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.

 

 

Formation Rate Analysis in an Anisotropic Formation and its Practical Applications

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.

 

 

Microseismic monitoring of a hydraulic injection test at the Yufutsu gas reservoir

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’s 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 gRugged Wellsite Unitsh 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 gStatic and Dynamich Model, moreover opens an new era for Petrophysical Evaluations by providing critical fluid information right at the beginning to understand the big picture.

 

 

Development of a prototype of fiber-optical PTF tool

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fs equation is intuitively understood to be the acoustic analogue of Archiefs equation. Krieffs 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fs 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fs exponent, and apparent grain moduli.

Using field-calibrated grain properties and Gassmanfs 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fs 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.

 

                                        

 

 

Logging by Gravity Hammering -An unique logging tool for near surface soil investigation-

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.