Reservoir Rocks (reservoir + rock)

Distribution by Scientific Domains


Selected Abstracts


PETROPHYSICAL CHARACTERISTICS OF SOURCE AND RESERVOIR ROCKS IN THE HISTRIA BASIN, WESTERN BLACK SEA

JOURNAL OF PETROLEUM GEOLOGY, Issue 4 2009
C. Cranganu
The petroleum system in the Histria Basin, Western Black Sea, includes Oligocene source rocks and Upper Cretaceous , Eocene reservoir rocks. Here we report on the petrophysical characteristics of these source and reservoir rocks using mercury intrusion porosimetry data from 14 core samples collected from five wells drilled on the East Lebada, West Lebada and Pescarus structures. Samples were in general dominated by carbonate lithologies with minor shales. Petrophysical parameters analyzed were: median pore-throat radius, average pore-throat radius, apparent porosity, pore-throat size distribution, pore-throat type, pore-throat sorting, maximum threshold entry radius, pore-throat radius at 35% mercury saturation (R35), and air permeability. Reservoir rock quality was estimated using a permeability / porosity / pore-throat type plot. The Oligocene samples showed little petrophysical variation. Samples were relatively homogenous and had the same pore-throat type (nano), were well sorted, had unimodal pore-throat distribution (suggesting the existence of a single fluid phase), had similar values for median and average pore-throat radius, and similar values for R35 and maximum threshold entry radius. Upper Cretaceous , Eocene samples were more heterogeneous in terms of petrophysical properties, and reservoir quality was in general higher than in the Oligocene interval. Average porosity and calculated air-permeability values were 18.4% and 0.37 mD, respectively for Upper Cretaceous samples; and 11.8% and 27.11 mD, respectively for Eocene samples. A case study of Oligocene and Cretaceous , Eocene samples from well West Lebada 817 is presented. This paper represents the first petrophysical study of source and reservoir rocks in the Histria Basin, Western Black Sea. The results will help to establish the links between petrophysical characteristics, age and depositional environment for source and reservoir rocks in other basins bordering the Black Sea. [source]


HYDROTHERMALLY FLUORITIZED ORDOVICIAN CARBONATES AS RESERVOIR ROCKS IN THE TAZHONG AREA, CENTRALTARIM BASIN, NW CHINA

JOURNAL OF PETROLEUM GEOLOGY, Issue 1 2006
Zhijun Jin
Reservoir rocks at the Tazhong 45 oil pool, central Tarim Basin, consist of fluoritized carbonate strata of Middle - Late Ordovician age. Petrological observations indicate that the fluorite replaces calcite. Several other hydrothermal minerals including pyrite, quartz, sphalerite and chlorite accompany the fluorite. Two generations of fluid inclusions are present in the fluorite. Homogenization temperatures (Th) for primary inclusions are mostly between 260°C and 310°C and represent the temperature of the hydrothermal fluid responsible for fluorite precipitation. Th for secondary inclusions range from 100°C to 130°C, and represent the hydrocarbon charging temperature as shown by the presence of hydrocarbons trapped in some secondary inclusions. The mineral assemblage and the homogenization temperatures of the primary fluid inclusions indicate that the precipitation of fluorite is related to hydrothermal activity in the Tazhong area. Strontium isotope analyses imply that the hydrothermal fluids responsible for fluorite precipitation are related to late-stage magmatic activity, and felsic magmas were generated by mixing of mafic magma and crustal materials during the Permian. Theoretical calculations show that the molecular volume of a carbonate rock decreases by 33.5% when calcite is replaced by fluorite, and the volume shrinkage can greatly enhance reservoir porosity by the formation of abundant intercrystalline pores. Fluoritization has thus greatly enhanced the reservoir quality of Ordovician carbonates in the Tazhong 45 area, so that the fluorite and limestone host rocks have become an efficient hydrocarbon reservoir. According to the modelled burial and thermal history of the Tazhong 45 well, and the homogenization temperatures of secondary fluid inclusions in the fluorite, hydrocarbon charging at the Tazhong 45 reservoir took place in the Tertiary. [source]


EVALUATION OF THE CONTROLS ON FRACTURING IN RESERVOIR ROCKS

JOURNAL OF PETROLEUM GEOLOGY, Issue 4 2005
D.C.P. Peacock
The style, geometry and distribution of fractures within reservoir rocks can be controlled by numerous factors, including: rock characteristics and diagenesis (lithology, sedimentary structures, bed thickness, mechanical stratigraphy, the mechanics of bedding planes); structural geology (tectonic setting, palaeostresses, subsidence and uplift history, proximity to faults, position in a fold, timing of structural events, mineralisation, the angle between bedding and fractures); and present-day factors, such as orientations of in situ stresses, fluid pressure, perturbation of in situ stresses and depth. The relative timing of events plays a crucial role in determining the geometry and distribution of fractures. For example, open fractures are commonly clustered around faults if the open fractures and faults formed at the same time, but clustering does not tend to occur if the open fractures pre-date or post-date the faults. Understanding these factors requires traditional geological skills, including the analysis of one-dimensional (line-sampling) data from core, borehole images and exposed analogues. This paper reviews the factors that control fractures within reservoir rocks and discusses methods to assess those controls. Examples are presented from Mesozoic limestones in southern England. It is shown that traditional geological skills are of vital importance in determining the rock characteristics, structural and present-day factors that control fractures. [source]


FAULT-RELATED SOLUTION CLEAVAGE IN EXPOSED CARBONATE RESERVOIR ROCKS IN THE SOUTHERN APENNINES, ITALY

JOURNAL OF PETROLEUM GEOLOGY, Issue 2 2001
A. Billi
The deformation associated with a number of kilometre-scale strike-slip fault zones which cut through outcropping carbonate rocks in the Southern Apennines was investigated at regional and outcrop scales. These faults trend roughly east-west and were studied at the Gargano Promontory on the Adriatic Coast (in the Apulian foreland) and in the Matese Mountains, about 120 km to the west (within the Apenninic fold-and-thrust belt). The fault zones are 200,300 m wide and typically comprise a core surrounded by a damage zone. Within fault cores, fault rocks (gouges and cataclasites) typically occur along master slip planes; in damage zones, secondary slip planes and solution cleavage are the most important planar discontinuities. The protolith carbonates surrounding the fault zone at Gargano show little deformation, but they are fractured in the Matese Mountains as a result of an earlier thrust phase. Cleavage surfaces in the damage zone of the studied faults are interpreted to be fault-propagation structures. Our field data indicate that cleavage-fault intersection lines are parallel to the normals of fault slip-vectors. The angle between a fault plane and the associated cleavage was found to be fairly constant (c. 40") at different scales of observation. Finally, the spacing of the solution cleavage surfaces appeared in general to be regular (with a mean of about 22 mm), although it was found to decrease slightly near a fault plane. These results are intended to provide a basis for predicting the architecture of fault zones in buried carbonate reservoirs using seismic reflection and borehole data. [source]


NEOGENE TECTONIC HISTORY OF THE SUB-BIBANIC AND M'SILA BASINS, NORTHERN ALGERIA: IMPLICATIONS FOR HYDROCARBON POTENTIAL

JOURNAL OF PETROLEUM GEOLOGY, Issue 2 2007
H. L. Kheidri
The southern Bibans region in northern Algeria is located in the external zone of the Tell fold-and-thrust belt. Field observations in this area together with seismic data integrated with previous studies provide evidence for a number of Tertiary deformation phases. Late Eocene Atlassic deformation was followed by Oligocene (?)-Aquitanian-Burdigalian compression, which was associated with the development of a foreland basin in front of a southerly-propagating thrust system. Gravity-driven emplacement of the Tellian nappes over the basin margin probably occurred during the Langhian-Serravallian-Tortonian. The Hodna Mountains structural culmination developed during the Miocene-Pliocene. Analysis of brittle structures points to continued north-south shortening during the Neogene, consistent with convergence between the African and Eurasian Plates. The unconformably underlying Mesozoic-Cenozoic autochthonous sequence in this area contains two potential source rock intervals: Cenomanian-Turonian and Eocene. Reservoir rocks include Lower Cretaceous siliciclastics and Upper Cretaceous to Palaeogene carbonates. Structural style has controlled trap types. Thus traps in the Tell fold-and-thrust belt are associated with folds, whereas structural traps in the Hodna area are associated with reactivated normal faults. In the latter area, there is also some evidence for base-Miocene stratigraphic traps. [source]


HYDROTHERMALLY FLUORITIZED ORDOVICIAN CARBONATES AS RESERVOIR ROCKS IN THE TAZHONG AREA, CENTRALTARIM BASIN, NW CHINA

JOURNAL OF PETROLEUM GEOLOGY, Issue 1 2006
Zhijun Jin
Reservoir rocks at the Tazhong 45 oil pool, central Tarim Basin, consist of fluoritized carbonate strata of Middle - Late Ordovician age. Petrological observations indicate that the fluorite replaces calcite. Several other hydrothermal minerals including pyrite, quartz, sphalerite and chlorite accompany the fluorite. Two generations of fluid inclusions are present in the fluorite. Homogenization temperatures (Th) for primary inclusions are mostly between 260°C and 310°C and represent the temperature of the hydrothermal fluid responsible for fluorite precipitation. Th for secondary inclusions range from 100°C to 130°C, and represent the hydrocarbon charging temperature as shown by the presence of hydrocarbons trapped in some secondary inclusions. The mineral assemblage and the homogenization temperatures of the primary fluid inclusions indicate that the precipitation of fluorite is related to hydrothermal activity in the Tazhong area. Strontium isotope analyses imply that the hydrothermal fluids responsible for fluorite precipitation are related to late-stage magmatic activity, and felsic magmas were generated by mixing of mafic magma and crustal materials during the Permian. Theoretical calculations show that the molecular volume of a carbonate rock decreases by 33.5% when calcite is replaced by fluorite, and the volume shrinkage can greatly enhance reservoir porosity by the formation of abundant intercrystalline pores. Fluoritization has thus greatly enhanced the reservoir quality of Ordovician carbonates in the Tazhong 45 area, so that the fluorite and limestone host rocks have become an efficient hydrocarbon reservoir. According to the modelled burial and thermal history of the Tazhong 45 well, and the homogenization temperatures of secondary fluid inclusions in the fluorite, hydrocarbon charging at the Tazhong 45 reservoir took place in the Tertiary. [source]


The upper continental crust, an aquifer and its fluid: hydaulic and chemical data from 4 km depth in fractured crystalline basement rocks at the KTB test site

GEOFLUIDS (ELECTRONIC), Issue 1 2005
I. STOBER
Abstract Detailed information on the hydrogeologic and hydraulic properties of the deeper parts of the upper continental crust is scarce. The pilot hole of the deep research drillhole (KTB) in crystalline basement of central Germany provided access to the crust for an exceptional pumping experiment of 1-year duration. The hydraulic properties of fractured crystalline rocks at 4 km depth were derived from the well test and a total of 23100 m3 of saline fluid was pumped from the crustal reservoir. The experiment shows that the water-saturated fracture pore space of the brittle upper crust is highly connected, hence, the continental upper crust is an aquifer. The pressure,time data from the well tests showed three distinct flow periods: the first period relates to wellbore storage and skin effects, the second flow period shows the typical characteristics of the homogeneous isotropic basement rock aquifer and the third flow period relates to the influence of a distant hydraulic border, probably an effect of the Franconian lineament, a steep dipping major thrust fault known from surface geology. The data analysis provided a transmissivity of the pumped aquifer T = 6.1 × 10,6 m2 sec,1, the corresponding hydraulic conductivity (permeability) is K = 4.07 × 10,8 m sec,1 and the computed storage coefficient (storativity) of the aquifer of about S = 5 × 10,6. This unexpected high permeability of the continental upper crust is well within the conditions of possible advective flow. The average flow porosity of the fractured basement aquifer is 0.6,0.7% and this range can be taken as a representative and characteristic values for the continental upper crust in general. The chemical composition of the pumped fluid was nearly constant during the 1-year test. The total of dissolved solids amounts to 62 g l,1 and comprise mainly a mixture of CaCl2 and NaCl; all other dissolved components amount to about 2 g l,1. The cation proportions of the fluid (XCa approximately 0.6) reflects the mineralogical composition of the reservoir rock and the high salinity results from desiccation (H2O-loss) due to the formation of abundant hydrate minerals during water,rock interaction. The constant fluid composition suggests that the fluid has been pumped from a rather homogeneous reservoir lithology dominated by metagabbros and amphibolites containing abundant Ca-rich plagioclase. [source]


Processing, modelling and predicting time-lapse effects of overpressured fluid-injection in a fractured reservoir

GEOPHYSICAL JOURNAL INTERNATIONAL, Issue 2 2002
Erika Angerer
Summary Time-lapse seismology is important for monitoring subsurface pressure changes and fluid movements in producing hydrocarbon reservoirs. We analyse two 4-D, 3C onshore surveys from Vacuum Field, New Mexico, USA, where the reservoir of interest is a fractured dolomite. In Phase VI, a time-lapse survey was acquired before and after a pilot tertiary-recovery programme of overpressured CO2 injection, which altered the fluid composition and the pore-fluid pressure. Phase VII was a similar time-lapse survey in the same location but with a different lower-pressure injection regime. Applying a processing sequence to the Phase VI data preserving normal-incidence shear-wave anisotropy (time-delays and polarization) and maximizing repeatability, interval-time analysis of the reservoir interval shows a significant 10 per cent change in shear-wave velocity anisotropy and 3 per cent decrease in the P -wave interval velocities. A 1-D model incorporating both saturation and pressure changes is matched to the data. The saturation changes have little effect on the seismic velocities. There are two main causes of the time-lapse changes. Any change in pore-fluid pressures modifies crack aspect ratios. Additionally, when there are overpressures, as there are in Phase VI, there is a 90° change in maximum impedance directions, and the leading faster split shear wave, instead of being parallel to the crack face as it is for low pore-fluid pressures, becomes orthogonal to the crack face. The anisotropic poro-elasticity (APE) model of the evolution of microcracked rock, calculates the evolution of cracked rock to changing conditions. APE modelling shows that at high overburden pressures only nearly vertical cracks, to which normal incidence P waves are less sensitive than S waves, remain open as the pore-fluid pressure increases. APE modelling matches the observed time-lapse effects almost exactly demonstrating that shear-wave anisotropy is a highly sensitive diagnostic of pore-fluid pressure changes in fractured reservoirs. In this comparatively limited analysis, APE modelling of fluid-injection at known pressure correctly predicted the changes in seismic response, particularly the shear-wave splitting, induced by the high-pressure CO2 injection. In the Phase VII survey, APE modelling also successfully predicted the response to the lower-pressure injection using the same Phase VI model of the cracked reservoir. The underlying reason for this remarkable predictability of fluid-saturated reservoir rocks is the critical nature and high crack density of the fluid-saturated cracks and microcracks in the reservoir rock, which makes cracked reservoirs critical systems. [source]


An approach to combined rock physics and seismic modelling of fluid substitution effects

GEOPHYSICAL PROSPECTING, Issue 2 2002
Tor Arne Johansen
ABSTRACT The aim of seismic reservoir monitoring is to map the spatial and temporal distributions and contact interfaces of various hydrocarbon fluids and water within a reservoir rock. During the production of hydrocarbons, the fluids produced are generally displaced by an injection fluid. We discuss possible seismic effects which may occur when the pore volume contains two or more fluids. In particular, we investigate the effect of immiscible pore fluids, i.e. when the pore fluids occupy different parts of the pore volume. The modelling of seismic velocities is performed using a differential effective-medium theory in which the various pore fluids are allowed to occupy the pore space in different ways. The P-wave velocity is seen to depend strongly on the bulk modulus of the pore fluids in the most compliant (low aspect ratio) pores. Various scenarios of the microscopic fluid distribution across a gas,oil contact (GOC) zone have been designed, and the corresponding seismic properties modelled. Such GOC transition zones generally give diffuse reflection regions instead of the typical distinct GOC interface. Hence, such transition zones generally should be modelled by finite-difference or finite-element techniques. We have combined rock physics modelling and seismic modelling to simulate the seismic responses of some gas,oil zones, applying various fluid-distribution models. The seismic responses may vary both in the reflection time, amplitude and phase characteristics. Our results indicate that when performing a reservoir monitoring experiment, erroneous conclusions about a GOC movement may be drawn if the microscopic fluid-distribution effects are neglected. [source]


Snap-off of a liquid drop immersed in another liquid flowing through a constricted capillary

AICHE JOURNAL, Issue 8 2009
T. J. Peña
Abstract Emulsions are encountered at different stages of oil production processes, often impacting many aspects of oilfield operations. Emulsions may form as oil and water come in contact inside the reservoir rock, valves, pumps, and other equipments. Snap-off is a possible mechanism to explain emulsion formation in two-phase flow in porous media. Quartz capillary tubes with a constriction (pore neck) served to analyze snap-off of long ("infinite") oil droplets as a function of capillary number and oil-water viscosity ratio. The flow of large oil drops through the constriction and the drop break-up process were visualized using an optical microscope. Snap-off occurrence was mapped as a function of flow parameters. High oil viscosity suppresses the breakup process, whereas snap-up was always observed at low dispersed-phase viscosity. At moderate viscosity oil/water ratio, snap-off was observed only at low capillary number. Mechanistic explanations based on competing forces in the liquid phases were proposed. © 2009 American Institute of Chemical Engineers AIChE J, 2009 [source]


INVESTIGATION OF ELASTIC INVERSION ATTRIBUTES USING THE EXPANSIBLE CLAY MODEL FOR WATER SATURATION

JOURNAL OF PETROLEUM GEOLOGY, Issue 2 2009
J. O. Ugbo
Quantitative X-ray diffraction has been used to characterize water saturation levels in complex shaly sand reservoirs (i.e. shaly sands with infrequent carbonates and minor proportions of iron-rich minerals such as pyrite and siderite). The results led to the design of a total expansible clay model for water saturation, which is similar in form to the Dual Water model except that the excess effect of the clay minerals has been accounted for by a volume-conductivity relationship, rather than one of the usual volume-porosity translations, effectively reducing the uncertainties in estimating water saturation. Given the ambiguities associated with predicting these petrophysical properties from data on rock properties, such as mineralogy, an investigation of the relationship of estimated water saturation based on the total expansible clay model to independently determined rock properties was undertaken using well log inversion and forward modelling techniques. The results show that there is consistency in the relationship between water saturation estimates made from the total expansible clay model and known elastic parameters such as primary and shear-wave sonic velocity (Vp, Vs), bulk density (,b) and impedance (I), when the Raymer-Gardner-Hunt model is used. Use of the Raymer-Gardner-Hunt model to reconstruct the required rock-physics relationship avoids the classic limitation of the more advanced Gassman model, which assumes that the dry shear modulus is equivalent to the wet shear modulus (,dry=,wet). The present work raises further questions on the application of the Voigt-Reuss-Hill (VRH) limits, or the Hashin Shtrikman bounds for averaging the effective shear modulus of the dry matrix in complex shaly sand reservoirs, where a two-mineral matrix is normally assumed. The study shows the inapplicability of the VRH or Hashin-Shtrikman averaging techniques but provides a minor adjustment to the averaging that solves the problems faced in reconstructing the relationships between directly measured elastic properties and derived petrophysical properties for this type of reservoir rock. [source]


SEISMIC FACIES ANALYSIS BASED ON 3D MULTI-ATTRIBUTE VOLUME CLASSIFICATION, DARIYAN FORMATION, SE PERSIAN GULF

JOURNAL OF PETROLEUM GEOLOGY, Issue 2 2006
P. Farzadi
Interpretation of recently acquired 3D seismic data from the adjacent Sirri C and D oilfields in the SE Persian Gulf indicates that a 3D interpretation of seismic facies is crucial to resolve the internal stratal geometries of the Aptian Dariyan Formation. This carbonate formation passes southward into the Shu'aiba Formation, a prolific reservoir rock of similar facies in the UAE. Lack of exposures and limited cored intervals have forced reliance on the seismic data for evidence of the depositional environment and the internal architecture of potential reservoir rocks. The progradational nature of the Dariyan Formation and the occurrence of carbonate build-ups within it make this stratal geometry complex. The complex internal heterogeneity of the build-ups and presence of seismic noise make mapping of the build-ups in 3D space using conventional seismic interpretation tools difficult, despite the availability of high-quality 3D seismic data covering the area. The high quality seismic and limited well data from this field is one of the few datasets of this kind presented in the literature. A procedure for the hierarchical multi-attribute analysis of seismic facies using Paradigm's Seis Facies software is used in this study to provide a 3D interpretation of the stratal patterns. Principal component analysis reduces the noise and redundant data by representing the main data variances as a few vector components in a transformed coordinate system. Cluster analysis is performed using those components which have the greatest contribution to the maximum spread of the data variability. Six seismic attribute volumes are used in this study and the result is a single 3D classified volume. Important new information obtained from within the Dariyan Formation gives new insights into its stratigraphic distribution and internal variability. This method of processing seismic data is a step towards exploring for subtle stratigraphic traps in the study area, and may help to identify exploration targets. [source]


A REVIEW OF GEOLOGICAL DATA THAT CONFLICT WITH THE PARADIGM OF CATAGENIC GENERATION AND MIGRATION OF OIL

JOURNAL OF PETROLEUM GEOLOGY, Issue 3 2005
H. Hugh Wilson
The majority of petroleum geologists today agree that the complex problems that surround the origin, generation, migration and accumulation of hydrocarbons can be resolved by accepting the geochemical conclusion that the process originates by catagenic generation in deeply-buried organically-rich source rocks. These limited source rock intervals are believed to expel hydrocarbons when they reach organic maturity in oil kitchens. The expelled oil and gas then follow migration pathways to traps at shallower levels. However, there are major geological obstacles that cast doubt upon this interpretation. The restriction of the source rock to a few organically rich levels in a basin forces the conclusion that the basin plumbing system is leaky and allows secondary horizontal and vertical migration through great thicknesses of consolidated sedimentary rocks in which there are numerous permeability barriers that are known to effectively prevent hydrocarbon escape from traps. The sourcing of lenticular traps points to the enclosing impermeable envelope as the logical origin of the trapped hydrocarbons. The lynch-pin of the catagenic theory of hydrocarbon origin is the expulsion mechanism from deeply-buried consolidated source rock under high confining pressures. This mechanism is not understood and is termed an "enigma". Assuming that expulsion does occur, the pathways taken by the hydrocarbons to waiting traps can be ascertained by computer modelling of the basin. However, subsurface and field geological support for purported migration pathways has yet to be provided. Many oilfield studies have shown that oil and gas are preferentially trapped in synchronous highs that were formed during, or very shortly after, the deposition of the charged reservoir. An unresolved problem is how catagenically generated hydrocarbons, expelled during a long-drawn-out maturation period, can have filled synchronous highs but have avoided later traps along the assumed migration pathways. From many oilfield studies, it has also been shown that the presence of hydrocarbons inhibits diagenesis and compaction of the reservoir rock. This "Füchtbauer effect" points to not only the early charging of clastic and carbonate reservoirs, but also to the development of permeability barriers below the early-formed accumulations. These barriers would prevent later hydrocarbon additions during the supposed extended period of expulsion from an oil kitchen. Early-formed traps that have been sealed diagenetically will retain their charge even if the trap is opened by later structural tilting. Diagenetic traps have been discovered in clastic and carbonate provinces but their recognition as viable exploration targets is discouraged by present-day assumptions of late hydrocarbon generation and a leaky basin plumbing system. Because there are so many geological realities that cast doubt upon the assumptions that devolve from the paradigm of catagenic generation, the alternative concept of early biogenic generation and accumulation of immature oil, with in-reservoir cracking during burial, is again worthy of serious consideration. This concept envisages hydrocarbon generation by bacterial activity in many anoxic environments and the charging of synchronous highs from adjacent sources. The resolution of the fundamental problem of hydrocarbon generation and accumulation, which is critical to exploration strategies, should be sought in the light of a thorough knowledge of the geologic factors involved, rather than by computer modelling which may be guided by questionable geochemical assumptions. [source]


NEURAL NETWORK PREDICTION OF PERMEABILITY IN THE EL GARIA FORMATION, ASHTART OILFIELD, OFFSHORE TUNISIA

JOURNAL OF PETROLEUM GEOLOGY, Issue 4 2001
J.H. Ligtenberg
The Lower Eocene El Garia Formation forms the reservoir rock at the Ashtart oilfield, offshore Tunisia. It comprises a thick package of mainly nummulitic packstones and grainstones with variable reservoir quality. Although porosity is moderate to high, permeability is often poor to fair with some high permeability streaks. The aim of this study was to establish relationships between log-derived data and core data, and to apply these relationships in a predictive sense to uncored intervals. An initial objective was to predict from measured logs and core data the limestone depositional texture (as indicated by the Dunham classification), as well as porosity and permeability. A total of nine wells with complete logging suites, multiple cored intervals with core plug measurements together with detailed core interpretations were available. We used a fully-connected Multi-Layer-Perceptron network (a type of neural network) to establish possible non-linear relationships. Detailed analyses revealed that no relationship exists between log response and limestone texture (Dunham class). The initial idea to predict Dunham class, and subsequently to use the classification results to predict permeability, could not therefore be pursued. However, further analyses revealed that it was feasible to predict permeability without using the depositional fabric, but using a combination of wireline logs and measured core porosity. Careful preparation of the training set for the neural network proved to be very important. Early experiments showed that low to fair permeability (1,35 mD) could be predicted with confidence, but that the network failed to predict the high permeability streaks. "Balancing " the data set solved this problem. Balancing is a technique in which the training set is increased by adding more examples to the under-sampled part of the data space. Examples are created by random selection from the training set and white noise is added. After balancing, the neural network's performance improved significantly. Testing the neural network on two wells indicated that this method is capable of predicting the entire range of permeability with confidence. [source]


A REVIEW OF EOCENE NUMMULITE ACCUMULATIONS: STRUCTURE, FORMATION AND RESERVOIR POTENTIAL

JOURNAL OF PETROLEUM GEOLOGY, Issue 1 2001
A. Racey
Eocene nummulite accumulations, also referred to as nummullte "banks", form Important hydrocarbon reservoirs in Tunisia and Libya and may constitute exploration targets in other parts of North Africa, the Mediterranean and the Middle East. Porosities commonly average 10,20% and permeabilities 10,50md. Foraminifera of the genus Nummulites may comprise up to 98% of the bioclasts in these carbonate reservoirs, although only one or two species may be present. The absence of associated fauna is generally taken to indicate an oligotrophic depositional environment. In this paper, the palaeoecology of the genus Nummulites is discussed together with depositional models for two nummulitic carbonate reservoirs , the Middle Eocene Seeb Limestone of Oman and the Early Eocene El Garia/Jdeir Formation of Tunisia and Libya. The El Garia and Seeb Limestone Formations were deposited in ramp settings, and comprise a series of amalgamated sheets or low-relief banks. In the Hasdrubal field offshore Tunisia, where the El Garia Formation constitutes the reservoir rock, most of the nummulites have been redeposited from shallow into deeper waters whilst in the Bourri field (offshore Libya) they occur as an in situ "bank". Nummulite accumulations often show evidence that both physical reworking (scouring, winnowing and imbrication) and biological processes (reproduction strategies and bioturbation) have influenced their formation. A general model is outlined for discriminating between physically and ecologically produced biofabrics, and the implications for reservoir quality are discussed. [source]


Oil and Gas Accumulation in the Foreland Basins, Central and Western China

ACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 2 2010
Yan SONG
Abstract: Foreland basin represents one of the most important hydrocarbon habitats in central and western China. To distinguish these foreland basins regionally, and according to the need of petroleum exploration and favorable exploration areas, the foreland basins in central and western China can be divided into three structural types: superimposed, retrogressive and reformative foreland basin (or thrust belt), each with distinctive petroleum system characteristics in their petroleum system components (such as the source rock, reservoir rock, caprock, time of oil and gas accumulation, the remolding of oil/gas reservoir after accumulation, and the favorable exploration area, etc.). The superimposed type foreland basins, as exemplified by the Kuqa Depression of the Tarim Basin, characterized by two stages of early and late foreland basin development, typically contain at least two hydrocarbon source beds, one deposited in the early foreland development and another in the later fault-trough lake stage. Hydrocarbon accumulations in this type of foreland basin often occur in multiple stages of the basin development, though most of the highly productive pools were formed during the late stage of hydrocarbon migration and entrapment (Himalayan period). This is in sharp contrast to the retrogressive foreland basins (only developing foreland basin during the Permian to Triassic) such as the western Sichuan Basin, where prolific hydrocarbon source rocks are associated with sediments deposited during the early stages of the foreland basin development. As a result, hydrocarbon accumulations in retrogressive foreland basins occur mainly in the early stage of basin evolution. The reformative foreland basins (only developing foreland basin during the Himalayan period) such as the northern Qaidam Basin, in contrast, contain organic-rich, lacustrine source rocks deposited only in fault-trough lake basins occurring prior to the reformative foreland development during the late Cenozoic, with hydrocarbon accumulations taking place relatively late (Himalayan period). Therefore, the ultimate hydrocarbon potentials in the three types of foreland basins are largely determined by the extent of spatial and temporal matching among the thrust belts, hydrocarbon source kitchens, and regional and local caprocks. [source]


Diagenesis and Restructuring Mechanism of Oil and Gas Reservoir in the Marine Carbonate Formation, Northeastern Sichuan: A Case Study of the Puguang Gas Reservoir

ACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 6 2009
DU Chunguo
Abstract: Based on the technology of balanced cross-section and physical simulation experiments associated with natural gas geochemical characteristic analyses, core and thin section observations, it has been proven that the Puguang gas reservoir has experienced two periods of diagenesis and restructuring since the Late Indo-Chinese epoch. One is the fluid transfer controlled by the tectonic movement and the other is geochemical reconstruction controlled by thermochemical sulfate reduction (TSR). The middle Yanshan epoch was the main period that the Puguang gas reservoir experienced the geochemical reaction of TSR. TSR can recreate the fluid in the gas reservoir, which makes the gas drying index higher and carbon isotope heavier because C2+ (ethane and heavy hydrocarbon) and 12C (carbon 12 isotope) is first consumed relative to CH4 and 13C (carbon 13 isotope). However, the reciprocity between fluid regarding TSR (hydrocarbon, sulfureted hydrogen (H2S), and water) and reservoir rock results in reservoir rock erosion and anhydrite alteration, which increases porosity in reservoir, thereby improving the petrophysical properties. Superimposed by later tectonic movement, the fluid in Puguang reservoir has twice experienced adjustment, one in the late Yanshan epoch to the early Himalayan epoch and the other time in late Himalayan epoch, after which Puguang gas reservoir is finally developed. [source]


Real-time mud gas logging and sampling during drilling

GEOFLUIDS (ELECTRONIC), Issue 3 2006
J. ERZINGER
Abstract Continuous mud gas loggings during drilling as well as offline mud gas sampling are standard procedures in oil and gas operations, where they are used to test reservoir rocks for hydrocarbons while drilling. Our research group has developed real-time mud gas monitoring techniques for scientific drilling in non-hydrocarbon formations mainly to sample and study the composition of crustal gases. We describe in detail this technique and provide examples for the evaluation of the continuous gas logs, which are not always easy to interpret. Hydrocarbons, helium, radon and with limitations carbon dioxide and hydrogen are the most suitable gases for the detection of fluid-bearing horizons, shear zones, open fractures, sections of enhanced permeability and permafrost methane hydrate occurrences. Off-site isotope studies on mud gas samples helped reveal the origin and evolution of deep-seated crustal fluids. [source]


Full waveform inversion of seismic waves reflected in a stratified porous medium

GEOPHYSICAL JOURNAL INTERNATIONAL, Issue 3 2010
Louis De Barros
SUMMARY In reservoir geophysics applications, seismic imaging techniques are expected to provide as much information as possible on fluid-filled reservoir rocks. Since seismograms are, to some degree, sensitive to the mechanical parameters and fluid properties of porous media, inversion methods can be devised to directly estimate these quantities from the waveforms obtained in seismic reflection experiments. An inversion algorithm that uses a generalized least-squares, quasi-Newton approach is described to determine the porosity, permeability, interstitial fluid properties and mechanical parameters of porous media. The proposed algorithm proceeds by iteratively minimizing a misfit function between observed data and synthetic wavefields computed with the Biot theory. Simple models consisting of plane-layered, fluid-saturated and poro-elastic media are considered to demonstrate the concept and evaluate the performance of such a full waveform inversion scheme. Numerical experiments show that, when applied to synthetic data, the inversion procedure can accurately reconstruct the vertical distribution of a single model parameter, if all other parameters are perfectly known. However, the coupling between some of the model parameters does not permit the reconstruction of several model parameters at the same time. To get around this problem, we consider composite parameters defined from the original model properties and from a priori information, such as the fluid saturation rate or the lithology, to reduce the number of unknowns. Another possibility is to apply this inversion algorithm to time-lapse surveys carried out for fluid substitution problems, such as CO2 injection, since in this case only a few parameters may vary as a function of time. We define a two-step differential inversion approach which allows us to reconstruct the fluid saturation rate in reservoir layers, even though the medium properties are poorly known. [source]


Processing, modelling and predicting time-lapse effects of overpressured fluid-injection in a fractured reservoir

GEOPHYSICAL JOURNAL INTERNATIONAL, Issue 2 2002
Erika Angerer
Summary Time-lapse seismology is important for monitoring subsurface pressure changes and fluid movements in producing hydrocarbon reservoirs. We analyse two 4-D, 3C onshore surveys from Vacuum Field, New Mexico, USA, where the reservoir of interest is a fractured dolomite. In Phase VI, a time-lapse survey was acquired before and after a pilot tertiary-recovery programme of overpressured CO2 injection, which altered the fluid composition and the pore-fluid pressure. Phase VII was a similar time-lapse survey in the same location but with a different lower-pressure injection regime. Applying a processing sequence to the Phase VI data preserving normal-incidence shear-wave anisotropy (time-delays and polarization) and maximizing repeatability, interval-time analysis of the reservoir interval shows a significant 10 per cent change in shear-wave velocity anisotropy and 3 per cent decrease in the P -wave interval velocities. A 1-D model incorporating both saturation and pressure changes is matched to the data. The saturation changes have little effect on the seismic velocities. There are two main causes of the time-lapse changes. Any change in pore-fluid pressures modifies crack aspect ratios. Additionally, when there are overpressures, as there are in Phase VI, there is a 90° change in maximum impedance directions, and the leading faster split shear wave, instead of being parallel to the crack face as it is for low pore-fluid pressures, becomes orthogonal to the crack face. The anisotropic poro-elasticity (APE) model of the evolution of microcracked rock, calculates the evolution of cracked rock to changing conditions. APE modelling shows that at high overburden pressures only nearly vertical cracks, to which normal incidence P waves are less sensitive than S waves, remain open as the pore-fluid pressure increases. APE modelling matches the observed time-lapse effects almost exactly demonstrating that shear-wave anisotropy is a highly sensitive diagnostic of pore-fluid pressure changes in fractured reservoirs. In this comparatively limited analysis, APE modelling of fluid-injection at known pressure correctly predicted the changes in seismic response, particularly the shear-wave splitting, induced by the high-pressure CO2 injection. In the Phase VII survey, APE modelling also successfully predicted the response to the lower-pressure injection using the same Phase VI model of the cracked reservoir. The underlying reason for this remarkable predictability of fluid-saturated reservoir rocks is the critical nature and high crack density of the fluid-saturated cracks and microcracks in the reservoir rock, which makes cracked reservoirs critical systems. [source]


Improved understanding of velocity,saturation relationships using 4D computer-tomography acoustic measurements

GEOPHYSICAL PROSPECTING, Issue 2 2005
K. Monsen
ABSTRACT A recently developed laboratory method allows for simultaneous imaging of fluid distribution and measurements of acoustic-wave velocities during flooding experiments. Using a specially developed acoustic sample holder that combines high pressure capacity with good transparency for X-rays, it becomes possible to investigate relationships between velocity and fluid saturation at reservoir stress levels. High-resolution 3D images can be constructed from thin slices of cross-sectional computer-tomography scans (CT scans) covering the entire rock-core volume, and from imaging the distribution of fluid at different saturation levels. The X-ray imaging clearly adds a new dimension to rock-physics measurements; it can be used in the explanation of variations in measured velocities from core-scale heterogeneities. Computer tomography gives a detailed visualization of density regimes in reservoir rocks within a core. This allows an examination of the interior of core samples, revealing inhomogeneities, porosity and fluid distribution. This mapping will not only lead to an explanation of acoustic-velocity measurements; it may also contribute to an increased understanding of the fluid-flow process and gas/liquid mixing mechanisms in rock. Immiscible and miscible flow in core plugs can be mapped simultaneously with acoustic measurements. The effects of core heterogeneity and experimentally introduced effects can be separated, to clarify the validity of measured velocity relationships. [source]


DOLOMITIZATION AND ANHYDRITE PRECIPITATION IN PERMO-TRIASSIC CARBONATES AT THE SOUTH PARS GASFIELD, OFFSHORE IRAN: CONTROLS ON RESERVOIR QUALITY

JOURNAL OF PETROLEUM GEOLOGY, Issue 1 2010
H. Rahimpour-Bonab
Dolomitization and related anhydrite cementation can complicate the characterization of carbonate reservoirs. Both processes have affected the Permo-Triassic Upper Dalan , Kangan carbonates, the main reservoir at the South Pars gasfield, offshore Iran. The carbonates were deposited in a shallow-marine ramp or epeiric platform and, according to previous studies, underwent intense near-surface diagenesis and minor burial modification. Detailed petrographical and geochemical analyses indicate that dolomitization and anhydrite precipitation can be explained in terms of the sabkha/seepage-reflux models. The early dolomites then re-equilibrated or re-crystallized in a shallow burial setting. Evaluation of poroperm values in different reservoir intervals indicates that replacive dolomitization in the absence of anhydrite precipitation or with only patchy anhydrite has enhanced the reservoir quality. Where anhydrite cement is pervasive and has plugged the rock fabric, poroperm values are significantly decreased. As emphasized in previous studies and confirmed here, dolomitization and anhydrite cementation, together with original facies type, are the major factors controlling reservoir quality in the Dalan , Kangan carbonates at South Pars. When associated with minor anhydrite cementation, replacive dolomitization has enhanced reservoir quality by increasing permeability. However, porosity in fabric-retentive dolomite was apparently inherited from the precursor rock and therefore reflects the original depositional environment. Low-temperature dolomitization is commonly fabric-selective and partially fabric-retentive. Whole rock stable isotope thermometry indicates that fabric-destructive dolomites in the reservoir rocks formed at temperatures above 22°C, whereas fabric-retentive dolomites and associated anhydrites formed in surface and near-surface conditions. Fabric-destructive dolomite or dolomite neomorphism post-date fabric-retentive dolomite and continued to form in deep burial conditions (,1400m). These observations may explain why fabric-retentive dolomite and anhydrite fabrics are traversed by stylolites. [source]


PETROPHYSICAL CHARACTERISTICS OF SOURCE AND RESERVOIR ROCKS IN THE HISTRIA BASIN, WESTERN BLACK SEA

JOURNAL OF PETROLEUM GEOLOGY, Issue 4 2009
C. Cranganu
The petroleum system in the Histria Basin, Western Black Sea, includes Oligocene source rocks and Upper Cretaceous , Eocene reservoir rocks. Here we report on the petrophysical characteristics of these source and reservoir rocks using mercury intrusion porosimetry data from 14 core samples collected from five wells drilled on the East Lebada, West Lebada and Pescarus structures. Samples were in general dominated by carbonate lithologies with minor shales. Petrophysical parameters analyzed were: median pore-throat radius, average pore-throat radius, apparent porosity, pore-throat size distribution, pore-throat type, pore-throat sorting, maximum threshold entry radius, pore-throat radius at 35% mercury saturation (R35), and air permeability. Reservoir rock quality was estimated using a permeability / porosity / pore-throat type plot. The Oligocene samples showed little petrophysical variation. Samples were relatively homogenous and had the same pore-throat type (nano), were well sorted, had unimodal pore-throat distribution (suggesting the existence of a single fluid phase), had similar values for median and average pore-throat radius, and similar values for R35 and maximum threshold entry radius. Upper Cretaceous , Eocene samples were more heterogeneous in terms of petrophysical properties, and reservoir quality was in general higher than in the Oligocene interval. Average porosity and calculated air-permeability values were 18.4% and 0.37 mD, respectively for Upper Cretaceous samples; and 11.8% and 27.11 mD, respectively for Eocene samples. A case study of Oligocene and Cretaceous , Eocene samples from well West Lebada 817 is presented. This paper represents the first petrophysical study of source and reservoir rocks in the Histria Basin, Western Black Sea. The results will help to establish the links between petrophysical characteristics, age and depositional environment for source and reservoir rocks in other basins bordering the Black Sea. [source]


A FUZZY LOGIC APPROACH TO ESTIMATING HYDRAULIC FLOW UNITS FROM WELL LOG DATA: A CASE STUDY FROM THE AHWAZ OILFIELD, SOUTH IRAN

JOURNAL OF PETROLEUM GEOLOGY, Issue 1 2009
A. Kadkhodaie-Ilkhchi
Porosity-permeability relationships in the framework of hydraulic flow units can be used to characterize heterogeneous reservoir rocks. Porosity is a volumetric parameter whereas permeability is a measure of a rock's flow properties and depends on pore distribution and connectivity. Thus zonation of a reservoir using flow zone indicators and the identification of flow units can be used to evaluate reservoir quality based on porosity-permeability relationships. In the present study, we attempt to make a quantitative correlation between flow units and well log responses using fuzzy logic in the mixed carbonate-clastic Asmari Formation at the Ahwaz oilfield, South Iran. A hybrid neuro-fuzzy approach was used to verify the results of fuzzy modelling. For this purpose, well log and core data from three wells at Ahwaz were used to make an intelligent formulation between core-derived flow units and well log responses. Data from a separate well was used for evaluation and validation of the results. The results of this study demonstrate that there is a good agreement between core-derived and fuzzy-logic derived flow units. Fuzzy logic was successful in modelling flow units from well logs at well locations for which no core data was available. [source]


RESERVOIR POTENTIAL OF A LACUSTRINE MIXED CARBONATE / SILICICLASTIC GAS RESERVOIR: THE LOWER TRIASSIC ROGENSTEIN IN THE NETHERLANDS

JOURNAL OF PETROLEUM GEOLOGY, Issue 1 2008
D. Palermo
The Lower Triassic Rogenstein Member of the Buntsandstein Formation produces gas at the De Wijk and Wanneperveen fields, NE Netherlands and consists mainly of claystones with intercalated oolitic limestone beds. The excellent reservoir properties of the oolites (,= 20-30%; k = 5-4000 mD) are predominantly controlled by depositional facies. Oolitic limestones are interpreted as the storm and wave deposits of a shallow, desert lake located in the Central European Buntsandstein Basin. The vertical sequence of lithofacies in the Rogenstein Member indicates cyclic changes of relative lake level. The reservoir rock is vertically arranged in a three-fold hierarchy of cycles, recognised both in cores and wireline logs. These cycles are a key to understanding the distribution of reservoir facies, and are used as the basis for a high-resolution sequence stratigraphic correlation of the reservoir units. Slight regional-scale thickness variations of the Rogenstein Member (in the order of tens of metres) are interpreted as the effects of differential subsidence associated with the inherited Palaeozoic structural framework. The depositional basin can be subdivided into subtle palaeo-highs and -lows which controlled facies distribution during Rogenstein deposition. Oolitic limestones show their greatest lateral extent and thickest development in the Middle Rogenstein during large-scale maximum flooding. Potential reservoir rocks (decimetre to metres thick) are present in the NE Netherlands, in particular in the Lauwerszee Trough and the Lower Saxony Basin, where abundant gas shows of 200 - 4000 ppm CH4 have been recorded. Preserved primary porosity is interpreted to be a result of rapid burial in subtle depositional palaeo-lows in this area. The thickest, amalgamated oolite intervals (tens of metres thick) occur in the eastern part of the Central Netherlands Basin. Because of poor reservoir properties, other areas appear to be less promising in terms of Rogenstein exploration potential. [source]


A 3D HIGH RESOLUTION MODEL OF BOUNDING SURFACES IN AEOLIAN-FLUVIAL DEPOSITS: AN OUTCROP ANALOGUE STUDY FROM THE PERMIAN ROTLIEGEND, NORTHERN GERMANY

JOURNAL OF PETROLEUM GEOLOGY, Issue 3 2007
C. Fischer
The fluvial-aeolian Rotliegend succession exposed in a quarry near Magdeburg (Flechtinger Höhenzug, Northern Germany) is an analogue for deeply-buried gas-bearing Rotliegend sandstones in the Southern Permian Basin. The spatial configuration of bounding surfaces within this succession was reconstructed with reference to twelve profiles with 926 sample points. Generally sub-horizontal interdune migration surfaces were surveyed, and the areal extent of small-scale superimposition surfaces and the thicknesses of intervening strata were measured. Based on these observations and also on the extent of different lithofacies types and on corresponding porosity and permeability data, a 3D lithofacies model (including bounding surface configurations) incorporating porosity and radial permeability was created using PETRELTÔ software. In the quarry, aeolian sandstones approximately 12 m thick (,, 5-11 vol. %, ,radial, 0.01-10mD) are separated into a number of tabular bed sets by sub-horizontal interdune migration surfaces. The surfaces are often associated with thin pelitic intervals with low permeabilities which originate from deflation and sheet flow events. Aeolian deposits consist mainly of two lithotypes: low-angle cross-bedded, and steeply cross-bedded medium-grained sandstones. Superimposition surfaces occur at the base of the low-angle cross-bedded sandstone bodies. The highest porosities and permeabilities occur within the steeply cross-bedded sandstones, reflecting intense eodiagenetic calcite and quartz cementation with subsequent calcite dissolution. The low-angle cross-bedded sandstones may act as flow baffles. This outcrop-derived, high resolution model may contribute to a better understanding of the subsurface architecture and reservoir properties of aeolian-fluvial successions. Taking into consideration the centimetre- to metre-scaled inhomogeneities observed at outcrop, lithotype modelling with reference to the occurrence of bounding surfaces may help to predict how similar reservoir rocks are partitioned. [source]


CYLINDRICAL AND CONICAL FOLD GEOMETRIES IN THE CANTARELL STRUCTURE, SOUTHERN GULF OF MEXICO: IMPLICATIONS FOR HYDROCARBON EXPLORATION

JOURNAL OF PETROLEUM GEOLOGY, Issue 3 2006
J. J. Mandujano V.
The NW-SE trending Cantarell structure in the Gulf of Campeche hosts the largest oilfield in Mexico. The oil occurs predominantly in latest Cretaceous , earliest Tertiary breccias with subsidiary reserves in Upper Jurassic (Oxfordian and Kimmeridgian) and Lower Cretaceous oolitic and partially dolomitized limestones, dolomites and shaly limestones. Cantarell has been interpreted both as a fold-and-thrust zone and as a dextral transpressional structure. Analysis of structure contours at 100m intervals, on the tops of the Tertiary breccia and the Kimmeridgian (Upper Jurassic) dolomite, indicates that the structure is an upright cylindrical fold with gently plunging conical terminations; there is also a conical portion in the central part of the structure. The axes of the central, NW and SE cones are subvertical. This geometry indicates that the two fold terminations and the central cone are aprons rather than points, with the NW and central cone axes intersecting the cylindrical fold axis at the point where the geometry switches from conical to cylindrical. The apical angle (i.e. the angle between the fold and cone axes) varies as follows: (i) in the NW cone, it is ,70° in the breccia and ,76° in the Kimmeridgian dolomite; (ii) in the central cone, it is ,77° in the breccia and ,73° in the Kimmeridgian dolomite; and (iii) in the SE cone, it is ,64° in the breccia and ,57° in the Kimmeridgian dolomite. This indicates that whereas the fold opens with depth in the NW cone, it tightens with depth in the central and SE cones. Assuming a parallel fold geometry, these apical angles indicate an increase in volume in the NW cone (i.e. larger hydrocarbon reservoirs), compared to the central and SE cones. Theoretical considerations indicate that the curvature increases dramatically towards the point of the cone. In the case of the Cantarell structure, the apices of the cones are located at the conical-cylindrical fold junctions, where the highest curvature may have resulted in a higher degree of fracturing. The coincidence of maximum curvature and the intersection of the conical and cylindrical fold axes in the fold culminations with porous and permeable reservoir rocks may have made these locations favourable for the accumulation of hydrocarbons. [source]


SEISMIC FACIES ANALYSIS BASED ON 3D MULTI-ATTRIBUTE VOLUME CLASSIFICATION, DARIYAN FORMATION, SE PERSIAN GULF

JOURNAL OF PETROLEUM GEOLOGY, Issue 2 2006
P. Farzadi
Interpretation of recently acquired 3D seismic data from the adjacent Sirri C and D oilfields in the SE Persian Gulf indicates that a 3D interpretation of seismic facies is crucial to resolve the internal stratal geometries of the Aptian Dariyan Formation. This carbonate formation passes southward into the Shu'aiba Formation, a prolific reservoir rock of similar facies in the UAE. Lack of exposures and limited cored intervals have forced reliance on the seismic data for evidence of the depositional environment and the internal architecture of potential reservoir rocks. The progradational nature of the Dariyan Formation and the occurrence of carbonate build-ups within it make this stratal geometry complex. The complex internal heterogeneity of the build-ups and presence of seismic noise make mapping of the build-ups in 3D space using conventional seismic interpretation tools difficult, despite the availability of high-quality 3D seismic data covering the area. The high quality seismic and limited well data from this field is one of the few datasets of this kind presented in the literature. A procedure for the hierarchical multi-attribute analysis of seismic facies using Paradigm's Seis Facies software is used in this study to provide a 3D interpretation of the stratal patterns. Principal component analysis reduces the noise and redundant data by representing the main data variances as a few vector components in a transformed coordinate system. Cluster analysis is performed using those components which have the greatest contribution to the maximum spread of the data variability. Six seismic attribute volumes are used in this study and the result is a single 3D classified volume. Important new information obtained from within the Dariyan Formation gives new insights into its stratigraphic distribution and internal variability. This method of processing seismic data is a step towards exploring for subtle stratigraphic traps in the study area, and may help to identify exploration targets. [source]


EVALUATION OF THE CONTROLS ON FRACTURING IN RESERVOIR ROCKS

JOURNAL OF PETROLEUM GEOLOGY, Issue 4 2005
D.C.P. Peacock
The style, geometry and distribution of fractures within reservoir rocks can be controlled by numerous factors, including: rock characteristics and diagenesis (lithology, sedimentary structures, bed thickness, mechanical stratigraphy, the mechanics of bedding planes); structural geology (tectonic setting, palaeostresses, subsidence and uplift history, proximity to faults, position in a fold, timing of structural events, mineralisation, the angle between bedding and fractures); and present-day factors, such as orientations of in situ stresses, fluid pressure, perturbation of in situ stresses and depth. The relative timing of events plays a crucial role in determining the geometry and distribution of fractures. For example, open fractures are commonly clustered around faults if the open fractures and faults formed at the same time, but clustering does not tend to occur if the open fractures pre-date or post-date the faults. Understanding these factors requires traditional geological skills, including the analysis of one-dimensional (line-sampling) data from core, borehole images and exposed analogues. This paper reviews the factors that control fractures within reservoir rocks and discusses methods to assess those controls. Examples are presented from Mesozoic limestones in southern England. It is shown that traditional geological skills are of vital importance in determining the rock characteristics, structural and present-day factors that control fractures. [source]


THE LACUSTRINE LIANGJIALOU FAN IN THE DONGYING DEPRESSION, EASTERN CHINA: DEEP-WATER RESERVOIR SANDSTONES IN A NON-MARINE RIFT BASIN

JOURNAL OF PETROLEUM GEOLOGY, Issue 4 2005
Jin Qiang
A lacustrine fan covering an area of about 175sq. km has been identified in the Liangjialou area in the SW of the Dongying Depression, a Tertiary non-marine rift basin in eastern China. Fluvial and deltaic sandstones are established reservoir rocks in the basin, and the deep-water sandstones of the fan succession, which are assigned to Member 3 of the lower Tertiary Shahejie Formation, are also thought to have important reservoir potential. Available data for this study included some 800m of core from 16 wells, well-log data from 426 wells, and 220 sq.km of 3D surveys together with well-test and other production data. From geomorphological reconstructions of the fan, we distinguish first-order (major) fan channels from second-order branched and more distal tip channels. Crevasse splays and overbank shales occur between channels, and sandstone lobes were deposited at channel mouths. Conglomeratic sandstones deposited in major channels are probably the most promising reservoir facies (average porosity c. 20%; average permeability > 1D). Fan construction took place during a single complete cycle of lake level variation which was composed of several sub-cycles. During initial highstand conditions, the fan was dominated by small-scale branched and tip channels and intervening sandy lobes. Fan size increased rapidly during the following lowstand, and then decreased during the ensuing highstand. [source]