Well Log Interpretation/Well Control Research Papers (original) (raw)

A Borehole instability problem contributes significantly to increase in non-productive time (NPT) and overall cost of the drilling. These problems can occur in a variety of forms including stuck pipe, loss circulation, hole enlargement, breakout. Borehole problems such as drill pipe sticking, hole collapse, breakout, ,caving and tight holes have been experienced during drilling of wells in an oil field in the Niger Delta. This work analyzed the major cause of wellbore instability in a field in the Niger Delta by using data from two wells drilled and proposes an optimum mud window for cost-effective and safe drilling operations. Geomechanical model was used to evaluate the in-situ stress and induced stresses with Mogi Coulomb and Mohr Coulomb failure criteria to predict the breakout profile and estimate the optimum mud weight to avoid sticking of the drill string. The result shows that the Mogi failure criterion was 1.46sg and 1.39sg while Mohr failure criteria were 1.48sg and 1.42sg for well 1 and well 2 respectively. Based on the results obtained, Mogi coloumb is preferable to Mohr coloumb criteria. Mogi failure criteria give more accurate result to obtain optimum mud weight window for the field considered in the Niger Delta. Therefore, in the prediction of an optimum mud weight window for any well in the Niger Delta, mohr failure criteria should be employed and adopted.

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- Well Log Interpretation/Well Control

Evaluation of shale gas hydrocarbon potential of Talhar Shale member of Lower Goru Formation, by using well logs data only, has been a challenging task in Southern Lower Indus Basin Pakistan. This paper is helpful to evaluate shale gas potential of source rock by using well log data. We have introduced and applied Empirical and Graphical method to resolve this task and have derived geochemical parameters from well logs data. The way mentioned is fastand the cheapest. Talhar Shale has kerogen typeIII and type II which has potential to produce, mainly, oil and gas. Talhar Shale is of Montmorillonite clay type. So, Talhar Shale has better sorption property. Empirical formulas are used to derive parameters, using well logs of Porosity, Density and Uranium. Porosity and Volume of Kerogen, calculated from density log, gives average values of 11.8% and 11.4%. Level of Maturity Index (LMI), derived by log, average value is 0.54 which indicates that it is on early stage of maturity. Vitrinite reflectance is between 0.5-0.55% as calculated by graphical method and empirical formula. Talhar Shale with main products of oil and gasis onset of oil generation,;could be a good potential source in the study area. KEY WORDS:Talhar Shale,kerogen type,sorption property,thermal maturity,vitrinite reflectance (R O), Southern Lower Indus Basin

- by Muhsan Ehsan and +1
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- Well Log Interpretation/Well Control, Petrophysics and Well Logging

Porosity is one of the most important characteristics for modeling reservoir. In recent years, some new methods for estimation have been introduced, which are more applicable and accurate than old methods. Fuzzy logic has shown reliable results in petroleum modeling area for describing reservoir characteristics. In this study, a Sugeno fuzzy model has been formulated to predict porosity. In order to select the number of membership function, subtractive clustering method was utilized through Gaussian membership functions. Another technique for predicting porosity was multiple linear regression to compare with fuzzy logic technique. Results indicated that correlation between real value from core data and the predicted value by fuzzy logic was more accurate than multiple linear regression technique in this scope.

- by shirko mahmoudi
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- Petrology, Petrophysics, Petroleum, Petroleum geology

Sonic logging is a well logging tool that provides a formation’s interval transit time

- by Dr.Omar Hamdy
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- Petrophysics, Petroleum geology, Well Log Interpretation/Well Control, Well Logging

Atlas of Log Responses Atlas of Log Responses

- by Emin Emin
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- Well Log Interpretation/Well Control

All over the world, there is an urgent need for effective fluid control equipment, such needs can be found in foods, drugs, beverages, power generation, and oil and gas industries. Some of the existing equipment for this purpose has certain limitations for effective control of fluid at high pressure condition. Thus, there is a need for design modification to solve the prevailing problem. This paper majorly addressed the case peculiar to the oil and gas industries, where fluid control failure has cost millions of dollars, hazardous environmental effect and also decline in nation's economy, taking Niger Delta oil spillage as a case study. In this work, computer aided design method (CADM) was utilized to design and perform stress analysis of a high pressure gate valve used on a typical oil and gas wellhead of working pressure up to 15,000 psi. (103.4 MPa). The critical components in the gate valve are the body and gate (disc). Conversional design adopts calculations from analytical method, but in this work, finite element analysis (FEA) was used to determine stresses and deformations distribution on critical components of the high pressure gate valve (HPGV) as they are the main pressure retaining boundaries in the valve. The results obtained from the two methods indicated reasonable convergence after validation. The stress analysis conducted was based on von mises failure criterion which is most suitable for ductile materials. The results obtained from both analytical design calculation and that of finite element analysis indicates reasonable agreements by measuring their percentage performance variance. Therefore, the findings of this research work attests to reliability of the designed HPGV valves in meeting engineering design assessments, and in turn can be optimally advanced in the manufacture of high pressure gate valves.

Previous works based on statistical design of experiments (DoE) defined a model all-alumina self-flow refractory castable (SFRC) with optimized particle size distribution for simultaneous high flowability index (FI) and superior post-sintering performance. This work compares the SFRC rheological behaviour and setting time with those of alternative all-alumina castables with different Andreasen aggregate particle size distribution modulus, and of the equivalent castables containing calcium aluminate cement. The model castable showed Bingham behaviour with low yield stress, viscosity and thixotropy, guaranteeing easier casting and less wear in the casting and/or projection equipment. However, as the coarse particle fraction increases, the castable flow tends to be non-linear and changes from Bingham to Herschel-Bulkley. The cement containing castables quickly loose flowability despite the applied shear. This work confirmed previous conclusions based on FI measurements and demonstrates the adequacy of the use of FI values in the calculation of FI response surface by DoE.

Os textos aqui reunidos foram escritos para servirem de introdução aos estudos hermenêuticos para um público amplo. A ideia diretriz foi a de apresentar os conceitos e teorias que estruturam o paradigma do pensamento hermenêutico a partir de experiências cotidianas e comuns. Nessa estratégia vai embutida a tese de que os termos teóricos são abstrações por sobre práticas e experiências concretas de indivíduos e comunidades. No caso dos termos hermenêuticos básicos, como “sentido”, “expressão”, “significação”, “interpretação” e “compreensão” isso é tanto evidente quanto problemático, pois torna-se difícil apreender os conceitos teóricos que essas palavras designam em cada teoria hermenêutica sem confundi-los com as noções não teóricas a elas associadas no seu emprego cotidiano e vivo da língua.

- by mary seyed
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- Well Log Interpretation/Well Control

The identification of fluid contacts (gas–water contact—GWC, oil–water contact—OWC and gas–oil contact—GOC) is essential for field reserve estimates and field development and, also, for detailed formation evaluation. For the accurate calculation of some petrophysical parameters, such as porosity, the reservoir interval has to be zoned by fluid type, to account for differences in fluid saturations and fluid properties (e.g., hydrogen index, density, sonic transit time) in the various intervals: gas cap, oil column and aquifer zone. The fluid contacts may vary over a reservoir either because of faults, semipermeable barriers, rock quality variations / reservoir heterogeneity, hydrocarbon-filling history or a hydrodynamic activity. Horizontal contacts are typically taken into consideration, although irregular or tilted contacts occur in some reservoirs. The methods used for determining the fluid contacts include fluid sampling, water and hydrocarbons saturation estimation from geophysical well logs, analyses of conventional or sidewall cores, and formation pressure measurements. The pressure profiles obtained with various formation testing tools over reservoir intervals are, frequently, the primary source of data for defining the fluid contacts. When good quality pressure data can be collected, the fluid contacts can be determined by identifying the depths at which the pressure gradients (pressure versus depth trends) change. This study addresses some issues related to the identification of GWC for two gas fields of Early Pliocene age (Dacian stage), belonging to the biogenic hydrocarbon system of western Black Sea basin-Romanian continental shelf. We show that the identification of these contacts based exclusively on pressure gradients analysis is uncertain or may be inaccurate. The pressure gradients approach should be checked against the results of the conventional interpretation of geophysical well logs (e.g. changes in the computed fluid saturations as a function of depth) and, if available, the results of nuclear magnetic resonance (NMR) log investigations, which are able to indicate the intervals with clay-bound water, capillary-bound water and movable fluids.

- by Bogdan NICULESCU
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- Geology, Geophysics, Petrophysics, Reservoir Engineering

The petrophysical interpretation of Rudeis Formation was studied by using a comprehensive interpretation of the available digital well – log data as resistivity (deep and shallow), porosity (sonic, density and neutron), gamma-ray and composite logs and for example nine scattered wells (113-M-03, 113-M-04, 113-M-08REP, 113-M-12, 113-M-14, 113-M-17, 113-M-35, 113-M-45 & 113-M-56) have been studied, Corresponding well-log data have been processed through a sequence of graphical relations (manual interpretation) to evaluate the different petrophysical characteristics and also computerized through available computer software. The manual interpretation was started by Tri-porosity (M-N) cross-plots for mineral identifications are used to detect in general the types of lithology. Lithological identification cross-plot is achieved through cross-plots between RHOB, NPHI and DT to detect matrix density (ROH mat) and matrix interval transit time (DT mat) for each facies. These charts show that sandstone and shale represent the main components in Rudeis Formation. Mono-porosity cross-plots are constructed to determine the water and hydrocarbon saturations (Sw& Shr), formation water resistivity (Rw) and Sonic, neutron and density derived porosities (Øs, Øn and Ød). Dia- porosity cross-plots were established to determine the shale volume (Vsh) and effective porosity (Ø eff). All petrophysical characteristics, inferred from the previous steps were represented vertically in the form of petrophysical data logs (PDL).

- by Khalil Gad
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- Well Log Interpretation/Well Control

Gamma Ray log known as GR log. Its measure the intensity of natural radioactivity of rocks. The intensity of GR is high in the
Shale. Why?. The answer is very simple. The radioactive particles like Uranium, Potassium, Thorium are very fine grains.
During deposition these particles deposit with shale because Shale is also fine grain rock. That’s why the value of GR is high in
Shale. GR is the best log for correlation.

- by Dr.Omar Hamdy
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- Petrophysics, Petroleum geology, Well Log Interpretation/Well Control, Well Logging

Reservoir characterization is a process that involves the integration of various qualities and quantities of data in a consistent way to describe the reservoir properties of interest in each well locations. Characterizing the reservoir is a process which describes various properties in reservoirs using all the available data to provide reliable reservoir models for accurate prediction of the performance of a reservoir. Reservoir characterization is of high importance because it plays an important role in the exploration and exploitation processes of the oil and gas industry and also gives room for optimum recovery of hydrocarbon at a minimized cost. A
play is one or more prospects that may define a profitable accumulation of undiscovered petroleum. Traditionally, a play is developed and evaluated without any particular petroleum system in mind. Wireline log data and 3D seismic data were analyzed to characterize the
reservoir with respect to its porosity, water saturation, the volume of shale and permeability in
“HARK” field. Reservoir “A” was delineated across four (4) wells-HARK_5, HARK_7,
HARK_10 and HARK_11. The average permeabilities observed across the wells range from
1108.945mD to 1767.393mD, while the effective porosity ranges from 21.4% to 23.9%. The
Hydrocarbon saturation ranges from 69.1% to 90.5% signifying the presence of a commercial
quantity of hydrocarbon accumulation. Oil-Water Contact has been encountered by the well at 3814 m TVD. The volumetric analysis carried out revealed that the volume of hydrocarbon in place for reservoir “A” was estimated at 308 bb/STB. The outcome of this project is a notable approach in characterizing reservoirs and hydrocarbon producibility of the reservoir.

Nowadays, the failure to understand a hydrocarbon ﬁeld’s geomechanics signiﬁes an expensive risk in several complex drilling, well completion, and exploitation processes. Thus, the precise estimation of reservoir geomechanical parameters can lessen that risk and provide beneﬁts all the way through oil and gas ﬁeld’s lifespan. Several factors like compaction of sediments, lithology characteristics, overburden, hydrocarbon and capillary entry pressures add substantial effects to cause of abnormal pressure and resultantly affect the well design and stability. The aim of current study is to compute geomechanical properties such as overburden pressure and vertical effective stress and ﬁnally to deﬁne the lower and upper bounds (breakout and breakdown limits) of safe mud weight window by determining the pore pressure and fracture gradient for pre-drill planning in future exploration and real timemonitoring in the Sinjhoro Field, the Lower Indus Basin of Pakistan. Current studies examined the wireline logs data of four wells drilled in the Cretaceous reservoir sands and seismic reﬂection data-based P wave velocity functions and describes a workﬂow for reliable estimation of geomechanical parameters. Our results revealed that high pore
pressure (5000–7000 Psi) is predicated at reservoir zone and it increases in southeast directions. On the basis of pore pressure
and fracture pressure, both lower (5388.89 Psi) and upper (6572 Psi) bounds for safe mud weight window are deﬁned for safe drilling and well stability that will help future exploration and development in the Sinjhoro ﬁeld. Both overburden pressure and vertical effective stress increase uniformly with depth but spatial variations are nonlinear and increasing in northwest directions. The present work will support the petroleum industry by reducing the borehole drilling cost with no compromising
on environment and safety concerns.

- by Nisar Ahmed
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- Well Log Interpretation/Well Control

We investigate the potential usefulness of Principal Component Analysis (PCA) method in providing meaningful petrophysical information, in addition to the results obtained via conventional well log interpretation, or to constrain and validate such results. We applied PCA to a geophysical logging data set recorded in a natural gas exploration well drilled in the NW part of Moldavian Platform-Romania. The first principal components of the data seem to respond to major lithological changes or shale/clay content variations, whereas the higher-order principal components most likely reflect fluid-related data variability, such as fluids type and/or volume. The results of this study suggest that PCA may successfully complement the standard log interpretation and formation evaluation methods.

- by Bogdan NICULESCU and +1
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- Geology, Geophysics, Petrophysics, Principal Component Analysis

The key for determining electrofacies is core and log data integration. Recognition of electrofacies in a wide variety of depositional environments can be achieved through inductive and deductive methodologies. In two different fields located in Argentina and Venezuela, open hole logs (spontaneous potential, gamma ray, caliper, shallow-medium and deep resistivities, neutron, density, sonic, photoelectric factor and nuclear magnetic resonance) were calibrated according to the lithological variations described in the cores. The potential capability of multivariate analysis in distinguishing each electrofacies was analyzed based on recognition of geological facies within the core samples. K-means cluster analysis in n dimensions was used to define electrofacies which were entirely associated with the facies observed in the core samples. Encouraging results were obtained after applying such techniques in eolian sand dunes and interdune deposits, mouthbars, distributary channels, meandering and braided deposits. Furthermore, porosity -permeability relationships were established according to the defined electrofacies. An example of a 3D distribution of the electrofacies performed in one field is presented as well. Results reveal the usefulness of applying this methodology for supporting reservoir characterization independently of the depositional environment.

- by luis stinco
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- Well Log Interpretation/Well Control

Complexly faulted subsurface configuration is capable of causing erroneous deductions in the absence of a well packaged interpretation approach and workflow for an oilfield exploration programme, thus a well prepared analysis saddled on the use and integration of sufficient data is indispensable to the unravelling of complex field subsurface structure as the search for oil and gas progresses into deeper waters. S uite of signatures from wireline logs and seismic volume was employed to gain more insight into the complexities of the hydrocarbon hosting units within and outside the vicinity of well control in the X-field Niger Delta. Horizons and fault interpretation were carried out to produce subsurface structure maps. Amplitudes of the horizons mapped were extracted and were used to study the distri bution of the hydrocarbon sand. Three hydrocarbon bearing reservoirs were delineated within the study interval, namely: ROJ A, ROJ C and ROJ D. Well to seismic tie revealed that these reservoirs tied direct hydrocarbon indicators (bright spots) on the vertical sections. The structure maps produced revealed a series of NW-S E and E-W trending growth faults and fault echelons, most of which dip to the south. Fault assisted closure s were revealed at the southern part of the field, which correspond to the crest of roll over structures and possibly served as the trapping mechanism for the reservoirs. The reflection amplitude of the studied horizons shows a fine network of anomalies that can be correlated to the prediction of the lateral distribution of the hydrocarbon sand. The conclusion of the study was that the western part of horizon ROJ A is a highly prospective area as bright spots were observed in the region. Also in the adjacent southern direction of this horizon, hydrocarbon accumulations have been confirmed from wells. These gas sands are possibly trapped in anticlinal closures located in the same area. On the other hand, the results from the study of horizon ROJ C suggest de velopment opportunities in the southern area. High amplitude gas sands are seen to spread to the south and stratigraphy was assumed to play a major role in hydrocarbon migration. The study over horizon ROJ D reveal likely geologic features like regional sand pinch outs and channels in the southern part of the field. S pectral decomposition interpretation was suggested to be used further in improving the delineation of the thin reservoir sand bodies and for better outlining of their geometries but was not available on the workstation used. The study has shown the feasibility of integrating structural interpretation and instantaneous amplitude in prospect identification and reservoir prediction.

Investigating the distribution and variation of reservoir property within a field is important for both field
development plan and production optimisation. Porosity, net-to-gross, water saturation and permeability
information, derived from petrophysical analysis, are controlled basically by inherent depositional settings. A
sequence stratigraphic study was done to define the environment of deposition within constrained reservoir
intervals in Alpha, Beta and Gamma field of OML’999’ block, onshore Niger Delta by integrating log
information and biostratigraphic data from three (3) wells. The analysis delineated three sequences with key
surfaces generated used for correlation. These surfaces were delineated at varying depth in Maro-001 and
Tegus-002 wells, suggesting the existence of fault in the block.
A comparison of the properties of the hydrocarbon bearing reservoir of Maro-001, Tegus-002 and Seyi-003
wells indicated varying petrophysical property from north to south, which can be attributed to facies change
which was determined to be from fluvio-deltaic to shallow marine as we move basinward.
The general trend of the fault in the 2-D regional line is NW- SE, while the throw direction is SW for the
synthetic faults which dip basinward and NE for the antithetic faults. The trapping mechanisms were identified
to be fault dependent and are typically roll over structures, hanging wall and foot wall closures, which are the
basic hydrocarbon trap associated with normal detached fault in an extensional setting.

This paper aims to review some of the widely used conventional and other contemporary Inflow & Productivity models that exist for Horizontal wells, and comment on their limitations by drawing on the experiences of other author's critiques... more

- by Krishna Kumar
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- Petrophysics, Petroleum, Reservoir Engineering, Petroleum geology

Mud invasion one of the problem that found in drilling operation, for drilling operation mud invasion will reduce the amount of drilling fluids, and obviously it will take more budget to add extra mud to circulate. And if we see from the petrophysics aspect, all logging tool have limitations such as depth of investigation. Depth of investigation is the ability of logging tool to measure reservoir characterity with a certain distance. Borehole environment study will show us mud invasion detaily, and also give the preview and simulation about the way invasion mud will move and replace oil and gas zone in the permeable formation. One of the logging measurement that affected by mud invasion is resistivity. Resistivity tool limited by its DOI (depth of investigation), along the wellbore mud will penetrate increasingly at the same time with the increaisng of the time. So that all engineers should consider about time that will spent after drilling operation to logging operation. In this case, the combination tools of drilling and logging would be Preffered. And the solution is Logging while drilling. Logging while drilling give the same information with the conventional logging operation, althought there are some differentiation beetwen them. Logging While Drilling or LWD is the general

- by Raynaldo Panjaitan
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- Petrophysics, Well Log Interpretation/Well Control

This paper addresses some formation evaluation challenges and petrophysical particularities regarding two gas fields of Early Pliocene age, belonging to the biogenic hydrocarbon system of Western Black Sea Basin-Romanian continental shelf. Although these structures are located at the same depth and only 15 km apart, the wells that intercepted the sands and silts gas-bearing reservoirs indicate an important lateral facies variation and different reservoir qualities. We analyzed and interpreted data from exploration and appraisal wells that targeted these reservoirs, showing that: (1) there is a limited radioactivity contrast between the reservoir and non-reservoir intervals, so a clay volume determination based solely on the gamma ray log is not practical; (2) the reservoirs are characterized by high capillary-bound water contents, leading sometimes to abnormally low resistivity readings; (3) an additional resistivity suppression might be caused by the limited vertical resolution of the electrical logging tools, in the presence of thinly laminated sand-shale intervals; (4) the identification of gas-water contacts based exclusively on pressure gradients may be inaccurate and should be checked against the results of conventional geophysical logs interpretation and of nuclear magnetic resonance logs, for delineating the intervals with bound water or with movable fluids.

- by Bogdan NICULESCU and +1
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- Geology, Geophysics, Structural Geology, Petrophysics

Desarrollo de un programa básico programado en la plataforma excel mediante el uso de macros y lenguaje de programación Visual Basic, con la finalidad de automatizar, agilizar el proceso de recuperación del control del pozo y especificar... more

La evaluación final se realizó por medio de la interpretación estratigráfica y estructural de los PayShales arrojando como resultado la zona 4 al NW del área de estudio como la mejor para profundizar la evaluación de un yacimiento del... more

- by Miguel Angel Manjarrez Cantú
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- Geology, Geophysics, Assessment, Petroleum

Borehole instability issues account for approximately 18% of the non-productive time during drilling. The data needed for the planning of optimized wellbore trajectories and mud weight windows can come from multiple sources, notably Logging-While-Drilling (LWD) and wireline measurements. In particular, in-situ tectonic stresses can be inferred from the identification and characterization of breakouts (some of the most common processes that infringe upon the stability of boreholes). Two techniques can help to distinguish the breakouts: (1) determining borehole ovalization and (2) identifying the breakouts on borehole geophysical images. Multi-arm caliper logs from wireline imaging tools provide a direct measure of the borehole size but are not always available. Borehole shape can, however, be inferred from LWD geophysical imaging logs, notably from acoustic and density logs, which are very sensitive to standoff. Synthetic caliper curves can be computed from the standoff curves and converted into an oriented caliper image, displayed as a borehole wireframe. Sections through this borehole wireframe provide ovalization information and eliminate the uncertainty of breakouts direction estimation from resistivity images, which may show sometimes artifacts related to the presence of bad hole conditions or to very high formations true resistivity/mud resistivity ratios.
This paper presents the application of LWD imaging data for better characterization of a borehole cross-section and easier breakouts detection in hostile environments (borehole excavations and rugosity, resistivity image artifacts, presence of fractures and faults). The proposed method enables detecting breakouts in real time or in memory mode. Determining the magnitude and orientation of borehole breakouts enables the validation or adjustment of geomechanical models and the selection of optimal parameters for the drilling mud.

- by Bogdan NICULESCU
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- Geology, Geophysics, Petrophysics, Tectonics

Studi kekokohan bangunan infrastruktur akhir-akhir ini tidak hanya ditentukan oleh kekuatan material penyusun bangunan akan tetapi faktor geoteknik juga menjadi sandaran utama sebelum bangunan infrastruktur dibangun di suatu area lahan kosong. Mengingat sebagian besar wilayah kota besar Indonesia memiliki tingkat kerawanan gempabumi yang tinggi, maka perencanaan pembangunan di wilayah-wilayah tersebut harus mempertimbangkan adanya efek topografi, struktur geologi bawah permukaan, dan kekuatan material penyusun bangunan infrastruktur. Belum adanya pemetaan terperinci tentang wilayah rawan bencana geologi merupakan suatu permasalahan yang sangat perlu dipecahkan untuk perencanaan pembangunan di masa datang. Salah satu usaha yang dapat digunakan untuk menduga lokasi rawan gempabumi logsoran tanah adalah melakukan survei dengan menggunakan metode gravitasi. Metode ini dianggap lebih murah dan mudah dilaksanakan sehingga pemetaan daerah rawan bencana geologi dapat dengan cepat dibuat. Hasil studi ini diharapkan akan menjadi masukan bagi pemangku kepentingan dalam merencanakan pembangunan gedung-gedung bertingkat pada pembangunan kampus II UIN Maulana Malik Ibrahim Malang yang terletak di wilayah Tlekung Junrejo-Batu.

- by Taufiquddin ibnu
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- Well Log Interpretation/Well Control

High resolution temperature data were used to identify the formation of condensate in the rock matrix and the subsequent developing banks of condensate in a highly layered gas condensate reservoir, during an appraisal drill stem test (DST). Condensate blockage leads to reduced gas productivity and loss of production of the more valuable, heavier components. Understanding this phenomenon is not only important for the transient analysis of the DST pressure data, but also for the future production plan of the field. A multiple discrete temperature sensor array (MDTS), run on TCP guns across a perforated interval, enabled consecutive real-time recordings of wellbore temperature profiles to be made throughout the whole duration of a DST, at high temporal, spatial and thermal resolutions. These transient data were used to create a detailed 3D map of the wellbore thermal response. Using this technology, simultaneous Joule-Thomson heating of liquid condensate and cooling of lean gas entering the wellbore from various layers were identified. By continuous monitoring of the temperature profiles across the perforated interval, liquid condensate dropout in the near-wellbore rock formation was identified. The reservoir consists of thin sand beds, separated by shaly layers, which provided an upper and lower boundary to contain the separated gas and liquid condensate. In each layer, there are two phases; lean gas exhibiting Joule-Thomson cooling, and liquid condensate exhibiting Joule-Thomson heating. A continuous reduction in productivity index throughout the flow period provided supporting evidence of the formation of a condensate bank, causing a reduction in gas relative permeability. During the shut-in periods, the high-resolution temperature sensors detected a growing column of warm liquid condensate in the wellbore. At the near-wellbore region, the condensate bank collapsed under the influence of gravity and wept into the wellbore. Pressure gauges below, above and in the middle of the perforated interval confirmed the density of the condensate column, rising in the wellbore. Unlike other cases using synthetic data, this case study is based on real field data. Discrete temperature sensors across the producing interval, gave valuable information therefore making a significant contribution to the future field development plan.

Reservoir characterization deals with the description of the reservoir in detail for rock and fluid properties within a zone of interest. The scope of this study is to model lateral continuity of lithofacies and characterize reservoir rock properties using geostatistical approach on multiple data sets obtained from a structural depression in the bight of Bohai basin, China. Analytical methods used include basic log analysis with normalization. Alternating deflections observed on spontaneous potential (SP) log and resistivity log served as the basis for delineating reservoir sand units and later tied to seismic data. Computation of variogram was done on the generated petrophysical logs prior to adopting suitable simulation algorithms for the data types. Sequential indicator simulation (SIS) was used for facies modeling while sequential gaussian simulation (SGS) was adopted for the continuous logs. The geomodel built with faults and stratigraphical attitude gave unique result for the depositional environment studied. Heterogeneity was observed within the zone both in the faulted and unfaulted area. Reservoir rock properties observed follows the interfingering pattern of rock units and is either truncated by structural discontinuities or naturally pinches out. Petrophysical property models successfully accounted for lithofacies distribution. Porosity volume computed against SP volume resulted in Net to gross volume while Impedance volume results gave credibility to the earlier defined locations of lithofacies (sand and shale) characterized by porosity and permeability. Use of multiple variables in modeling lithofacies and characterizing reservoir units for rock properties has been revisited with success using hydrocarbon exploration data. An integrated approach to subsurface lithological units and hydrocarbon potential assessment has been given priority using stochastic means of laterally populating rock column with properties. This method finds application in production assessment and predicting rock properties with scale disparity during hydrocarbon exploration.

Classification of different lithofacies and petrotypes is one
of the main objectives of modern quantitative seismic
interpretation. In this study, we present preliminary results
of the application of a proximal support vector machine
(PSVM) classification algorithm to seismic data. In this
application we illustrate the PSVM method to differentiate
limestone from shale in a Barnett Shale gas play. The
PVSM’s low complexity feature compared to the standard
vector machines could be well exploited in a data intensive
computation such as the 3D seismic lithofacies
classification. The paper reports two applications of this
technique one for waveform classification and the other for
the classification of well data. In both these applications
PSVM classification results showed strong agreement with
structural and stratigraphic interpretation results.

- by Vikram Jayaram and +1
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- Machine Learning, Support Vector Machines, Facies Analysis, Well Log Interpretation/Well Control

During the last decade, exploration activities in the Ghadames Basin have been intensified by the National Oil Corporation (NOC), national, and international companies. Arabian Gulf Oil Company (AGOCO) was the leader in most of the discovered fields in the basin by drilling numerous wildcat wells targeting siliciclastic Paleozoic reservoirs, mainly of Silurian age. The Silurian rock units are known to contribute both source rock (Tanezzuft) and hydrocarbon reservoir (Acacus) successions in the area. The Acacus Formation is subdivided informally into three main units known as lower, middle, and upper, with the lower unit containing the main reservoir potential. These units have been mapped using basic well log data, nevertheless their sedimentological criteria remained untapped due to operational issues such as cutting cores. It has been observed from the appraisal wells that there is a high uncertainty of the reservoir's lateral continuity even within a few kilometers distance. Therefore, there was a demand to understand the stratigraphic depositional architecture and its lateral continuity and distribution of the sandstone reservoir units in the area. By using basic well log data alone, it was a challenge for the geoscientists to identify the main lateral variations especially in cases where the core is not available. Accordingly, AGOCO has started a new acquisition plan to come up with high resolution sedimentological understanding of the main reservoir in the area. The exploration team decided to acquire two main wireline tools, those are, borehole images (FMI) which gives a resolution down to 5 mm as well as element capture spectroscopy (ECS) which gives quantitative results of the elements for optimum geological interpretation in a detailed scale. The advantage is having more than 900 ft of core-like description data of the Lower Acacus units as well as a quantitative elements computation. This has in return resulted in a high resolution of sedimentological and stratigraphic interpretation throughout the Lower Acacus clastic reservoir in the Ghadames Basin. Imaging the wellbore and measuring the dip of the features have retained vast knowledge for AGOCO about the vertical succession of the main reservoir and understanding the reservoir geometries. In this poster, a case study from one of AGOCO wells has illustrated the value of the comprehensive wellbore integration and interpretation. As a result, and based on the detailed

The studied area is located in the NW of Moldavian Platform, the oldest platform unit of the Romanian territory, representing the western margin of the East European Platform. The integrated analysis and correlation of seismic reflection surveys and wireline logs, together with mud logging and additional geological data, allow a better delineation and characterization of the Sarmatian (Middle–Late Miocene) gas reservoirs from this area. A gradually decreasing reservoir quality and, most likely, hydrocarbon potential from NW towards SE is suggested, related to sedimentary facies changes. Thermal maturation models indicate that two hydrocarbon systems are present in the Moldavian Platform: a thermogenic hydrocarbon system of Paleozoic age and a biogenic hydrocarbon system of Miocene age. This analysis is focused on the biogenic hydrocarbon system of Miocene age, which contains significant gas fields. The gas is represented by more than 98% methane and is reservoired especially in the lower part of the Sarmatian deposits, where suitable conditions for accumulation and sealing are encountered. The hydrocarbon entrapment is in structural traps of faulted monocline type and in sands/sandstones that pinch out forming lithostratigraphic traps.

- by Bogdan NICULESCU and +1
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- Earth Sciences, Geology, Geophysics, Structural Geology

Metamorphic processes, leading to mineralogical and structural changes of the rocks in response to physical (pressure, temperature) and chemical conditions, can be associated with the development of sin-metamorphic or post-metamorphic fractures. The post-metamorphic ones are directly related to tectonic stress. In addition, tectonic stress may cause the reorientation of minerals on a direction perpendicular to the stress direction, generating foliations (schistosity). This paper presents a structural analysis of the pre-Alpine metamorphic basement and its relations with the sedimentary cover by using geophysical data recorded in an exploration well located in the North Dobrogean Promontory (Romania). The analysis was based on quad-combo wireline logs, spectral gamma ray, sonic cross-dipole, and borehole electrical imaging data. The imaging analysis allowed the identification and characterization of metamorphic foliations, sedimentary bedding, natural fractures, and the determination of tectonic stress orientation. A brittleness index was computed by means of elastic parameters derived from density and sonic compressional and shear logs. Also, a fracture intensity characterization by using fracture area per volume of rock was conducted. The integration of geophysical well logging with mud logging and drilling data allowed us to carry out a detailed analysis of the metamorphic basement in the studied area.

- by Bogdan NICULESCU and +1
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- Geology, Geophysics, Structural Geology, Metamorphic Petrology

The electric formation resistivity factor (F) and the seismic compressional wave velocity (Vp) are powerful parameters in understanding the electric and elastic behavior of porous media and in identifying the type of fluid saturating the pore spaces. The formation resistivity factor is a function of various infuences, including
pore and grain properties; saturation, salinity, and viscosity of pore water; formation and pore-water resistivities; cation-exchange capacity; and clay content. The compressional wave velocity is a function of bulk (grain and fluid) density; type of saturant and degree of saturation; and various elastic moduli, including bulk (pore, fluid, and grain) compressibility. Both parameters (F and Vp) are significantly
affected by variations of porosity (¿), pressure, and temperature. The three parameters (F, Vp, Porosity) were obtained from well log measurements for complex, heterogeneous, and consolidated shaly sandstone reservoirs, saturated with multiphase fluids, offshore of the eastern coast of Canada. Relationships among the three parameters,
having coefficients of correlation ranging from 0.75 to 0.92, were obtained. Both F and Vp are correlated inversely to Porosity and directly to each other.

- by Hilmi S. Salem (Prof. Dr.)
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- Petrophysics, Reservoir Engineering, Density, Petroleum geology

We investigate the potential usefulness of Principal Component Analysis (PCA) method in providing meaningful petrophysical information in the case of hydrocarbon exploration wells, in addition to the results obtained via conventional log interpretation, or to constrain and validate such results. PCA is a multivariate data dimensionality reduction technique, which may also be employed to discover and interpret dependencies and relationships possibly existing among the variables or to highlight dominant data trends. We applied PCA to geophysical logging data sets recorded in wells drilled in various oil and gas fields from Romania and evaluated the PCA results by comparison with production tests, core analyses, lithology logs, and actual formation tops. This study suggests that PCA may successfully complement conventional formation evaluation methods. Straightforward applications of PCA include recognition and separation of lithostratigraphic units, reducing the uncertainty related to formation tops, and accurate delineation of reservoir intervals. Generally, the first principal components respond to major lithology changes, shale/clay content variations or significant borehole diameter variations. Higher-order principal components frequently reflect fluid-related data variability, but their use as hydrocarbon indicators or predictors for a certain area or structure requires a careful calibration by cross-checking with well test results and core analyses.

- by Bogdan NICULESCU and +2
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- Earth Sciences, Geology, Geophysics, Multivariate Statistics

- by Dr Arzu Javadova
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- Geology, Sedimentology, Petrophysics, Petroleum

Exploration activity in the Kutch-Saurashtra area has drawn major attention and because of the recent hydrocarbon discoveries offshore Kutch-Saurashtra basin is now moved from category III to II. Accurate understanding of the full present-day stress tensor and pore pressure is critical for field development. In this study, pore pressure, stress magnitudes and horizontal stress direction have been estimated from high resolution geophysical logs and various direct downhole measurements recorded in the studied offshore exploratory wells. Extensive availability of subsurface pressure measurements confirms hydrostatic pore pressure in the tertiary sediments. Magnitudes of vertical, minimum and maximum horizontal stresses indicate a strike slip tectonic stress regime. Wellbore breakouts of A-C qualities have been identified in density image logs and four arm caliper logs, indicating a NNE trend (N10°E to N20°E) of SHMax (maximum horizontal stress). The same has been confirmed from Shear wave anisotropy analysis as well. The interpreted stress direction is in good agreement with the World Stress map data available from the adjacent area. This study is significant in understanding the subsurface behavior during drilling, reservoir modeling, future well stimulation and production optimization.

- by Souvik Sen
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- Geomechanics, Tectonics, Well Log Interpretation/Well Control, Tectonics and Stress

Carbonate reservoirs are important exploration targets from the perspective of hydrocarbon and, also, groundwater reserves. In this respect, the most important aquifer system in Romania is located in South Dobrogea region, comprising two distinct aquifer complexes: a deeper one, mostly under pressure, hosted in fractured/fissured and karstified limestones and dolomites of Late Jurassic–Early Cretaceous age and a shallower one, mostly unconfined, hosted in Sarmatian (late Middle Miocene) lumachellic and oolitic limestones. The deeper aquifer is regional, confined on more than 60% of its extension, has a SW–NE general flow direction and discharges in Siutghiol Lake (Constanţa city area) and through submarine springs on the Black Sea continental shelf. The water flow occurs through fractures/fissures and dissolution voids within the carbonate rocks and, also, along fault planes.
Although a large number of wells were drilled in South Dobrogea for groundwater exploitation from the Late Jurassic–Early Cretaceous aquifer and, also, for groundwater quality monitoring, there are few published data and studies regarding the geophysical response and petrophysical features of these formations, in relation with their hydrogeological characteristics. The more recent drilling of three hydrogeological research boreholes in the proximity of Cernavodă Nuclear Power Plant (NPP) offered an opportunity to gain valuable information concerning the geological succession in this northern part of South Dobrogea, with special regard to the carbonate formations hosting the aquifer. The boreholes were drilled to a depth of 700 m, for the identification and exploitation of aquifer horizons, in order to provide a fresh water supply for the NPP units. Geological analyses on drill cuttings and cores and geophysical well logging were carried out, for a comprehensive characterization of the intercepted formations from a lithologic and stratigraphic viewpoint, the identification of fractures/fissures and caverns as potential water-producing zones and the evaluation of formation porosity. The geophysical logs interpretation showed that the most probable water-producing zones are located in the so-called Dolomitic Complex (Kimmeridgian–Tithonian) on the 620–700 m (particularly 650–700 m) depth interval, in carbonates with average porosities of 12–16% and locally reaching more than 40%.

- by Bogdan NICULESCU
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- Geology, Geophysics, Hydrogeology, Structural Geology

Processing and interpretation of well logging data is a very complex process, in which mathematical algorithms, statistical and numerical methods are deeply involved. In order to solve the major problems studied by the well logging (determination of the lithology, and porosity for the geological formations, delimitation of the reservoir rocks, estimation of their saturations), the interpreter must take into account various disturbing influences such as the borehole effect, presence of shale into formations, influence of the adjacent beds etc. The Influence of the perturbing factors on measured values is hard to estimate and it must be approached by means of numeric or statistic algorithms.

- by Bogdan NICULESCU
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- Earth Sciences, Geology, Geophysics, Petrophysics

Seismic diffractions may play an important role in seismic interpretation because they characterize geological objects that might not be visible for conventional seismic attribute analysis. Diffractivity may be caused by, and consequently may define, tectonic dislocations (faults and fractures), lithological variations, fluid saturation within rocks.
In this paper, we tie seismic diffractions extracted from vertical seismic profiling (VSP) data and borehole logging, from which we recognize the reasons that are responsible for diffractivity of the strata. First, we process a multi-source multicomponent VSP data set to extract seismic diffractions and construct diffraction images of the strata for all three of the VSP data components. Then, we perform joint analysis of well logs and diffractions to obtain petrophysical attributes associated with diffraction images. We divide the rock succession into several units, which have different diffraction properties. We identify compacted rock, alternating intervals, isolated fractured zones, and fluid-saturated layers.

Maintaining a stable borehole and optimizing drilling are still considered to be vital practice for the success of any hydrocarbon field development and planning. The present study deliberates a case study on the estimation of pore pressure and fracture gradient for the recently decommissioned Volve oil field at the North Sea. High resolution geophysical logs drilled through the reservoir formation of the studied field have been used to estimate the overburden, pore pressure, and fracture pressure. The well-known Eaton's method and Matthews-Kelly's tools were used for the estimation of pore pressure and fracture gradient, respectively. Estimated outputs were calibrated and validated with the available direct downhole measurements (formation pressure measurements, LOT/FIT). Further, shear failure gradient has been calculated using Mohr-Coulomb rock failure criterion to understand the wellbore stability issues in the studied field. Largely, the pore pressure in the reservoir formation is hydrostatic in nature, except the lower Cretaceous to upper Jurassic shales, which were found to be associated with mild overpressure regimes. This study is an attempt to assess the in-situ stress system of the Volve field if CO 2 is injected for geological storage in near future.

Fracture zones are usually characterized by an increased fracture density and thus a higher secondary porosity. In the studied area (Potwar Basin, Northern Pakistan), the porosities derived from a neutron log and fracture apertures (obtained via-high resolution resistivity images) are very low, even if the resistivity images show a high fracture density cataclastic zone. This analysis refers to a tight carbonate reservoir located close to a major fault zone, with a high density of fractures that do not contribute to fluid flow due to their small apertures. The compressive, reverse faulting regime with active hanging walls led to the formation of the main hydrocarbon traps, these being laterally delimited by such faults. Borehole breakouts and drilling-induced fractures were used for tectonic stress evaluation. The dominant minimum stress direction identified in the analyzed wells is WSW - ENE, normal to the direction of drilling-induced fractures, as indicators of the maximum stress direction, which are oriented NNW - SSE. The orientation of drilling-enhanced fractures confirms the maximum stress direction as determined via drilling-induced fractures. The alignment of the major fault and the natural fractures, parallel to the minimum horizontal stress direction, suggests a compressional tectonic regime at the moment of their formation. The maximum tectonic stress, normal to the fractures direction, has contributed to apertures closure and secondary porosity reduction. This explains why in an area characterized by intense cataclasis, resulted from the fault proximity, porosity is less than 2% and fracture apertures are, generally, less than 0.5 mm. But the simultaneous presence of breakouts and drilling-induced fractures in the same well is an indicator of a strike-slip stress regime. One may conclude that a change in the tectonic stress regime took place, from a compressive to a strike-slip one. The major fault, which initially had a compressive character (dominantly vertical movement), later became a strike-slip one, with a dominantly horizontal component. Knowledge of the fractures' propagation direction with respect to maximum tectonic stress is extremely important for the potential design of horizontal wells. Experience has shown that production is highly correlated to fracture volume and connectivity in tight formations, implying the future successful economic development of this particular field lies in knowledge of the fracture propagation direction.

- by Bogdan NICULESCU
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- Earth Sciences, Geology, Geophysics, Structural Geology

High pour point oil reservoir contains various typical properties; such as a kind of high freezing point, high paraffin content and high cloud point temperature reservoir, while the temperature is regarded as high sensitive parameter for oil reservoirs. The current research aim is to develop and assess the effect by cold water flooding, the structure and properties model was built with the combination method of reservoir geological modeling and simulation. Various degrees of cold damage have deep relation with paraffin deposition and reservoir channel plug due to decline of temperature below the cloud point temperature. Precipitated paraffin has changed the rheological properties of crude oil, which can increase filtration resistance and reducing the oil displacement efficiency. Furthermore, model simulation analysis results compared under two different conditions cold and hot water flooding and predicted the inter well temperature field distribution belongs to reservoir through the model numerical simulation. Present study depicts that the integrated method base on log, geological data and experiment can predict and analysis the temperature variation efficiently, while thermal displacement method has efficiently improved the high pour-point oil reservoir development effect, increasing oil mobility and enhancing oil recovery.

- by Muhsan Ehsan
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- Well Log Interpretation/Well Control