Reservoir Characterization Research Papers - Academia.edu (original) (raw)

Recent advances in the understanding of the molecular and colloidal structure of asphaltenes in crude oils are codified in the Yen−Mullins model of asphaltenes. The Yen−Mullins model has enabled the development of the industry's first asphaltene equation of state for predicting asphaltene concentration gradients in oil reservoirs, the Flory−Huggins−Zuo equation of state (FHZ EOS). The FHZ EOS is built by adding gravitational forces onto the existing Flory−Huggins regular solution model that has been used widely to model the phase behavior of asphaltene precipitation in the oil and gas industry. For reservoir crude oils with a low gas/oil ratio (GOR), the FHZ EOS reduces predominantly to a simple form, the gravity term only, and for mobile heavy oil, the gravity term simply uses asphaltene clusters. The FHZ EOS has successfully been employed to estimate the concentration gradients of asphaltenes and/or heavy ends in different crude oil columns around the world, thus evaluating the reservoir connectivity, which has been confirmed by the subsequent production data. This paper reviews recent advances in applying the FHZ EOS to different crude oil reservoirs from volatile oil (condensate) to black oil to mobile heavy oil all over the world to address key reservoir issues, such as reservoir connectivity/compartmentalization, tar mat formation, non-equilibrium with a late gas charge, and asphaltene destabilization. The workflow incorporates the integration of new technology, downhole fluid analysis (DFA), coupled with the new scientific advances, the FHZ EOS and Yen−Mullins model. The combination proves a powerful new method of reservoir evaluation. Asphaltene or heavy end concentration gradients in crude oils are treated using the FHZ EOS, explicitly incorporating the size of resin molecules, asphaltene molecules, asphaltene nanoaggregates, and/or asphaltene clusters. All of the parameters in the FHZ EOS are related to DFA measurements, such as compositions, GOR, density, etc. The variations of gas and oil properties with depth are calculated by the classical cubic equation of state (EOS) based on DFA compositions and GOR using specifically developed delumping, characterizing, and oil-based drilling mud (OBM) contamination correcting techniques. Field case studies have proven the value and simplicity of this asphaltene or heavy end treatment. Heuristics can be developed from results corresponding to estimation of asphaltene gradients. Perylene-like resins with the size of ∼1 nm are dispersed as molecules in high-GOR volatile oils with high fluorescence intensity and virtually no asphaltenes (0 wt % asphaltene). Heavy asphaltene-like resins with the size of ∼1.3 nm are molecularly dissolved in volatile oil at a very low asphaltene content. Asphaltene nanoaggregates with the size of ∼2 nm are dispersed in stable crude oil at a bit higher asphaltene content. Asphaltene clusters are found in mobile heavy oil with the size of ∼5 nm at even higher asphaltene content (typically >8 wt % based on stock tank oil). Two types of tar mats are identified by the FHZ EOS: one with a large discontinuous increase in asphaltene content versus depth typically at the base of an oil column (corresponding to asphaltene phase transition) and one with a continuous increase in asphaltene content at the base of a heavy oil column simply by extending the oil column in the downdip direction because of an exponential increase in viscosity with asphaltene content. All of these studies are in accordance with the observations in the Yen−Mullins model within the FHZ EOS analysis.

- by and +1
- •
- Reservoir Characterization, Asphaltenes, Asphalt Pavements, Oil and Gas Reservoir Characterization

Avian influenza (AI) disease still threat poultry industry in Egypt causing great economic losses. In order to identify and characterize the agent of suggestive clinical cases of AI disease, 28 flocks showing clinical signs suspected to be due to AI infections have been investigated. By slide Haemagglutination (HA), the positive samples were 14/28 and concerning the results of real time-reverse transcriptase polymerase chain reaction (RRT-PCR), 2/14 samples were positive to AI H5, 7/14 to New castle disease virus (NDV), 1/14 to H9 and 4/14 co-infected (2 samples had NDV + AI H5 and others had NDV + AI H9). These positive PCR samples were subjected to further characterization by genotyping and sequencing analysis. The two isolated of H5 AI strain were classified to H5N8 which, related to Russian strains (clade 2.3.4.4) and the genetic analysis approved little relationship between these two H5N8 strain and the commercial AI vaccines with percent (80-91.7%). So, the researchers should have more monitoring for these viral diseases with effective biosecurity and quarantine measures to minimize the disease occurrence.

Reservoir characterization and structural mapping using integration of well logs and 3-D seismic data was carried out to determine the prolificacy of OVU field, onshore Niger delta. The distribution of reservoir physical parameters (porosity, permeability etc.) and availability of traps that favour hydrocarbon accumulation in the field were evaluated. Four hydrocarbon bearing reservoirs were delineated out of several identified sands in the field out of which three horizons were mapped. Two major growth faults, an antithetic fault and five synthetic faults were delineated. Structural closures were identified as rollover anticlines with the trapping mechanism delineated as a Fault assisted anticlinal structure. The computed range of values for gross thickness, volume of shale, net to gross, water saturation, hydrocarbon saturation, total porosity and absolute permeability with respect to each reservoir are: 18-125m, 9-17%, 83-92%, 18-28%, 62-82%, 21-23%, and 736-3965mD respectively. Hydrocarbon reserves calculations reveals a total reserve of 30.9 billion stock tank barrels of oil. With the very good to excellent calculated values of petrophysical parameters and high hydrocarbon reserve together with the suitable trapping mechanisms makes the study field prolific. Few wells exist in the southwestern corner of the field where a closure is identified in this study. The area should therefore be subjected to further evaluation with a view to increasing the number of wells there.

Schiff base synthesis of 1,3,4 oxadiazole derivatives containing
Indole moiety bearing thiazolidinone ring were synthesized by the
condensation of 2-(3-(4-oxo-3-(p-tolyl) 1H-tetrazol-5-yl)-1Hindol-1-yl)-N-(1,1,1-trifluoropropan-2- ylidene) acetohydrazide
with acetic anhydride. To this reaction was subjected in schiff base
reaction. It forms 2-(1-((4-acetyl-5-methyl-5-(trifluoromthyl)-4, 5-dihyro-1, 3, 4-oxadiazol-2-yl) methyl)-1H-indol-3yl)-3-(p-tolyl)
1H-tetrazol-5-yl). The structure of these newly synthesized
compounds was characterized by
1
H NMR,
13
CNMR, Mass, IR,
and elemental analysis.

Uncertainty analysis is a critical component of field development plan which describes the risks and assists to achieve comprehensive understanding of reservoir characteristics. Accurately assessing and ranking key uncertainties provides necessary tools to the technical and management team to mitigate risks appropriately and generate robust development scenarios over the range of key uncertainties. Uncertainty in input parameters impacts the project in two ways—in-place volumes and recovery factor. In this study, an analysis methodology is adopted in such a way to assess the impact of uncertainty on both independently.

- by Serdar Kaya
- •
- Geology, Structural Geology, Reservoir Engineering, Modeling and Simulation

The Gulf of Suez in Egypt has a north-northwest–south-southeast
orientation and is located at the junction of the African and Arabian
plates where it separates the northeast African continent from the
Sinai Peninsula. It has excellent hydrocarbon potential, with the
prospective sedimentary basin area measuring approximately
19,000 km2, and it is considered as the most prolific oil province
rift basin in Africa and the Middle East. This basin contains more
than 80 oil fields, with reserves ranging from 1350 to less than 1
million bbl, in reservoirs of Precambrian to Quaternary age. The
lithostratigraphic units in the Gulf of Suez can be subdivided into
three megasequences: a prerift succession (pre-Miocene or Paleozoic–
Eocene), a synrift succession (Oligocene–Miocene), and a
postrift succession (post-Miocene or Pliocene–Holocene). These
units vary in lithology, thickness, areal distribution, depositional
environment, and hydrocarbon importance. Geological and geophysical
data show that the northern and central Gulf of Suez consist
of several narrow, elongated depositional troughs, whereas the
southern part is dominated by a tilt-block terrane, containing numerous
offset linear highs.
Major prerift and synrift source rocks have potential to yield oil
and/or gas and are mature enough in the deep kitchens to generate
hydrocarbons. Geochemical parameters, sterane distribution, and
biomarker correlations are consistent with oils generated from marine
source rocks. Oils in the Gulf of Suez were sourced from potential
source rock intervals in the prerift succession that are typically
oil prone (type I), and in places oil and gas prone (type II), or
are composites of more than one type (multiple types I, II, or III
for oil prone, oil and gas prone, or gas prone, respectively).
The reservoirs can be classified into prerift reservoirs, such as
the Precambrian granitic rocks, Paleozoic–Cretaceous Nubian sandstones,
Upper Cretaceous Nezzazat sandstones and the fractured
Eocene Thebes limestone; and synrift reservoirs, such the Miocene
sandstones and carbonates of the Nukhul, Rudeis, Kareem, and Belayim
formations and the sandstones of South Gharib, Zeit, andpost-Zeit. The majority of oil fields in the region incorporate
multiple productive reservoirs. Miocene
evaporites are the ultimate hydrocarbon seals, whereas
the shale and dense limestones of the prerift and the
synrift stratigraphic units are the primary seals. Structural,
stratigraphic, and combination traps are encountered
in the study area. The Gulf of Suez is the most
prolific and prospective oil province in Egypt, and any
open acreage, or relinquished area, will be of great interest
to the oil industry.

- by Ahmed E. Radwan
- •
- Geology, Structural Geology, Research Methodology, Petroleum
- by Mohammed Hakimi
- •
- Geology, Arabian Gulf, Reservoir Characterization, Porosity

A sequence stratigraphic analysis was carried out on the sedimentary packages of parts of the Bengal Basin hydrocarbon province. This paper focuses on the identification of petroleum system of Srikail Gas Field within eastern folded belt of Bengal basin using sequence stratigraphic concept. Three strike and five dip seismic lines are used in this work and data analysis is done using Petrel 2015 software. Seismic line-2 (SK-2) of Srikail is good in resolution and is used here only for identifying potential petroleum system. Seven sequence boundaries were identified on the basis of onlap and reflection truncation. The result of the interpreted sequence boundary has revealed that all the elements which are required to generate a potential prospect are present in the study area. Fine grained sediments deposited during the rising and lowering of sea level might act as a potential source rock. Time contour maps of the study area have revealed that the NW-SE trending anticlinal Srikail structure is largely affected by shale filled channel in the crestal and western flank. The channel filled shale is later acting as a seal on north and western part of the structure. Erosional remnants truncated against shale fill canyon is acting as prospective reservoirs in the Srikail gas field. The NW-SE trending anticlinal structure and shale fill canyon help this sand as potential traps for hydrocarbon accumulation. Hence the petroleum system of the study area become very prospective in terms of hydrocarbon accumulation.

- by Md. Imam Sohel Hossain and +1
- •
- Reservoir Characterization, Oil and Gas Reservoir Characterization

Stratigraphy and the oil industry are intricately intertwined and have been so ever since the early days of hydrocarbon exploitation. Stratigraphic understanding forms the basis for all upstream activity from basin exploration through field evaluation to reservoir development and production. In the quest for hydrocarbons, both the exploration and exploitation programs can be greatly enhanced by applying stratigraphic analysis. This technique provides the explorationist with the capability to recognize, discover and evaluate new hydrocarbon reservoirs and to reduce the risk in management's decision-making.
Stratigraphic approach to hydrocarbon studies can make use of high-resolution biostratigraphic and pale bathymetric data, well-log signatures and seismic-reflection profiles, and well core data to determine the lithostratigraphy, lithofacies, depositional sequences, and the sequence boundaries.
This study explores the integration of seismic and well-log data for stratigraphic studies. The identification of depositional environments from well logs is based on the principle that well log responses are related to changes in thickness, texture, grain size, and lithology along the well path, while the relection pattern recorded on seismic sections can be interpreted in term of depositional environment and lithofacies.
A case study of the Sequence Stratigraphy of Akos Field in the Coastal Swamp Depobelt of the Niger Delta was considered. From which it can be concluded that the integration of seismic and well log data for stratigraphic studies is a valuable tool for oil and gas exploration.

- by Victor Towoju
- •
- Geophysics, Exploration Geophysics, Reservoir Characterization, Applied Geophysics

... Con-sidering that the Superior Province was constructed largely from the addition of mantle-derived material between 3100 and 2600 Ma (Card 1990) and that the Grenville Province comprises tectonically stacked slices of reworked... more

GOR and asphaltene gradients are routinely measured by downhole fluid analysis (DFA) and analyzed by the cubic EoS and the FHZ EoS, respectively. These results are then placed within a reservoir perspective; for example, equilibrated asphaltenes are known to indicate reservoir connectivity. Therefore, understanding the origins of these gradients is important. The variations of different crude oil components measured in present day are a function of charge history as well as in-reservoir fluid processes that can cause fluid components to equilibrate thermodynamically. Here, petroleum system modeling is used to create different initial reservoir fluid distributions immediately after trap filling, where layer-cake " Stainforth " density stacking trap filling is presumed. Charges that are relatively homogeneous versus those of greatly differing thermal maturities are considered. Subsequent to trap filling, diffusion is forward modeled. For a charge of greatly differing thermal maturity, the initial (post trap filling) versus final equilibrated gradients in GOR and asphaltenes are seen to be similar, equilibrium is attained relatively quickly. In contrast, for this case, the large initial gradient in liquid fingerprints and biomarkers is very dissimilar to the final homogenous equilibrium distribution of these components, thus, longer times are required for equilibrium. Consequently, a single oil column can exhibit equilibrium distributions of GOR and asphaltenes with disequilibrium in oil fingerprints and biomarkers. In contrast, a homogenous charge can yield the opposite, equilibrium of fingerprints and biomarkers, and disequilibrium of GOR and asphaltenes. The 'thermodynamic distance' from the initial condition (at end of trap filling) to equilibrium determines, to a large degree, the diffusive time required to achieve equilibrium.

- by Oliver C Mullins and +1
- •
- Geochemistry, Reservoir Engineering, Reservoir Characterization, Asphaltenes

In this reservoir study, two adjacent fault blocks have
been subject to the same initial liquid and subsequent gas
charges, yet fl uid characteristics are different. Wells in each
fault block have a gas-oil contact (GOC) and an oil-water
contact (OWC), thus all depth-dependent in-reservoir fl uid
geodynamic processes are visible within each well. The
two adjacent fault blocks are found to be at different stages
of the same reservoir fl uid geodynamic process yielding a
‘movie’ with two time frames.
Diffusion of gas, from the late gas charge, into the oil
column causes a signifi cant increase of solution gas initially
at/near the GOC. This increase in solution gas causes the
asphaltenes to migrate down in the oil column. Well 1 is in
the middle of this process exhibiting huge disequilibrium
gradients of gas-oil ratio (GOR), saturation pressure and
asphaltenes. In Well 2, the diffusion of gas reached the
base of the column expelling most of the asphaltenes out
of the oil column creating a 10-m tar mat at the base of
the column. In Well 2, the oil is nearly in thermodynamic
equilibrium in contrast to large disequilibrium in Well 1.
Asphaltene extracts of core plugs are consistent with these
fl uid profi les and reinforce conclusions. The disequilibrium
oil column is associated with low vertical permeability
as seen with pressure interference testing indicating
multiple baffl es. In drillstem tests (DSTs), the equilibrated
oil column exhibited 10x greater production than the
disequilibrium oil column. Equilibrated asphaltenes are
associated with good production; here, disequilibrium
asphaltene gradients and poor vertical permeability are
associated with low production due to reservoir baffl ing.

The study area is located in the northern and western parts of Moldavian Platform, the oldest platform unit of the Romanian territory and representing the margin of the East European Platform. Two hydrocarbon systems are recognized in the Moldavian Platform: a thermogenic system of Paleozoic age and a biogenic system of Miocene age. The Miocene biogenic system comprises significant natural gas fields (including dry gas with more than 98% methane), reservoired especially in Sarmatian (late Middle Miocene) deposits, where suitable conditions for accumulation and sealing are encountered. The Sarmatian stage was marked by permanent changes of the sedimentary conditions, passing from a predominantly marine environment to a transitional one, of deltaic type with lacustrine-continental influences. The gas accumulations are usually hosted in sands/sandstones (observed as good seismic reflectors with continuous or discontinuous character) that pinch out forming lithostratigraphic traps. The sand beds or sand bodies formed during the deltaic construction, especially when they overlap and alternate with pelitic sequences, offer the most favorable settings for such accumulations.
The integrated analysis of recent geophysical well logs (conventional logs and high-resolution electrical imaging logs) and seismic reflection surveys, together with mud logging data and well flow test results, allow a better characterization of the Sarmatian deposits, particularly the gas reservoirs, from the study area. The correlation of three exploration wells along a NW–SE profile indicates that a low-energy, fine-grained depositional environment is developing towards SE, with a prevalence of claystones and with fewer sand reservoirs, if any. This may reflect a deltaic transition from distributary channels and mouth bar sands towards prodelta offshore silts and muds. The processed electrical imaging data recorded in the northernmost exploration well show two dominant dip azimuths (142 and, subordinately, 218 degrees) in the shale intervals. Most likely, these indicate NW to SE and NE to SW sediment paleotransport directions, related to seaward delta progradation. The electrical imaging results also reveal the presence of two high-angle faults (48–54 degrees dip values), which might have provided pathways for gas migration from deeper levels up to shallower Sarmatian reservoirs.

- by Bogdan NICULESCU and +1
- •
- Geology, Geophysics, Structural Geology, Oil and gas

Gas condensate fields are quite lucrative fields because of the highly economic value of condensates. However, the development of these fields is often difficult due to retrograde condensation resulting to condensate banking in the immediate vicinity of the wellbore. In many cases, adequate characterization and prediction of condensate banks are often difficult leading to poor technical decisions in the management of such fields. This study will present a simulation performed with Eclipse300 compositional simulator on a gas condensate reservoir with three case study wells-a gas injector (INJ1) and two producers (PROD1 and PROD2) to predict condensate banking. Rock and fluid properties at laboratory condition were simulated to reservoir conditions and a comparative method of analysis was used to efficiently diagnose the presence of condensate banks in the affected grid-blocks. Relative Permeability to Condensate and gas and saturation curves shows condensate banks region. The result shows that PROD2 was greatly affected by condensate banking while PROD1 remained unaffected during the investigation. Other factors were analyzed and the results reveal that the nature and composition of condensates can significantly affect condensate banking in the immediate vicinity of the wellbore. Also, it was observed that efficient production from condensate reservoir requires the pressure to be kept above dew point pressure so as to minimize the effect and the tendency of retrograde condensation.

The objective of this study is to provide information on source organic matter input, depositional conditions and the correlation between crude oils recovered from Sunah oilfield and Upper Jurassic Madbi Formation. A suite of twenty-six crude oils from the Lower Cretaceous reservoirs (Qishn clastic) of the Masila Region (Eastern Yemen) were analysed and geochemically compared with extracts from source rock of the Upper Jurassic (Madbi Formation). The investigated biomarkers indicated that the Sunah oils were derived from mixed marine and terrigenous organic matter and deposited under suboxic conditions. This has been achieved from normal alkane and acyclic isoprenoids distributions, terpane and sterane biomarkers. These oils were also generated from source rock with a wide range of thermal maturity and ranging from early-mature to peak oil window. Based on molecular indicators of organic source input and depositional environment diagnostic biomarkers, one petroleum system operates in the Masila Region; this derived from Upper Jurassic Madbi organic-rich shales as source rock. Therefore, the hydrocarbon exploration processes should be focused on the known location of the Upper Jurassic Madbi strata for predicting the source kitchen.

- by Nabil M . Al-Areeq
- •
- Sedimentology, Petrophysics, Petroleum, Petrology and Geochemistry

Downhole fl uid analysis (DFA) is used to characterize
compositional fl uid gradients, and equations of state
(EoS) models are used for analysis to delineate reservoir
fl uid variations, connectivity and other complexities. A
series of reservoirs is examined to assess the state of the
contained fl uids in terms of thermodynamic equilibrium
in the reservoir. Substantial, systematic fl uid variations
are found using DFA. The cubic EoS is used for gasliquid
analysis, and the Flory-Huggins-Zuo EoS and the
Yen-Mullins model of asphaltenes are used for analysis of
dissolved solid-solution equilibria of reservoir crude oils.
‘Young’ reservoirs exhibit large, nonmonotonic variations
of fl uids (and solids), moderately aged reservoirs exhibit
monotonic, yet disequilibrium properties and ‘aged’
reservoirs are fully equilibrated even when in massive
scale. Nevertheless, these old reservoirs retain signifi cant
fl uid and organic solid variations as a result of sequential
fl uid-related processes in geologic time.
The dynamic behaviors of fl uids within reservoirs
that account for these variations are obtained by linking
a fundamental understanding of petroleum with basic
concepts from fl uid mechanics. In particular, the location
of tar deposition within reservoirs is clarifi ed when formed
due to asphaltene instability upon a secondary reservoir fl uid
charge. Tar deposition can be formed upstructure for rapid
gas charge, as is regularly seen in young reservoirs, or can
be formed at the oil-water contact for a slower gas charge,
as seen in many older reservoirs. The state of the reservoir
fl uids within the context of geologic time is shown to be
tightly coupled to key reservoir concerns for production.
Thus, understanding the context of the reservoir within
the overall geology and petroleum system can be used to
optimize reservoir evaluation. The expanding capabilities
of DFA, plus major advances in asphaltene science, have
revealed dramatic systematic variations of reservoir
fl uids and are becoming indispensable for optimization of
production.

- by Oliver C Mullins and +2
- •
- Geochemistry, Reservoir Engineering, Oil and gas, Reservoir Characterization

separator test to determine pvt properties of crude oil and gases

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
- •
- Geology, Geophysics, Petrophysics, Reservoir Engineering

Interference well test analysis provides valuable information about reservoir characteristics such as permeability and hydraulic diffusivity coefficient. Interference well test analysis is based on the solution of the diffusivity equation which describes mass transfer in a porous [1]. Interference tests have two major objectives. They are used (l) to determine whether two or more wells are in pressure communication (i.e., in the same reservoir) and (2) when communication exists, to provide estimates of permeability k and porosity/compressibility product, in the vicinity of the tested wells [2]. The pressure variation with time recorded in observation wells resulting from changes in rates in production or injection wells. In commercially viable reservoirs, it usually takes considerable time for production at one well to measurably affect the pressure at an adjacent well. Consequently, interference testing has been uncommon because of the cost and the difficulty in maintaining fixed flow rates over an extended time period. With the increasing number of permanent gauge installations, interference testing may become more common than in the past [3].

- by Omar Mohammed
- •
- Reservoir Characterization
- by Yan Darmadi
- •
- Reservoir Characterization

When reservoir pressure decreases in gas condensate reservoirs, there is a compositional change which makes the system difficult to handle. This type of system requires an Equation of State (EOS) to ensure proper fluid characterization so that the Pressure Volume Temperature (PVT) behavior of the reservoir fluid can be well understood. High quality and accurate PVT data will help reservoir engineers to predict the behavior of reservoir fluids and facilitate simulation studies. The aim of this study is to determine what to do on reservoir fluid before carrying out reservoir modeling. PVT data were obtained from a reservoir fluid in the Niger Delta which was sampled following standard procedures. Then the laboratory experiments were critically examined to ensure accuracy, consistency and validity before PVT analysis. Finally, the results from the PVT experiments were imported into PVT software and subsequently in a reservoir simulator for simulation studies. These processes generate the EOS model for reservoir modeling of gas condensate reservoirs. 2 the consistencies of the data were ascertained and the composition added up to 100%. The pattern of the CCE/CVD comparison plot was observed to reflect that less liquid dropout was experienced later in the depletion process of the CVD experiment than in the CCE experiment. PVT validation checks help to confirm the Gas oil ratio of the system and the richness of the gas condensate fluid. It is imperative to obtain representative reservoir fluid samples and carry out reliable laboratory experiments to generate PVT data for fluid characterization. PVT fluid characterization and consistency checks will ensure that accurate results are obtained from reservoir simulation models leading to proper reservoir management. NOMENCLATURES A 1 = Slope of the Hoffman et al Plot A o = Intercept of the Hoffman et al plot BIP = Binary Interaction Parameter CCE = Constant Composition Expansion CVD = Constant Volume Depletion C f = Characteristic factor correlation EOS = Equation of State F = Total moles of Feed Fi = Hoffman Factor FVF = Formation Volume Factor F/V = Intercept of Mass Balance Plot GOR = Gas Oil Ratio K-Value = Y/X L = Total moles of separator Liquid L/V = Slope of Mass Balance Plot Mi = Molecular weight of Heptane plus Pc = Critical Pressure P D = Dew Point Pressure PR = Peng-Robinson PT = Patel and Teja Psc = Pressure at standard conditions PVT = Pressure Volume Temperature RK = Redlich Kwong SRK = Soave Redlich Kwong T = Separator Temperature Tb = Normal Boiling Temperature TBP = True Boiling Point Tc = Critical Temperature V = Total moles of separator Vapour VLE = Volume Liquid Equilibrium Xi = Moles fraction of component i in Liquid Yi = Mole fraction of component i in Vapour Zi = Mole fraction of component i in feed ZJ = Zudkevitch and Joffe i  = Specific Gravity

Crude oils consist of dissolved gases, liquids,
and dissolved solids—the asphaltenes. The chemical
identity and thermodynamic treatment of gas and liquid
components of crude oil have long been understood. For
example, the cubic equation of state (EoS) is very familiar
to the reservoir engineering community. In contrast, in
years past, the asphaltenes were viewed as complex,
enigmatic and without a thermodynamic foundation.
Consequently, oil􀂿 eld observations related to asphaltenes,
such as asphaltene gradients in crude oil, heavy-oil
gradients, viscosity gradients, tar mat formation, bitumen
deposition and asphaltene 􀃀 ow assurance, were all viewed
very much within a phenomenological context without
a 􀂿 rst-principles foundation. In the recent past, a simple
molecular and nanocolloidal model of asphaltenes, the
Yen-Mullins model, has been shown to apply broadly. This
model, combined with the Flory-Huggins-Zuo Equation
of State (FHZ EoS), accounts for asphaltene gradients
in bulk oil and when combined with the Langmuir EoS
accounts for oil-water interfacial properties. Such success
establishes validation.
These new developments in asphaltene science
have been closely linked with downhole 􀃀 uid analysis
(DFA) to address a wide variety of reservoir concerns.
Consequently, petrophysicists and other geoscientists
traditionally charged with the responsibility of formation
evaluation are left with the task of understanding the
asphaltenes. Here, we provide an overview of asphaltenes
in order to make asphaltenes accessible to technologists
who are not expert in petroleum and asphaltene science.
The emphasis is on the simplicity of asphaltene chemistry.
This discussion naturally leads to basic chemical precepts
of solubility especially because asphaltenes are de􀂿 ned by
their solubility characteristics.

- by Oliver C Mullins and +1
- •
- Geochemistry, Reservoir Engineering, Oil and gas, Reservoir Characterization
- by Musliu Oladipo
- •
- Geology, Reservoir Characterization

Revisión de las propiedades fundamentales de los fluidos de yacimiento y de las pruebas de caracterización (PVT). Análisis de las pruebas PVT y evaluación teórica.

- by Julius U Akpabio
- •
- Reservoir Engineering, Reservoir Characterization
- by Agus Alexandri
- •
- Reservoir Characterization

The generation of an Integrated Petrophysical Model for Rayoso Clástico Formation in Desfiladero Bayo Este Field, was performed with the objective of improving the knowledge of the reservoir, and supporting static and dynamic models to, consequently, define the best way to continue its development. One of the important characteristics for this purpose is the determination of water saturation in an environment of low resistivities, which leads to high uncertainty in its estimation from logs. This work presents how an study was developed based upon the integration of conventional and special core analysis data, integrated with information from well logs, geological environment and production data. At the end, it was possible to compare an Sw calculated from the basis of a resistivity model, with an Sw defined from Leverett's J-Function, which required the definition of rock types based on the size and distribution of pore throats.

- by Juan Carlos Porras and +2
- •
- Petrophysics, Reservoir Characterization
- by Aliniski Jalo
- •
- Geology, Reservoir Characterization

This study will provide insight to evaluate the potential risks involved with the alteration of in situ effective stresses around the borehole and the risks associated with the reservoir pressure decline. We studied how years of production and reservoir depletion may cause future major geological hazards in the area of study. Wellbore instability and stress distribution analysis around a vertical borehole is also carried out in the Bakken Formation including elastic anisotropy of the layer. We calculated the magnitude of maximum principal horizontal stress as a major input parameter through a new method. This study shows the importance of geomechanical modeling in the petroleum industry with the recent growth of drilling plans in unconventional reservoirs as a novel source of energy where many of them are fine layered, anisotropic and naturally fractured. For this study, dynamic elastic properties were collected through the Bakken Formation using advanced sonic logs. The interpretation of these data is significant in estimating the rock strength, pore pressure, and in situ stresses. The measured dynamic elastic moduli were converted to static ones and were used as input into poroelasticity equations to calculate the magnitude of the horizontal principal stresses. The direction of the maximum principal horizontal stress was determined to be N70E by analyzing fast shear azimuth (FSA) using major fractures which have caused more than 20% shear anisotropy. Finally stress analysis and wellbore stability were performed and compared in the current state of the reservoir stress state and after 5 years of production. Stress polygons are created in the reservoir (horizontal section of the well) to predict future natural hazards. The results confirm the possible occurrence of normal faulting in the region and existence of borehole breakouts after years of production.

- by Ostadhassan, Mehdi and +1
- •
- Geomechanics, Reservoir Engineering, Reservoir Characterization, Computational geomechanics

Astronomically located on coordinate 120o29’00” - 124o7’00” BT and
0o32’00” - 0o53’00” LS. Administratively the research area is located in the area
concession of Pertamina Geothermal Energy Limited company’s, Kotamobagu
Regency, North Sulawesi. This research is referred to know the geothermal reserves of
the Kotamobagu prospect area, with qualitative method by geological analysis and
kuantitatife method by geochemical and geophysical analysis.
The reserves calculate performed with the volumetric method (measurable
hypothesis) refers to geothermal SNI. Variables value determination obtained through
geological data, geochemical analysis, geophysical analysis, and assumed parameter
number in unexpected resource class geothermal SNI.
The obtained variables from this research is density 2,6 gr/cm3, volume 16,895
km2, fluid type is bicarbonate and sulfate, initial temperature 260oC, final temperature
180 oC, surface temperature 91,4 oC, water saturation 100 %, porosity 10%, rock heat
capacity 1 kJ/kg °C, age of the plant 30 years, electricity conversion factor 10 %, and
also additional variables obtained by the steam heat table (Beaton, 1986). Total of the
geothermal reserves available are 176.28 Mwe.
Keywords : kotamobagu, reserves, geothermal energy, volumetric method

- by dwii nuraenia and +1
- •
- Geothermal Energy, Reservoir Characterization, Volumetric Development, Pertamina Geothermal Energy

Carbonate reservoir is known as heterogeneous reservoir due to its pore complexity caused by depositional setting and diagenetic process. This complexity can create comprehension about its storage capacity and flow capacity, including water saturation. Reservoir characterization method through Flow Zone Indicator (FZI) can be useful to divide reservoir rock based on its flow unit and irreducible water saturation as well. Reservoir characterization is applied to Kujung formation, in Jago and Bravo Structure, North East Java Basin which has an invalid calculation Archie's water saturation. Firstly, flow unit is identified by FZI, then water saturation of the reservoir is then calculated by Leverett J-Function method which every flow unit has its irreducible water saturation. From FZI method, Kujung formation can be
divided into three flow units with their own characteristics. Flow unit 1 has channeling pore type and 0.25 Swirr value, flow unit 2 has vuggy pore type and 0.39 Swirr value, while flow unit 3 has highly cemented interparticle pore type and 0.43 Swirr value. Water saturation, calculated by using Leverett J-Function method, provides a more precise result compared to Archie’s water saturation method, which has been validated by fractional flow test in Kujung reservoir interval. It is inferred that the reservoir characterization implies an excellent prediction of water saturation by using J-Function Method.

Integration of structural and horizon mapping of
3D seismic volume, petrophysical studies of over sixty (60)
wireline logs, stratigraphic analyses, reservoir property
modeling and production information have been adopted to
study Eni field that has been experiencing production
decline with increase in water output. Generated reservoir
structural framework and spatial reservoir property distribution
have proved useful to guide the optimal placement
of proposed wells and also provide information needful for
the development of best production plan that would guarantee
effective oil drainage from the delineated reservoir
compartments.

The use of seismic direct hydrocarbon indi-
cators is very common in exploration and reservoir
development to minimise exploration risk and to opti-
mise the location of production wells. DHIs can be
enhanced using AVO methods to calculate seismic
attributes that approximate relative elastic properties. In
this study, we analyse the sensitivity to pore ﬂuid
changes of a range of elastic properties by combining
rock physics studies and statistical techniques and
determine which provide the best basis for DHIs.
Gassmann ﬂuid substitution is applied to the well log
data and various elastic properties are evaluated by
measuring the degree of separation that they achieve
between gas sands and wet sands. The method has been
applied successfully to well log data from proven
reservoirs in three different siliciclastic environments of
Cambrian, Jurassic, and Cretaceous ages. We have
quantiﬁed the sensitivity of various elastic properties
such as acoustic and extended elastic (EEI) impedances,
elastic moduli (Ksat and Ksat–l), lambda–mu–rho method
(kq and lq), P-to-S-wave velocity ratio (VP/VS), and
Poisson’s ratio (r) at fully gas/water saturation scenar-
ios. The results are strongly dependent on the local
geological settings and our modeling demonstrates that
for Cambrian and Cretaceous reservoirs, Ksat–l, EEI, VP/
VS, and r are more sensitive to pore ﬂuids (gas/water).
For the Jurassic reservoir, the sensitivity of all elastic
and seismic properties to pore ﬂuid reduces due to high
overburden pressure and the resultant low porosity. Fluid
indicators are evaluated using two metrics: a ﬂuid indi-
cator coefﬁcient based on a Gaussian model and an
overlap coefﬁcient which makes no assumptions about a
distribution model. This study will provide a potential
way to identify gas sand zones in future exploration.

The lower Indus basin is one of the largest hydrocarbon producing sedimentary basins in Pakistan. It is characterized by the presence of many hydrocarbon-bearing fields including clastic and carbonates proven reservoirs from the Cretaceous to the Eocene age. This study has been carried out in the Sanghar oil field to evaluate the hydrocarbon prospects of basal sand zone of lower Goru Formation of Cretaceous by using complete suite of geophysical logs of different wells. The analytical formation evaluation by using petrophysical studies and neutron-density crossplots unveils that litho-facies mainly comprising of sandstone. The hydrocarbons potentialities of the formation zone have been characterized through various isoparameteric maps such as gross reservoir and net pay thickness, net-to-gross ratio, total and effective porosity, shaliness, and water and hydrocarbons saturation. The evaluated petrophysical studies show that the reservoir has net pay zone of thickness range 5 to 10 m, net-to-gross ratio range of 0.17 to 0.75, effective porosity range of 07 to 12 %, shaliness range of 27 to 40 % and hydrocarbon saturation range of 12 to 31 %. However, in the net pay zone hydrocarbon saturation reaches up to 95%. The isoparametric charts of petrophysically derived parameters reveal the aerial distribution of hydrocarbons accumulation in basal sand unit of the lower Goru Formation which may be helpful for further exploration.

- by Nisar Ahmed and +1
- •
- Petrophysics, Reservoir Characterization, Well Logs Interpretation

The various and heterogeneous nomenclatures previously proposed for the Jurassic of both central and northern Tunisia were examined and
revised. In this work we propose a new lithostratigraphic chart taking into account the progress of our knowledge on the sedimentological and
palaeontological (ammonites) aspects obtained during the two late decades. This chart summarizes and restores the major sedimentary and
stratigraphic events (discontinuities) recorded in the Jurassic rocks. It outlines the main phases of the palaeogeographic evolution of the
Tunisian atlasic domain during the Jurassic, in relation with the main controlling factor (tectonic and eustatism), which accompanied the
tethyan rifting.

The value of water saturation in the reservoir at any point in time determines largely the hydrocarbon in place. This plays a vital role in field development economics. Its determination in well logging from formation resistivity factor approach requires a good knowledge of representative values of the intercept "a" and the cementation factor "m" as used by Archie in his derived relationship between formation resistivity factor "F" and porosity " ".
This paper presents "a" and "m" values and their relationship obtained from formation resistivity factor and porosity data from four different samples with BET surface area range 0.015m2/g to 0.5m2/g of a synthetic model rock (ROBU). Comparison between the resulting model and the widely used ones as reported in the literature was carried out. The formation resistivity factor values of range 4.5 to 8.5 were plotted against the porosity values of range 0.27 to 0.39 on a semi-log plot. Power law regression with R2 fitting of 0.994 was applied to obtain representative values of “a” and “m” and a relationship was derived. Using an assumed range of values of porosity from 0.2 to 0.8, the values of the formation resistivity factor obtained with the derived model were compared with those obtained with the widely used ones presented in the literature.
The result show that the values of the intercept “a” and cementation factor “m” arrived at for the synthetic glass rock, though of the same form are slightly different from Archie’s and Chevron equation. Though the derived model is slightly of different form with the Shell model but their conformity increases with increasing porosity. At high porosity, minimal difference is observed in the values of the formation resistivity factor recorded for both models. At a porosity value of 0.4, the derived model gives the same result as Humble model. However, the model gives higher values of formation resistivity factor at a porosity of less than 0.4 and lower values at a porosity of more than 0.4. The Humble model gives the least value of resistivity factor followed by the derived model. Rather than using existing models, the use of representative values of "a" and "m" in any geological field should be encouraged for proper reservoir management decision.

- by Abasiubong A UDOFIA and +1
- •
- Reservoir Characterization, Porosity and Permeability in Reservoirs

Source locations provide fundamental information on earthquakes and lay the foundation for seismic monitoring at all scales. Seismic source location as a classical inverse problem has experienced significant methodological progress during the past century. Unlike the conventional traveltime-based location methods that mainly utilize kinematic information, a new category of waveform-based methods, including partial waveform stacking, time reverse imaging, wavefront tomography, and full waveform inversion, adapted from migration or stacking techniques in exploration seismology has emerged. Waveform-based methods have shown promising results in characterizing weak seismic events at multiple scales, especially for abundant microearthquakes induced by hydraulic fracturing in unconventional and geothermal reservoirs or foreshock and aftershock activity potentially preceding tectonic earthquakes. This review presents a comprehensive summary of the current status of waveform-based location methods, through elaboration of the methodological principles, categorization, and connections, as well as illustration of the applications to natural and induced/triggered seismicity, ranging from laboratory acoustic emission to field hydraulic fracturing-induced seismicity, regional tectonic, and volcanic earthquakes. Taking into account recent developments in instrumentation and the increasing availability of more powerful computational resources, we highlight recent accomplishments and prevailing challenges of different waveform-based location methods and what they promise to offer in the near future. Plain language summary Earthquakes are a common physical phenomenon involving ground shaking and rupturing of the surface of the Earth. In addition to the well-known catastrophic tectonic earthquakes, similar vibration sources also appear at various scales in engineering fields, such as acoustic emissions resulting from microcracks in building walls and bridges, rock bursts in mines, microseismic events generated by mining and fluid injection/extraction, and microseisms caused by crustal activity. Seismic information provides a powerful tool for geophysical and engineering surveys. The source location describes the spatial and temporal extent of an earthquake and lays the foundation for seismic monitoring. Seismic location methods have made significant progress over the last century. Specifically, a category of new waveform-based location methods has emerged as a counterpart of conventional traveltime-based inversion. These methods directly utilize the notion of a wavefield and, very similar to an optical lens, aim at spatially focusing a source's emitted energy. Waveform-based methods have provided robust and effective source location results at various scales. We summarize the development history and current state of waveform-based location methods and discuss the advantages and challenges through their applications for seismic source location at multiple scales.

- by Benjamin Schwarz
- •
- Earth Sciences, Geophysics, Earthquake Engineering, Reservoir Engineering

The Upper Bahariya Member represents an argillaceous sandstone reservoir and it is one the Late Cretaceous units. There is a need for understanding the detailed facies and petrophysics of this member and identifying whether its petrophysical parameters are related to the facies changes or the present structures. Therefore, the present study aims at determining the facies and petrophysical characteristics of the Upper Bahariya Member and their distribution in the Abu Gharadig field. This field is located in the central portion of Abu Gharadig basin in the northern part of the Western Desert of Egypt. The available data for the present study includes four digital well logs, twenty 2D seismic sections and a checkshot survey. This is achieved through building the 3D facies and petrophysical models using Petrel™ Schlumberger Modeling software. These models were built on a predefined 3D stratigraphic and structural framework. The interpreted lithology of the Upper Bahariya Member is represented by sandstone cemented by argillaceous and/or calcareous materials, siltstone, shale and minor limestone inter-beds. A new lithofacies subdivision for the Upper Bahariya is introduced in the present study through the study area. This subdivision is represented by three lithofacies (an upper shale-silt-carbonate lithofacies, a middle sand-silt lithofacies and a lower shale-silt lithofacies). The Upper Bahariya Member is evaluated as a good quality reservoir and it exhibits rapid variations in the conditions of deposition, from continental fluvial to marine passing through the tidal flood plain conditions. The sandstone source is mainly from the southeast and southwest directions. The vertical and lateral changes of the different petrophysical parameters are directly related to vertical and lateral facies changes.

Seismic attributes used to identify and isolate important geological features from seismic data, while no unique attribute is expected to perfectly identify the targeted object, various attributes contributing to the same purpose should be utilized simultaneously when performing detection. In this work we present new hybrid attributes generated by combining various seismic attributes to enhance identifying of interested geological features from seismic data, by combining different spectral bands frequencies to increase signal-to-noise ratios, one of new hypride attributes average SD(spectral decompositions ) attributes, this attributes generated by combination divergent types of seismic attributes to eliminate noises effect and reduce effect of un wanted geological feature, average SD attribute used to generate similarity attribute to improve shallow channel detection and guidance to determine gas migration pass, it is important to combine faults attributes with amplitude attributes to identify faults trends, To validate the proposed method we use the volume of the Netherlands offshore F3 block downloaded from the Open Seismic Repository, average SD deliver promising results for both shallow and deep thin geological features interpretation because it combine different bands frequencies in one volume. Furthermore, the results show that average SD attributes can use for predict gas migration pass and faults attributes help for identify shallow minor faults.

- by Mohamed Shihataa
- •
- Geology, Geophysics, Reservoir Characterization, Seismic Attributes

The study area lies in the Greater Ughelli Depobelt of Niger Delta. Recently, a major focus within the Niger Delta is the rejuvenation of older fields (also called brown fields) and the identification of new prospects from these old fields. This study is focused on the evaluation of the Olive Field and the identification of new prospects within the field. Data used were; 3D seismic cube, four composite well logs and check shot. 3 dimension seismic, well log and structural interpretation were done to evaluate the petroleum potentials of the reservoirs using the petrel 2010 and the interactive petrophysic v.36 softwares. Well data were used in the identification of reservoirs and determination of petrophysical parameters and hydrocarbon presence. Four horizons that corresponded to selected well tops were mapped after well to seismic tie. Time and depth structural maps were created from the mapped horizons. Four Hydrocarbon bearing reservoirs within the depth range of 6743 ft – 9045 ft, having volume of shale (Vsh) ranging from 15.32%-29.06% were interpreted. The total porosity of the reservoirs ranges from 24.63%-34.01%, while the effective porosity ranges from 17.26%-31.71%, indicating the reservoirs have very good porosities. The ratio of the Net to Gross Thickness of the reservoirs ranges from 0.720 – 0.980 while the water saturation values ranges from 19.87%-29.07%. From the water saturation deductions, the hydrocarbon saturation ranges from 70.93%-78.86% of gas in the given reservoirs. Amplitude attribute extraction and analysis of the horizon maps was used in the identification of areas with hydrocarbon accumulations which are conformable with structures. The use of structural and attribute maps has aided the identification of prospects in the Olive Field. Therefore, it is recommended that wells be drilled to target the new prospects which will improve the hydrocarbon recovery in Olive Field.

- by Izuchukwu I Obiadi
- •
- Geology, Structural Geology, Reservoir Characterization, Delta

The study is focused on the formation evaluation of Srikail gas field located in western part of folded belt of the Bengal Basin which can be used to improve reservoir characterization. Digital version of wireline log data is used in this research work. Data analysis is done to evaluate the reservoirs using Techlog 2011 software. Four wells are drilled and data are used in the identification of prospective zones and determination of petrophysical properties and hydrocarbon presence. Seven hydrocarbon bearing zones within the measured depth range 2429.5-3501 m with volume of shale ranging from 8%-38% are interpreted. The effective porosity of the reservoirs ranges from 12.3%-24.9%, indicating the reservoirs have moderate to good porosities. The ratio of the net to gross thickness of the reservoir ranges from 10%-56%, while the water saturation ranges from 24.9%-46.9%. From the water saturation deductions, the hydrocarbon saturation ranges from 53.1%-75.1% of gas in the reservoirs indicating all the zones well saturated with hydrocarbon. From gross thickness, net thickness and net to gross ratio it is found that D, E and F sands have the significant gross and net thickness and net to gross ratio among the gas sands. Hence the three gas sands have comparatively higher reserve than the other four gas sands (A, B, C and G sands). Finally well to well correlation is done which reveals the detailed picture of reservoir sand distribution of Srikail gas field with the reason of missing of reservoir gas sand in the Srikail-1 well.

- by Benking Ugwu
- •
- Reservoir Characterization, Porosity, Niger Delta, Poisson's ratio

The performance of matrix acidized selected wells from the Tertiary sandstone reservoirs in the Niger/Delta was
evaluated, Data obtained was used to evaluate flow efficiency and production performance before and after acidizing. The results
showed that Matrix acidizing proven to be the best stimulation technique employed in recent years to remove near wellbore
damages and invariably increase productivity. The analysis involves the post net oil and percentage increase in oil achieved after acidizing, well inflow performance quality indicator and decline rate analysis.

- by Jeffrey Onuoma OSEH
- •
- Reservoir Characterization
- by Tiziana Vanorio
- •
- Geophysics, Reservoir Characterization, Permeability

Characterization of reservoirs or analysis of petrophysical characteristics includes determination of; lithology, porosity and permeability, etc. In this study, reservoir characterization is done by evaluation of well log data to obtain reservoir rock and fluid properties, such as porosity, permeability, lithology and stratigraphy on a foot by foot or meter by meter basis using Rock work 14 software. Log data of total four production wells of Kailashtila(KTL) field (KTL- 2, KTL- 3, KTL- 4, and KTL- 5) were analyzed. The Stratigraphic correlation modeling shows that the Kailashtila Gas Field is of uniform thickness in horizontal extend. Matrix density is estimated ranges from 2-2.65 gm/cc and resistivity of ranges from 20-50 ohm-m, reflecting the sandstone lithology with minor inclusions of shale. However, Density-Neutron (D-N) cross plot suggests that the lithology is mainly sandstone with little limestone. The porosity and permeability were determined which ranges from 20-35% and 100-500 millidarcy (md), respectively, which showing the good yielding capacity of the reservoir.

- by Daiyan Ahmed and +1
- •
- Reservoir Characterization

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
- •
- Geology, Geophysics, Structural Geology, Petrophysics