining
mechanical rock properties. It is found that compressional wave is sensitive to
the saturating fluid type. The use of the ratio of compressional wave velocity
to shear wave velocity" Vp/Vs" is a good tool in identifying fluid
type. The fact that compressional wave velocity decreases and shear wave
velocity increases with the increase of light hydrocarbon saturation, makes the
ratio of Vp/Vs more sensitive to change of fluid type than the use of Vp or Vs
separately. Field examples are
given to identify fluids type (water, oil and gas) using the Vp/Vs ratio. Field examples have shown that shear
travel time decreases while compressional travel time increases when the water
saturated points become gas or light oil saturated points in the studied
sections. The decrease of shear
travel time (increase of shear wave velocity) is due to the decrease of density
and the absorption of deformation by free gas in pores. The increase of
compressional travel time (decrease of compressional wave velocity) is due to
the decrease of bulk modulus of reservoir rocks which compensates the decrease
of rock density.
A new production
logging tool allows a superior mapping of the fluid velocities and holdups inside
the well bore
by
Hanaey D. Mostafa, Ali Al Marzooqi, Ghassan Abdouche,
Osama H. Khedr – Zadco and Antoine Elkadi – Schlumberger
Drawing the flow profile of the three phases (oil,
water and gas) downhole is the ultimate goal of production logging. However the
flow regimes that develop inside the well bore can be very complex (e.g.
stratification, mist, annular, recirculation, etc) and the mapping of the fluid
velocities and holdups inside the well bore is key to the proper evaluation of
the individual phases flowrates at every depth level along the survey interval.
The mapping ability of the present production logging tools is somewhat
limited; consequently big difficulties are encountered when interpreting data
sets that were acquired in such complex downhole conditions at the present
time.
The new tool is a Flow Scan Imager, which comprises
five micro-spinners, six electrical and six optical probes that get deployed
downhole once the tool is across the survey interval. Each micro-spinner will
evaluate the localized fluid velocity that is passing by it, whilst each
electrical and optical probe will respectively evaluate the localized water and
gas holdup that prevail around its place. When deployed, these sensors will be
positioned in such a way that their measurements will constitute a map of the
fluid velocities and holdups along a vertical cross section of the well bore at
every depth level thus enabling a superior estimation of the individual phases
flow rates in complex flow regimes downhole.
The new tool was run in a deviated well
for ZADCO in Abu-Dhabi. It has allowed the clear visualization, for the first
time, of water re-circulation downhole in an oil producer where the water cut
at surface is zero. This has given the operator a better insight in the
downhole conditions, which enabled him to plan a workover that will improve
substantially the well productivity.
The use of this tool in deviated and horizontal
wells will undoubtedly enable the operators to better understand their
production regimes, to define a more accurate flow profiles and consequently
plan more efficient remedial works or production strategies, which will
inevitably improve their ultimate hydrocarbon recovery.
SEISMIC AND WELL LOGGING ANALYSES OF BAHARIYA FORMATION IN AGHAR OIL FIELD, NORTHERN WESTERN DESERT, EGYPT.
by
GadAllah, M., Samir, A., Ghoneimi, A. and Nabih,
M.A.
Geology
Department, Faculty of Science, Zagazig University
The aim of this
study is to investigate the structural regime and reservoir characteristics of Aghar
oil field. The available data include twenty five seismic sections and well
logging data of five wells.
The structural
analysis involves the construction of structure contour maps, in terms of time
and depth, on the tops of Baharyia and Alamein Formations. These maps show three structural
closures on the top of Baharyia Formation, due to folding, that are dissected
by faults of ENE-WSW trend. These
faults constitute a graben and two step-like faults. Two structural closures are encountered on the top of
Alamein Dolomite, which is dissected by a larger number of faults having the
same trend as that of Baharyia Formation.
The well log
analysis of Baharyia Formation includes the digitizing, data base editing, data
corrections and formation evaluation. It was found that, the total porosity
varies from 26% to 35 %, the effective porosity ranges between 12 % and
23 %, the water saturation differs from 10 % to 90 %, the shale content
lies between 25 % and 59 % and the net-pay thickness of Baharyia Formation
varies from 39 to 229 ft. The
reservoir characteristics of Baharyia Formation indicate that the most
favorable places for oil production are the northern and northeastern parts of
the area which were considered for petrophysical analysis.
Theoretical
and Numerical Justifications of Formation Rate Analysis (FRA)
by
J.
Sheng, D. Georgi and A. Mezzatesta, Baker Atlas
Formation
Rate Analysis (FRA) is a technique used in the analysis of pressure and rate
data acquired with formation testing tools. The technique was derived based on
several approximations. Although the technique has been used successfully to
analyze formation pressure tests derived from both wireline and MWD
instruments, it has sometimes been challenged for lacking a solid theoretical
background, for example, whether it can be derived from the general diffusivity
flow equation.
This
paper discusses the theoretical and numerical justifications of FRA using the
steady-state solution for spherical flow, as well as numerical solutions to the
general diffusivity equation. The solution to spherical flow indicates that the
time required to reach steady-state flow is almost ignorable in practical
formation tests. Therefore, the flow in practical tests can be described by the
steady-state flow equation, which is one of the main assumptions used in FRA
formulation. The numerical solutions to the general diffusivity equation show
the dimensionless wellbore pressure drop is approximately equal to the
dimensionless sand face rate in spherical reservoirs inclusive of wellbore
storage, phase redistribution and skin. This relationship is implicitly
required in FRA. Consequently, the validity of this relationship proves the FRA
validity from the fundamental principles of spherical flow. Simulated and field
tests are used to support these theoretical and numerical justifications.
by
J.
Sheng, Baker Atlas
Formation Rate
Analysis (FRA) is a technique used in the analysis of pressure and rate data
acquired with formation testing tools. It uses the relationship between the
pressure drop and the sand face formation rate in formation tests. The
technique has been used extensively to estimate reservoir pressure and
mobility. The initial use of the technique assumed isotropic formation.
Consequently, the discrepancy between the permeability estimates from different
sources or from different analyses is not resolved. Use of the technique to
identify test conditions was also limited.
This paper first
presents the formation rate analysis (FRA) in an anisotropic formation. The use
of FRA in an anisotropic formation resolves the discrepancies between the
permeability estimates not only from different sources but also from different
analysis methods. It also provides an indication of formation damage.
Numerically, the effect of anisotropy and formation damage can be described by
the geometric factor used in the FRA technique. These values are theoretically
derived and numerically verified in this paper.
One of the most important uses of FRA is
to use the FRA plot (pressure drop vs. formation rate plot) to identify various
reservoir and fluid flow conditions. To this end, a number of simulated
pressure tests generated under different practical test conditions are
analyzed, and the corresponding FRA plots are presented. A number of effects on
the FRA plot are investigated, such as tight formation, flowing pressure below
the bubble point, mud filtrate invasion, supercharging, gauge resolution, and
rate measurement error. Actual field tests are also used to present the FRA
plots under these conditions. The information from these FRA plots is very
useful in a real time job, for example, in a sampling job, where the flowing
pressure below the bubble point could be identified from a FRA plot.
Estimate
Horizontal and Vertical Permeability from Combining FRA and Buildup Analysis
by
J.
Sheng, A. Mezzatesta and D. Georgi, Baker Atlas
To estimate formation
permeability from the probe test pressure data, the Formation Test Analysis
(FRA) or buildup analysis is used. The FRA uses the relationship between the
measured pressure and the sand face formation rate in a probe test, from which
the FRA permeability is derived. The FRA technique uses a geometric factor to consider
the non-spherical flow near the probe. The value of the geometric factor
strongly depends on the ratio of vertical to horizontal permeability, which is
unknown before the test is performed. The FRA estimated permeability does not
match the formation spherical permeability unless the correct geometric factor
is used. In addition, the spherical permeability can be obtained from a buildup
analysis without prior knowledge of formation anisotropy. Separately considered, neither method
provides the means to decompose the estimated formation permeability into its
horizontal and vertical components.
This paper presents a
method to estimate horizontal and vertical permeability by combining the
results of the two analysis procedures, FRA and pressure build up. The combined
results allow for estimating the geometric factor that corresponds to the level
of anisotropy of the formation. Subsequently, the ratio of vertical
permeability to horizontal permeability is determined based on the knowledge of
the geometric factor as a function of anisotropy derived from a separate work.
Finally, the knowledge of spherical permeability and anisotropy allows for
splitting the spherical permeability into its vertical and horizontal
components. The method is verified through simulated probe tests and validated
through several field examples.
3D Facies Model for Carbonate Sequences in the
Asmari reservoir, Parsi Field, South of Iran.
by
Ghanavati.k, Nisoc Co,
Iran, Samadi.M.H, Kanaz Moshaver Co., Iran
The Parsi Field is a relatively simple, slightly
asymmetric NW-SE trending anticline some 36km long by 7km wide lying in
Khuzestan, at the southwest edge of the Zagros mountain belt in the north
central part of the Dezful Embayment.
To model reservoir behavior it is important to understand
the lateral continuity of permeability barriers and conduits. This requires a geological model to map
out the likely variation in depositional environments.
Reservoir quality within carbonates is the product of
both facies and diagenetic history.
The prediction of lithology alone is, therefore, insufficient to
describe pore systems and a different approach is required.
2D modeling techniques have for many years been used as
the primary method of generating reservoir descriptions. Improvements in data
quality and an increased understanding of the reservoir have led to the
conclusion that these methods are often inadequate.
Through the use of multi-variate analysis it is possible
to predict lithotype, i.e. a particular combination of lithology and attendant
reservoir parameters. Where
calibrated with well data these lithotypes can be related to lithofacies. The purpose of calculating lithotype is
to help populate the geological model with appropriate reservoir parameters
through statistical methodologies.
Few of the wells in the Parsi Field have much core
information and the main recourse for the calculation of reservoir parameters
has therefore been the thorough analysis of electric log curves. The analysis of these curves requires
that they be calibrated to the core data that does exist.
Core from the PR-19 and PR-33 wells along with the
lithologic descriptions available from the Parsi area established the set of
criteria used to divide the Asmari and subjacent sediments in five
bio-lithofacies (A, B, C, D, and E).
These facies and criteria are shown on Table 1. Facies definition is supplemented by
fossil criteria. A summary; of
fossils versus depositional environment, compiled from literature, is shown in
Table 2. The total assemblage (criteria)
of sedimentary features as well as lack of certain features and their vertical
succession are used in defining the Asmari facies.
A New Integrated Workflow to Optimize NMR Applications in Carbonate
& Sandstone Reservoirs
by
N.
Al-Adani (Schlumberger), S. Hejri (PETRAN), M. Vaziri (PETRAN),
A.
Barati (PEDCO) and S. Yilmaz (Schlumberger).
With more constrains
on operation budget, sometimes some vital data acquisition, like cores get
dropped from the program. In this case, log data values should be optimized to
meet the expected results from core analysis. In addition, logs represent
closer scale to what is required by simulation engineers for their reservoir
evaluation.
In this paper, new
workflow was established to optimize NMR applications through integration with
all available logs across sandstone and carbonate. The objective is to provide
in absence of core from log data the effective porosity, wettability, fluid
contacts, residual fluid saturations, capillary water saturation, and reliable
permeability profile. All integration processes are demonstrated on an example
data from an offshore well drilled with an oil base mud. Nearby wells core data
were compared in this study as well.
Combining NMR and Stoneley
analysis for a better estimation of permeability in carbonate reservoirs.
by
Mohamed
Tchambaz, Schlumberger Oilfield Services.
Continuous curve of
permeability derived from NMR provides an important data for reservoir
characterization, but frequently affected by uncertainties related to the
intrinsic properties of the porous media.
The Stoneley slowness
analysis brings as well valuable information for permeability approach, however
it is influenced by different borehole fluid and formation parameters.
Both investigations can be combined as
complementary analysis, minimizing the uncertainties and providing more
information about the characteristics of porous network in carbonate
reservoirs.
After a discussion of
the NMR and Stoneley methods limitations, uncertainties are explained for different
types of porous media, dual porosities and range of permeability.
The presented methodology consists of an
integration of the estimated results from NMR and Stoneley computations with a
comprehensive evaluation-interpretation providing more representative approach
of permeability.
Equations are combined
and adjusted in order to evaluate the different variations of the porous
network properties including isolated and secondary porosities. To reduce the
permeability estimation uncertainties, a calibration is completed using the
mobility from formation tester measurements.
An example of
carbonate reservoir is shown to highlight the improvement obtained by this
combination.
Dispersive
Semblance Processing of Leaky-Compressional Mode from LWD Sonic Data in Very
Slow Formation
by
Takeshi Endo1, Shinji Yoneshima1 and Henri-Pierre Valero1
1Schlumberger
Oilfield Services
In shallow
un-consolidated formations, compressional slowness becomes close to the
borehole fluid (mud) slowness or sometimes slower than the mud. In these special conditions, the large
amplitude fluid arrivals are excited, which dominate the compressional head
waves making difficult to measure the compressional slowness of the
formation. In such situation, in wireline sonic the low frequency
leaky-compressional mode, less corrupted by fluid arrivals, is used to measure
the compressional slowness. The leaky-compressional mode is a dispersive
borehole mode with the phase slowness increasing with increasing frequency, propagating
at the formation compressional slowness at low frequency and at the mud
slowness at high frequency. A challenge for leaky-compressional processing is
to accurately correct the dispersion effect in order to measure the formation
compressional slowness. For wireline sonic data, Valero et al. (2003) developed
the dispersive semblance processing to measure the compressional slowness from
the leaky-compressional mode. This technique applies the dispersion correction
in the semblance computation based on the model dispersion curves and also the
ability to automatically determine the optimal processing frequency band.
Recent advent of
wideband LWD-Sonic measurements, which have significant energy in low
frequency, enabled us to apply the same technique to LWD-Sonic data. In order
to validate the processing technique for LWD-Sonic environment, waveform
modeling with a realistic tool model in the borehole was performed. This new
processing technique was first applied on synthetic waveforms, with this tool
model, computed for different borehole/formation conditions. Simultaneously,
the effects of processing parameter errors were also evaluated. These
simulations demonstrated that this method was able to successfully recover the
compressional slowness. After the validation, this dispersive semblance
processing was applied to real LWD Sonic data with the wideband acquisition in
ODP sites, 1173B and 808I. The processing results obtained with this enhanced
methodology are compared to core slowness measurements.
by
J. Drew,P.Primeiro
(Schlumberger Kabushki Kaisha), D. Leslie, G. Michaud, and L. Eisner
(Schlumberger Cambridge Research) and K.Tezuka (JAPEX)
Microseismic data was acquired and processed in October
2003, in realtime, during a hydraulic injection test at the Japex Yufutsu gas
reservoir using a 4-level Schlumberger VSI multicomponent borehole geophone
array. Wellsite processing enabled the realtime determination of event count,
correlation with injection process parameters, and preliminary event locations.
Subsequent processing using a more complicated velocity model has resulted in
improved event locations, and a characterization of microseismic events in
terms of moment magnitude and shear-to-compressional amplitude ratios. While
observations made from the remote monitoring well have revealed a geometrical
trend of microseismic event locations, uncertainty analysis demonstrates that
the orientation of the induced fracture is not well constrained with the
limited aperture array which was available. However, S-to-P amplitude ratios distinguish the shallow and
deep events. Waveform cross-correlation and clustering analysis has also
yielded several large groups of multiplets, which are consistent with the
observed grouping based on S-to-P
ratios, and with grouping based on absolute event location. Localization
uncertainties are derived from likelihood functions, dependent on measurement
uncertainty and geometrical sensitivity functions which are controlled by the
poor geometrical coverage in this experiment. Survey design techniques are
presented to illustrate how uncertainty can be reduced and localization
improvement could be achieved.
Waveform analyses for the Yufutsu HFM
experiment, Hokkaido, Japan.
by
P.Primeiro (Schlumberger
Kabushki Kaisha), L. Eisner (Schlumberger Cambridge Research) and K.Tezuka (JAPEX)
Waveform inversion of seismic
moment tensor is a method to estimate source parameters by comparing the
recorded seismic waveforms with synthetic Green痴 functions.
The inverted moment tensor
contains crucial information about seismic sources and the fracturing
mechanism. Moment magnitude, strike and dip of the fractured faults and
volumetric and deviatory components of observed micro-seismic events can be
extracted.
We performed a waveform analysis
for micro-earthquakes recorded during the
Yufutsu HFM experiment of October
2003. Strong attenuation in the particle velocity spectra was observed as the
amplitude decays linearly with the logarithm of the frequency.
This experiment poses a challenge
to waveform inversion as the micro-seismic events were observed by a single
vertical array of three-component sensors two kilometer away from the fractured
zone. Such geometry prevents from retrieving the complete moment tensor. Our
unique technique enables to invert only such components that are constrained by
the experimental geometry.
With this technique we are able to
invert moment magnitudes for the events with good signal-to-noise ratio and
estimate the cumulative energy released during the experiment.
The total moment magnitude of the
radiated energy recorded compared to the volume injected allows to estimate the
induced seismic deformation.
We show that the seismic energy
released during hydraulic fracturing is only fraction of the injected energy.
Early Determination of PVT Data and
Integration with Formation Testers information to reduce the Petrophysical
Uncertainties in West Africa.
by
Brendin Cronin & Adil G. Ceyhan –
Schlumberger
Inspection and rationalization
of the pressure-volume-temperature (PVT) fluid properties must be the opening
move in the study of any oilfield since the PVT functions, which relate surface
to reservoir volumes are required in practically every aspect of reservoir
engineering: calculating of hydrocarbon in place, pressure-depth regimes, any
of recovery calculations and to assure correct design of surface facilities.
This study or integration synergy explains how one can integrate PVT data with
Formation Tester measurements to reduce the petrophysical uncertainty in an
early stage of field development.
Traditionally, by far
the main responsibility of the practicing geoscience and petrophysic in this
matter is to the collection of valid fluid samples for transfer to the laboratory
where the basic PVT experiments are performed. In today advancing technology,
now the Petrophysicist can get PVT information from “Rugged Wellsite Units”
while evaluating the formations. Incorporating formation tester information
that became the commonly used FE service, with Wellsite PVT analysis can reduce
most unwanted long-term uncertainty at early stage of the field development.
This is especially very critical for Deep Offshore Field Development such as in
West Africa Turbidities channel system.
This study offers the
new way of using Fluid Property data into our daily based dealt “Static and
Dynamic” Model, moreover opens an new era for Petrophysical Evaluations by
providing critical fluid information right at the beginning to understand the
big picture.
by
Hiroshi Asanuma, Shoichi Takashima and Hiroaki Niitsuma
A prototype of a downhole measurement system is described
in this paper that uses fiber Bragg grating (FBG) sensors without electrical
circuits in the downhole part. Such a device could potentially allow small
sensors to be deployed in harsh borehole environments. We have tested and
demonstrated the measurements of pressure, temperature and fluid flow velocity. Pressure and temperature measurements
are discriminated using a dual-sensitivity FBG system. The system showed linear responses
within an expected range and noise levels of 0.18 MParms and 0.14 deg-Crms. For the flow measurement, the system
uses cross-correlation and Karman vortex shedding frequency techniques. It has been demonstrated from the
laboratory tests that the system has a linear response up to 1.00 m/s and the
minimum detectable velocity of 0.05 m/s.
Compressional and Shear Velocity Data Identify and Quantify Fluids in
Carbonates and Clastics – A Field Calibration Based Approach
By
K.M.
Sundaram1 and Dhruba J. Dutta2
1Oil
and Natural Gas Corporation Limited
2Schlumberger
In the present study, due importance has
been given to the fact that the Gassman equation does not explicitly address
grain-to-grain elastic property (grain-to-grain stiffness). In the case study,
the form of Krief’s equation is intuitively understood to be the acoustic
analogue of Archie’s equation. Krief’s exponent is understood to be the same for
compressional and shear wave velocity when the fabric is sandstone-fabric-like
and unequal when it is not so. Hence the Krief’s exponents are not expected to
be equal when heterogeneity of pore size, shape, and the way pore sizes are
distributed in a fabric-, exists, which is common in limestone.
In
light of the above, a field calibration is needed to take into account, the
effects of pore heterogeneity as well as grain-to-grain stiffness properties,
which respectively express themselves, Krief’s exponent, and apparent grain
moduli.
Using field-calibrated grain properties
and Gassman’s relations, forward- modeled bulk properties are derived for 100%
gas- and water-saturation for qualitative identification of gas. Apparent bulk
modulus of fluid is also derived, for the same purpose, and a sonic saturation
computation is made. Forward-modeled clean dry-frame properties; bulk
properties and slownesses in respect to P (Dcomp)
and S (Dshear) wave
are computed. Apparent bulk-fluid modulus (Kfluidapp) was recomputed
and compared with the apparent-bulk-modulus of fluid computed previously, and a
bulk-modulus of fluid chosen and sonic saturation recomputed.
Forward-modeled clean bulk slowness, and
grain and dry-frame properties are used for customization of compressional-shear
velocity ratio (vp/vs) versus compressional slowness (Dcomp) templates.
Difference in Krief’s exponent in respect
to P and S can be used to evaluate spherical porosity fraction in the total
porosity present.
SUGGESTED
SYSYTEM OF FORMATION EVALUATION
USING SONIC TT, GAMMA-RAY AND
RESISTIVITY DATA IN CLEAN/SHALY SAND FORMATIONS
by
Mostafa H.
Kamel & Walid. M. Mabrouk
This paper relies greatly on introducing a system of formation
evaluation, in shaly sand formations, using limited set of well log data
including the sonic transit time, resistivity and gamma-ray logging
measurements. The proposed system was applied to the proper well log interval
from two wells located in the central part of the Gulf of Suez Basin. These two
wells were selected on the base of completeness of well logging data set and
representing shaly sand sequence. These intervals were highly analyzed using
the ELANPlus; the most advanced petrophysical interpretation program
(Schlumberger, 1997) that requires a full data set. Comparative analysis of the end result using the system
proposed and the end result of running the ELANPlus, was carried out. The
successfulness of such comparison encourages safe application of the proposed
system in another localities.
A flowchart of the proposed system, which using a minimum set of
logging data, is also presented.
by
Okitsu, Fumio, Consultant, 1-3-2, Hase,
Kamakura, 248-0016 Japan
It is presented how a
unique logging tool for near surface soil investigation was developed and
applied.
Tool Design:
The tool is designed
to record the degree of penetration of the probe resulting from every hammer
stroke. The penetration of the probe into the near surface formation is
achieved by a free fall of hammer that weighs either 2 or 2+3 kg. The stroke of
the hammer for every fall is fixed at 50 cm. The total of the penetration depth
is measured by the rack and pinion system and stored in the electronic memory
in the recorder which is attached to the tool.
The penetration depth, thus recorded is
then differentiated with respect to the stroke number to give penetration rate.
The final results are displayed against depth, which are similar to the
presentations of the commercial logging data.
Total length of the probe and attached
rod is 5m long and the probe can penetrate the soil of maximum 4m in depth. If
the probe hits hard formations or encounters any obstacles, where no progress
of the penetration can be observed, the survey will be terminated.
Application
of the Tool:
Although the basic
design of the tool is quite simple, the resultant log data explains the details
of the near surface information of the soil. Operation of the tool is also so
simple that a job can be completed in a short time. Measurement with high
spatial density enables the economical investigation of detailed distribution
of the subsurface soil characteristic in short time. Results of the field
application of the tool such as the interpretation and relation between log
reading and physical properties of the soil will be shown at the
presentation.
A
study on new soil investigation method using seismic waves generated by dynamic
penetration blows
by
Hideki
Saito, Yoshinobu Murata, and Toshiyuki Takahara
In
order to obtain more reliable data for the information of the ground, a new
site investigation method is proposed, in which seismic waves (S-waves)
generated by the Swedish Ram Sounding Test (SRS) are used. It is indicated that the energy
transferred from the hammer to the rod in SRS's is much more stable, compared
to SPT's. A series of SRS with
measurements of seismic waves at the ground surface were carried out to clarify
the characteristics of seismic wave propagation in the ground. As the results
of comparison between seismic wave amplitudes and Nd values (blow count for
20cm penetration in SRS), it was found that amplitudes of S-waves generated by
SRS correlate very well with Nd values. The amplitude of the S-wave is thought
to be a useful parameter for evaluating soil strength and rigidity.