Showing papers on "Petroleum reservoir published in 2002"

Screening criteria for co2 storage in oil reservoirs

Abstract: Oil fields are likely to the first category of geologic formation where carbon dioxide (CO2) is injected for sequestration on a large scale, if geologic sequestration proves feasible. About 1.4 BCF per day (69 300 tonnes/day) of CO2 are currently injected for oil recovery in the U.S. Replacing this naturally occurring CO2 with anthropogenic CO2 would have a minor, but measurable, effect on overall CO2 emissions. However, CO2 is injected into only a small fraction of reservoirs and it is estimated that upwards of 80% of oil reservoirs worldwide might be suitable for CO2 injection based upon oil recovery criteria alone. These facts combined with the generally extensive geologic characterization of oil reservoirs and the maturity of CO2–oil recovery technology make oil reservoirs attractive first targets as CO2 sinks. This paper lays the groundwork necessary to evaluate whether an oil reservoir might be suitable for CO2 storage. As such, a series of criteria for injection into currently producing, d...

Incorporating capillary pressure, pore throat aperture radii, height above free-water table, and Winland r35 values on Pickett plots

Abstract: Methods are presented for incorporating capillary pressure, pore throat aperture radii, height above the free-water table, and Winland r 35 values on Pickett plots. The techniques involve the use of log-log plots of effective porosity vs. resistivity combined with empirical equations for calculating capillary pressure written as a function of permeability, porosity, and water saturation. I show that a crossplot of porosity vs. true resistivity (in some cases apparent resistivity or true resistivity affected by a shale group) should result in a straight line for intervals with constant capillary pressure and constant pore throat aperture radii. Key advantages of the proposed methods are (1) the capillary pressure at any point on the Pickett plot is consistent with porosity, permeability, and water saturation at that particular point; (2) the value of R w does not have to be known in advance, provided that the reservoir contains some water-bearing intervals; and (3) core data are not essential, although it is strongly recommended to have cores to properly calibrate the equations presented in this article. If capillary pressures from cores are available, it is possible to estimate the value of R w even if there are not water-bearing intervals in the reservoir. Pore throat aperture radii ( r 35) values computed using the empirically derived Winland equation compare reasonably well with pore throat aperture radii ( r p35) calculated from techniques presented in this article. This is significant because the data sets used to establish these empirical equations come from different areas, different reservoirs, and different lithologies and were evaluated independently at different times. A mathematical relationship is developed between Winland r 35 values and the pore throat aperture r p35 presented in this article. The methods are illustrated using two case histories. The first one is a Gulf Coast high-porosity sand-shale sequence. The second is a limestone oil reservoir from the Lansing Kansas City formation. The integration of permeability, capillary pressures, pore-size classes, and geometry of the pores on a log-log graph of porosity vs. resistivity makes the Pickett plot one of the most formidable formation evaluation tools yet devised. Roberto Aguilera is president of Servipetrol Ltd. in Calgary, Canada. He has an undergraduate degree in petroleum engineering from the Universidad de America in Bogota, Colombia, and a master's degree and Ph.D. in petroleum engineering from the Colorado School of Mines. He was an AAPG instructor on the subject of naturally fractured reservoirs from 1984 through 1996. He received the Outstanding Service Award from the Petroleum Society of the Canadian Institute of Mining, Metallurgy and Petroleum Engineers (CIM) in 1994. He is a Distinguished Author of the Journal of Canadian Petroleum Technology (1993 and 1999) and a Society of Petroleum Engineers Distinguished Lecturer on the topic "Naturally Fractured Reservoirs" for the 2000-2001 season. He has developed various methods that have been published in leading journals of the oil industry. He has authored and been a contributor to various books, including Naturally Fractured Reservoirs (PennWell, 1980 and 1995), The Technology of Artificial Lift Methods (PennWell, 1984), Horizontal Wells (Gulf Publishing, 1991), and Determination of Oil and Gas Reserves (Petroleum Society of CIM Monograph 1, 1994).

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

Abstract: 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 lowerpressure injection regime. Applying a processing sequence to the Phase VI data preserving normal-incidence shearwave 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.

Rock types and permeability prediction from dipmeter and image logs: Shuaiba reservoir (Aptian), Abu Dhabi

Abstract: The Shuaiba Formation is a complex carbonate reservoir characterized by small-scale geological heterogeneity primarily related to rudist macrofauna. The textural heterogeneity corresponds to extreme permeability variation that is the controlling factor in reservoir production. Because of the large vertical resolution contrast between cores (actual scale) and conventional logs (averaged responses over a few feet), extrapolation of small-scale heterogeneity into uncored wells using a traditional approach is unreliable. High-resolution log data, like dipmeters and image logs, are required to characterize small-scale heterogeneity that is essential to a good three-dimensional (3-D) geological model that predicts true reservoir behavior. Our study illustrates an approach to improve the reservoir characterization of the Shuaiba by quantifying small-scale heterogeneity using dipmeter and image logs. A methodology is proposed to use the existing high-resolution (High-resolution Dipmeter Tool [HDT], Stratigraphic High-resolution Dipmeter Tool [SHDT], and Formation MicroScanner [FMS]) and conventional log data to characterize and extrapolate geological heterogeneity. Texture and neural network analyses, derived from microresistivity variations and a multiregression approach, have been used in two wells to demonstrate the methodology. Both rock types and permeability are estimated for extrapolation into uncored wells. Although differences between the conductivity of conductive and resistive areas when normalized for background conductivity are an indirect measure of permeability for HDT and SHDT, the connectivity coefficient of conductive anomalies derived from textural analysis is related to permeability in the case of FMS. Reservoir rock types (RRT) obtained from the methodology correlate well with RRTs derived from the integration of core, special core analysis (SCAL), and conventional log data in two test wells. Permeability estimations, including small-scale extreme variations from less than 1 md in tight mudstones to greater than 1 d in caprinid rudstones, are in good agreement with the core plug permeability measurements after a simple calibration. In one example, permeability trends in rudist RRTs, which are not discernible using core plugs and minipermeameter data, are clearly resolved using SHDT data. The degree of correlation between estimated and core permeabilities is greater with increased vertical resolution of the tool (HDT, lowest; FMS, highest). Distinct RRTs resulting from small-scale geological heterogeneity can be classified and permeability can be estimated with a high degree of confidence, providing a better pathway of extrapolating from core data to conventional logs for 3-D modeling. The methodology has potential application to other carbonate and siliciclastic reservoirs with appropriate calibration and scaling. Underused HDT, SHDT, FMS, and Fullbore Formation MicroImager (FMI) databases are available in many other areas that could be analyzed. An order of magnitude improvement in the ability to characterize small-scale heterogeneity has significant implications for future coring, logging programs, and reservoir characterization efforts. Duffy Russell is a senior carbonate geologist at Saudi Aramco in the Reservoir Characterization Department, Southern Fields Characterization Division. He received B.S. and M.S. degrees in geology from North Carolina State University in 1976 and Duke University in 1979 and a Ph.D. in geology from the University of Aberdeen in 2001. He started his career as a geophysicist with Amoco Production Company in 1979 and has worked nearly 21 years as a geologist for Mobil Oil Corporation and ExxonMobil, specializing in carbonate reservoir characterization.Mahmoud Akbar is a principal geologist for Schlumberger working Iran, Qatar, the United Arab Emirates, Oman, and Yemen. He started his professional career with Schlumberger Wireline and Testing in 1985 in Pakistan. He received B.Sc. (1983) and M.Sc. (1985) degrees in applied geology from the University of Punjab, Pakistan. He has carried out research in the Lower Himalayas on factors controlling fractures and their effect on rock strength. Badarinadh Vissapragada is a senior petrophysicist with Schlumberger Data and Consulting Services, Abu Dhabi, United Arab Emirates. He did his postgraduate study in geophysics at Andhra University, Waltair, India. He has more than 19 years of petrophysics experience in India and Middle East reservoirs from fieldwide petrophysical studies and reservoir characterization. His special interests are reservoir rock typing, permeability, and fracture detection. Gordon Walkden is head of the Department of Geology and Petroleum Geology at the University of Aberdeen, Scotland. After receiving a degree from Quintin School in London, he obtained his Ph.D. in carbonate sedimentology from Manchester University, United Kingdom, in 1970. Gordon was appointed senior lecturer in 1988 and became department head in 1993. He has extensive field experience and supervision of research projects in Britain, Europe, North America, and the Middle East.

Iterative Coupled Analysis of Geomechanics and Fluid Flow for Rock Compaction in Reservoir Simulation

Abstract: Conventional reservoir simulators calculate the effect of rock compaction on pore volume change through the concept of rock compressibility under a defined loading condition (hydrostatic or uniaxial strain). This approach usually is appropriate for reservoirs with competent rock. For weaker formations and complicated rock compaction behavior, however, a coupled analysis of geomechanics and multiphase fluid flow may be required for obtaining more rigorous and accurate solutions from reservoir simulation. In general, computational efficiency and convergence of numerical solutions are two critical factors in order to make coupled analysis economically and numerically feasible for practical field applications. In this paper, an iterative procedure for coupled analysis of geomechanics and multi-phase flow in reservoir simulation is proposed for large-scale, full-field, 3D problems. The proposed procedure isgeneral and effective for handling reservoir rock with complicated constitutive behavior of rockcompaction and permeability change as well as for simulating various reservoir production scenarios. Descriptions of model formulations, constitutive equations, solution procedures, and strategies for enhancement of computational efficiency are presented in the paper. To demonstrate the capability of the developed procedure for iterative coupled analysis, several problems including a large-scale field example were studied and are presented.

Evolution and origin of deep reservoir water at the Activo Luna oil field, Gulf of Mexico, Mexico

Abstract: Petroleum wells of the Activo de Produccion Luna oil field at the Mexican Gulf Coast are partially invaded by formation water at a production depth between 5000 and 6000 m. Measured 14C activities between less than 0.9 and 13.7% modern carbon reflect a homogenous, late Pleistocene-early Holocene age (40-10 ka) for the regional infiltration of meteoric and marine water into the reservoir. Before infiltration, both components were partially affected by atmospheric evaporation, which explains the hypersaline composition of some formation waters. Very positive d18O values (up to +12.5‰) of the formation waters are caused by strong secondary water-rock interaction processes and reflect close to equilibrium conditions between the carbonate host rock and the fluids. The formation of biogenic and/or thermocatalytic methane in some parts of the petroleum reservoir is indicated by d13C values up to +20.4‰. Southwest-northeast-directed hydraulic migration of the deep aquifer between camps Sen and Escuintle-Pijije-Caparroso is indicated by interference tests and pressure drawdown characteristics, whereas northwest-southeast-trending thrust faults restrict communication toward the Luna and Tizon camps in the most northeastern part of the oil field. On a local scale, vertical zonation trends of the fluids with decreasing salinity toward upper parts of the common aquifer are related to separation processes by gravity and/or by the rising of condensed vapor. The migration of the fluids is mainly related to southwest-northeast-trending fractures and microfractures, whereas northwest-southeast- and northeast-southwest-trending reverse and normal faults, respectively, behave irregularly as barrier or as flow conduits. Recently, the extraction of petroleum caused an increased mobilization of the hydrodynamic aquifer system. (Begin page 458)

Hydrocarbon sources and stages of reservoir formation in Kuqa depression, Tarim Basin

Abstract: Kuqa depression bears not only plenty of natural gas, but also a large amount of condensate and small quantity of crude oil. Based on the geochemical correlation between the Jurassic and Triassic terrestrial hydrocarbon source rock, this paper confirms that the natural gas in Kuqa depression belongs to coal-type gas and the main gas source rock is attributed to the middle to lower Jurassic coal series formation, while the main oil source rock is the upper Triassic lacustrine mudstone. The authors indicated that Kuqa depression was slowly subsided in Mesozoic, but rapidly went down in Late Tertiary, which made the Jurassic and Triassic source rock suddenly deep-buried and rapidly evolved to high and over-mature phase since 5 Ma. The Triassic source rock is postponed to the Early Miocene during 23−12 Ma when entering the oil-generating peak, while the Jurassic is suspended to the latest 5 Ma, especially since 2.5 Ma to the dry gas-generating period, which is one of the characteristics of the source rock thermal evolution in Kuqa depression. This paper presents a two-stage trapping and late gas trapping model in Kuqa depression whose characteristics are: The main oil and gas reservoirs have different sources. The oil reservoir is formed early while the gas reservoir is formed lately. During the early stage, it, mainly as oil, takes long distance lateral migration, while in the later stage, it, mainly as gas, takes the vertical migration and also has lateral migration. The trap formed in different time on the south and north sides of the depression and evolved into a distributional pattern with oil in the south part and gas in the north, also oil on the outer ring and gas on the inner ring. This paper points out that the late trapping of the natural gas in Kuqa depression is favorable for the preservation of large gas fields.

Dynamics for multistage pool formation of Lunnan low uplift in Tarim Basin

Abstract: Lunnan area in the Tarim Basin has become an important onshore oil production base in China. Formation of the oil and gas pools in the low uplift of Lunnan has experienced a comparatively complex process of dynamics. Based on the hydrocarbon generation period of source rocks, the formation period of cap rocks and traps, the analysis of organic inclusion and the analysis of bitumen in the reservoir, this paper draws the conclusion that the low uplift area of Lunnan has experienced three pool formation periods: the Permian period, the Cretaceous-Early Tertiary period and the Late Tertiary-Quaternary period and two oil and gas reservoir adjustment periods: the Late Permian period and the Late Tertiary-Quaternary period. The comprehensive study indicates that the largescale Ordovician buried hill, formed in Early Hercynian, became the reservoir during the Permian period, because the Cambrian-Lower Ordovician oil was discharged laterally into the reservoir along the top of the Ordovician weathering crust from south to north. The reservoir experienced a complicated process—reconstruction in the end of Permian, adjustment in Cretaceous-Early Tertiary and redischarging process in Late Tertiary-Quaternary, leading to the early original heavy oil reservoir of marine facies and the late original light oil reservoir and gas pool. Carboniferous, Triassic and Jurassic oil and gas reservoirs result from upward adjustment and redistribution of Ordovician oil and gas reservoirs. Of those results, the formation of Triassic-Jurassic oil and gas pools came under the influence of the northwardtilting structure. The oil and gas sourcing from the different hydrocarbon source rock intervals vertically migrated into the base unconformity of Triassic system. Then the oil and gas migrated laterally from north to south and accumulated into the reservoir.

Structure, stratigraphy, and hydrocarbon system of a Pennsylvanian pull-apart basin in north-central Texas

Abstract: In 1989, a deep test in Cottle County, Texas, discovered an anomalously thick, gas-charged Pennsylvanian (lower Bend Group) clastic section along the Matador arch. Subsequent exploration and development provided data that support the concept that the natural gas fields in Cottle and King counties, north-central Texas, mark the extent of a hydrocarbon system related to the Broken Bone graben, an elongate 180 km2 pull-apart basin in southeastern Cottle County. The graben results from left-step overstepping of left-lateral fault zones and is a component of the Red River-Matador structural trend of the greater Ancestral Rocky Mountains. Arkosic detritus originating from the Amarillo-Wichita uplift was transported southward, over the region containing the graben, toward the Knox-Baylor trough. Episodic graben subsidence accommodated a part of this sediment load as syntectonic, cyclically stacked Bend Group (Atokan, lower Pennsylvanian) fluvial-deltaic to marine deposits. Organic facies within the graben fill are predominantly terrestrially derived (gas prone) and present in sufficient quantity for significant hydrocarbon generation. Lopatin method basin modeling, vitrinite reflectance (Ro) measurements, and Ro-calibrated pyrolysis-derived maturity measures demonstrate that the Bend Group organic facies in the graben have approached peak gas-generating maturation levels. Generated gas migrated within and outside of the basin following nonsealing faults and channelized fluvial pathways into several reservoir rock types in combination structural and stratigraphic traps. (Begin page 2)

Power-law scaling of spatially correlated porosity and log(permeability) sequences from north-central North Sea Brae oilfield well core

Abstract: Summary The spatial cross-correlation and power spectra of porosity and log(permeability) sequences are analysed for a total of 750 m of reservoir rock drill-core from four vertical wells in the Brae Formation, an important coarse-grained clastic North Sea hydrocarbon reservoir rock. The well core sequences are 80 ± 4 per cent cross-correlated at zero lag and have power-law-scaling spatial power spectra S(k)∝1/kβ, β≈ 1 ± 0.4, for spatial frequencies 5 km−1 < k < 3000 km−1. The strong spatial cross-correlation of porosity and log(permeability) and the systematic power-law scaling of log(permeability) spatial fluctuation spectra fit into a broad physical context of (1) the 1/k spectral scaling observed in several hundred well logs of sedimentary and crystalline rock recorded world-wide; (2) the 1/f spectral scaling of temporal sequences in a wide range of physical systems; and (3) analogy with power-law-scaling spatial fluctuation spectra in a wide range of critical-state thermodynamic systems. In this physical context, the spatial fluctuations of log(permeability) of clastic reservoir rock are interpreted as due to long-range correlated random fracture-permeability networks in a fluid-saturated granular medium where the range ξ of spatial correlation is effectively infinite. Fracture-permeability spatial fluctuations with long-range correlations and 1/k-scaling spectra have practical implications for geofluid reservoir management. Inadequate models of reservoir flow structure are widely attributed to uncertainty in fault and fracture location and connectivity. As a general phenomenon, spatial configurations of large-amplitude, long-range spatially correlated random fluctuations are unpredictable from the statistics of small-scale samples. The observed 1/k spectral scaling of porosity and log(permeability) distributions thus implies that large-scale, large-amplitude fracture-related flow heterogeneity (1) can determine the drainage pattern of crustal reservoirs but (2) cannot be accurately predicted using statistical techniques based on small-scale reservoir samples. Incompatibility of the physics of reservoir heterogeneity and the statistical approaches to reservoir models can thus explain the persistent under-performance of stochastic reservoir models. Accurate reservoir flow models can, however, be determined by direct observation of fluid flow at the reservoir scale. Recent advances in seismic time-lapse reservoir-fluid monitoring may provide data for significantly more effective management of hydrocarbon reservoirs, waste burial sites, mining works and groundwater aquifers.

A method for oil recovery from an oil field

Abstract: A method for increasing oil recovery from an oil reservoir in which method surplus gas streams from a plant for synthesis of higher hydrocarbons from natural gas is injected into the reservoir, is described. The surplus streams from the plant is the tailgas from the synthesis and optionally nitrogen from an air separation unit which delivers oxygen or oxygen enriched air to the plant for synthesis of higher hydrocarbons.

Seismic inversion successfully predicts reservoir, porosity, and gas content in Ibhubesi Field, Orange Basin, South Africa

Abstract: In 2000 Forest Oil International shot a 312 km2 3-D seismic survey in South Africa's Block 2A around a well that, despite testing 53 million ft3/d gas and 342 bbls condensate/d gas, had been abandoned in 1986 (Figure 1). This well (AK-1) was thought to have tested a small noncommercial structural trap. The 3-D showed that the field, now designated Ibhubesi Field, is in fact a giant regional stratigraphic trap. The 3-D survey might only cover a small part of the southern extent of the field, which may eventually produce 15 trillion ft3 of gas.

Changing paradigms in oil and gas reservoir monitoring - the introduction and commercialization of in-well optical sensing systems

Abstract: Downhole measurements play a critical role in the production of oil and gas reservoirs. Parameters such as pressure, temperature and fluid flow provide valuable insights into the depletion dynamics of a reservoir that, if optimized, can be highly beneficial to the productivity and economics of the well. Unfortunately, oil and gas reservoirs represent some of the harshest, least accessible, environments on earth. This paper addresses the development and commercialization of fiber optic sensing systems to monitor the conditions of these reservoirs on a real time basis as the oil and gas is produced.

Microstructural and geomechanical characterisation of fault rocks from the Carnarvon and Otway basins

Abstract: The results of natural and laboratory-induced fault behaviour from wells in the Otway Basin are compared with sample material from a producing Carnarvon Basin field where rocks from a fault zone have been cored. Capillary pressure, microstructural and juxtaposition data obtained from these fault rocks indicate a capability to hold back gas columns in excess of 100 m, yet many fault closures are found to contain only palaeo-columns. Trap failure is usually attributed to reactivation of trap-bounding faults, often during Miocene-Recent times in these basins. Faults susceptible to reactivation can be predicted by geomechanical methods involving the determination of the in-situ stress field and the orientation and dip of faults with respect to that stress field. Failure envelopes of fault rocks have been determined to estimate reactivation potential in the present day in-situ stress field. This approach works well where fault rocks are weaker than the host reservoir sandstone, but may not be applicable where fault rocks are stronger. In fields where the latter is the case, intact hydrocarbon columns are present, irrespective of whether faults are optimally oriented for reactivation. This indicates that the assumptions of zero cohesive strength and constant friction coefficient for predicting the reactivation potential of fault rocks may not be completely reliable.

Dating formation of natural gas pools using fluid inclusion data from reservoirs

Abstract: A method has been suggested which is based on the homogenization temperatures and other data of fluid inclusions from a reservoir rock, with the combination of burial and geothermal history of the hosted rock, to date the gas reservoir formation. On the basis of this, a case study of the Carboniferous-Permian gas pools in the Ordos Basin has been conducted. The results have shown that the reservoir sandstones of the gas pool were filled by gases during 125–150 Ma, earlier in the southern area and later in the northern area, which is consistent with the basin’s geological and geochemical background under which the gas pools formed

Subsurface and petroleum geology of the southwestern Santa Clara Valley ("Silicon Valley"), California

Abstract: Gravity anomalies, historical records of exploratory oil wells and oil seeps, new organic-geochemical results, and new stratigraphic and structural data indicate the presence of a concealed, oil-bearing sedimentary basin beneath a highly urbanized part of the Santa Clara Valley, Calif. A conspicuous isostatic-gravity low that extends about 35 km from Palo Alto southeastward to near Los Gatos reflects an asymmetric, northwest-trending sedimentary basin comprising low-density strata, principally of Miocene age, that rest on higher-density rocks of Mesozoic and Paleogene(?) age. Both gravity and well data show that the low-density rocks thin gradually to the northeast over a distance of about 10 km. The thickest (approx 4 km thick) accumulation of low-density material occurs along the basin's steep southwestern margin, which may be controlled by buried, northeast-dipping normal faults that were active during the Miocene. Movement along these hypothetical normal faults may been contemporaneous (approx 17-14 Ma) with sedimentation and local dacitic and basaltic volcanism, possibly in response to crustal extension related to passage of the northwestward-migrating Mendocino triple junction. During the Pliocene and Quaternary, the normal faults and Miocene strata were overridden by Mesozoic rocks, including the Franciscan Complex, along northeastward-vergent reverse and thrust faults of the Berrocal, Shannon, and Monte Vista Fault zones. Movement along these fault zones was accompanied by folding and tilting of strata as young as Quaternary and by uplift of the modern Santa Cruz Mountains; the fault zones remain seismically active. We attribute the Pliocene and Quaternary reverse and thrust faulting, folding, and uplift to compression caused by local San Andreas Fault tectonics and regional transpression along the Pacific-North American Plate boundary. Near the southwestern margin of the Santa Clara Valley, as many as 20 exploratory oil wells were drilled between 1891 and 1929 to total depths as great as 840 m. At least one pump unit is still standing. Although no lithologic or paleontologic samples are available from the wells, driller's logs indicate the presence of thick intervals of brown shale and sandstone resembling nearby outcrops of the Miocene Monterey Formation. Small amounts of oil and gas were observed in several wells, but commercial production was never established. Oil from the Peck well in Los Gatos is highly biodegraded, contains biomarkers commonly found in oils derived from the Monterey Formation, and has a stable-C-isotopic (δ 1 3 C) composition of -23. 32 permil, indicating derivation from a Miocene Monterey Formation source rock. Preliminary calculations suggest that about I billion barrels of oil may have been generated from source rocks within the Monterey Formation in the deepest part of the subsurface sedimentary basin between Los Gatos and Cupertino. Most of this oil was probably lost to biodegradation, oxidation, and leakage to the surface, but some oil may have accumulated in as-yet-undiscovered structural and stratigraphic traps along the complex structural boundary between the Santa Clara Valley and the Santa Cruz Mountains. Although some of these undiscovered accumulations of oil may be of commercial size, future petroleum exploration is unlikely because most of the area is currently devoted to residential, recreational, commercial, and industrial uses.

Characteristics of carbonate gas pool and multistage gas pool formation history of Hetianhe gas field, Tarim Basin, Northwest China

Abstract: Hetianhe is a big carbonate gas field which is found and demonstrated in the period of “Chinese National Ninth 5-Year Plan”. The proved reserve of Hetianhe gas field is over 600×108 m3. Its main producing layers are Carboniferous bioclastic limestone and Ordovician carbonate composed of buried hill. The former is stratified gas pool with water around its side, and the latter is massive gas pool with water in its bottom. The gases in the gas pools belong to dry gases with normal temperature and pressure systems. Based on the correlation of gas and source rock, the gases are mainly generated from Cambrian source rocks. According to the researches on source rock and structure evolution, and the observations on the thin section to reservoir bitumen and the studies on homogenization temperature of fluid inclusions, the gas pool has been identified and divided into three formation periods. The first is Late Caledonian when the oil generated from the Cambrian source rocks and migrated along faults, as a form of liquid facies into Ordovician carbonate reservoir and accumulated there. After that, the crust uplifted, the oil reservoir had been destroyed. The second is Late Hercynian when condensate gases generated from the Cambrian source rocks and migrated into Ordovician reservoir, as a form of liquid facies. Since the fractures had reached P strata, so the trap might have a real poor preservation condition, and the largescale gas pool formation had not happened. The third gas reservoir formation period occurred in Himalaya. The fractures on both sides of Hetianhe gas field developed violently under the forces of compression, and thus the present fault horst formed. The dry gases generated from Cambrian source rocks and migrated upwards as the form of gas facies into Ordovician and Carboniferous reservoirs, and the large gas pool as discovered at present was formed finally.

Method for modelling hydrocarbon degradation in an oil deposit

Abstract: The invention concerns a method for modelling degradation of hydrocarbons trapped in an oil deposit, or trapped by action of the bacterial population in a subjacent water zone. On the basis of data concerning the oil reservoir examined, concerning the shape and height of the reservoir, the physical characteristics of the porous environment, the thickness of the transition zone between the hydrocarbons and the water, the composition of the hydrocarbons, the flux of electron acceptors coming into the reservoir and data on the bacterial population in the water zone, a modelling is performed by discretizing the deposit by a meshing whereof the height of each mesh is the thickness of the transition zone, and the variation on the height of the deposit, of the proportion of heavy hydrocarbon fractions under the effect of biodegradation is determined by iterative adjustment within each mesh of the bacterial population to the amount of available hydrocarbons, to the available porous space, to the amount of electron acceptors present in the reservoir and the degradation capacities of said population. The invention is useful for determining the composition of oils in a deposit and in particular for locating the heaviest fractions.

Geologic Modelling of External and Internal Reservoir Architecture of Fluvial Depositional Systems

Abstract: An integrated study of a petroleum reservoir was conducted to delineate the facies and sequence-stratigraphic architectures, and structural framework for generation of 3D geologic models for use in improved estimates of reserves, flow-simulation studies, and field-development planning. The study incorporated information from 3D seismic interpretations, well-log correlations, facies and petrophysical analyses of cored intervals, and interpretations derived from outcrop exposures of the reservoir interval.

An experimental approach of elemental sulfur deposition in carbonate oil reservoirs

Abstract: The existence of sulfur compounds in crude oils creates many problems of sulfur deposition in the vicinity of the wellbore hole, in well completion and/or production equipment, and in producing reservoir rocks. The major objectives of this experimental study are to investigate the influences of oil flow rate, initial sulfur concentration of crude oil, and reservoir rock permeability on elemental sulfur plugging in carbonate oil reservoirs. To achieve these objectives, actual crude oils were de-asphaltened to eliminate the effect of asphaltene deposition. Ten dynamic flow experiments were conducted using two actual crude oils of 0.78 and 1.67% sulfur concentrations. Viscosity of crude oils of different sulfur concentrations was measured under different conditions of temperature. The crude oils were flooded through actual carbonate cores of different permeability in the range of 2.34–28.16 millidarcy and under different flow rates of 0.5, 1.0, 1.5, and 2.0 cc/min. In-situ sulfur deposited was measu...

Mechanisms of abnormal overpressure generation in Kuqa foreland thrust belt and their impacts on oil and gas reservoir formation

Abstract: Based on overview for mechanism of abnormal overpressure generation in sedimentary basins, an insight discussion is made by the authors for the distribution, features and generation mechanisms of abnormal overpressure in the Kuqa foreland thrust belt. The abnormal overpressure in the Kelasu structure zone west to the Kuqa foreland thrust belt was primarily distributed in Eogene to lower Cretaceous formations; structural compression and structural emplacement as well as the containment of Eogene gypssalt formation constituted the main mechanisms for the generation of abnormal overpressure. The abnormal overpressure zone in the eastern Yiqikelike structure zone was distributed primarily in lower Jurassic Ahe Group, resulting from hydrocarbon generation as well as structural stress other than from undercompaction. Various distributions and generating mechanisms have different impacts upon the formation of oil and gas reservoirs. K-E reservoir in the Kelasu zone is an allochthonous abnormal overpressure system. One of the conditions for reservoir accumulation is the migration of hydrocarbon (T-J hydrocarbon source rock) along the fault up to K-E reservoir and accumulated into reservoir. And this migration process was controlled by the abnormal overpressure system in K-E reservoir. The confined abnormal overpressure system in the Yiqikelike structure zone constituted the main cause for the poor developing of dissolved porosity in T-J reservoir, resulting in poor physical property of reservoir. The poor physical property of T-J reservoir of Yinan 2 structure was the main cause for the absence of oil accumulation, but the presence of natural gas reservoir in the structure.

Chapter 11 Abnormally low formation pressures

Abstract: Publisher Summary The existence of underpressured fluid chambers has enormous significance to oil and gas exploration, and production in the world. Such fluid compartments are determinative elements for undetected hydrocarbon traps (i.e., so-called subtle traps). Traditionally, most hydrocarbon production in the world has been from conventional structural and stratigraphic traps. Traps of a newly identified type, the underpressured hydrocarbon traps, may evolve from conventional traps as a result of changes in temperature and pressure. This kind of underpressured traps can be created by considerable overburden removal, and local temperature change due to uplift and erosion giving rise to decreased pore pressure. It is important to construct a model for potential hydrocarbon sources in geological sections with abnormally low pressure. This model can be constructed using the change of rock temperature in local zones with significant uplift and erosion. For estimating the thicknesses of eroded deposits the authors used the method of compression curves, that indicate the presence of unconformities and the thickness of eroded deposits not only near the surface, but also deep in the geologic section. The modeling of subsurface underpressured zones may indicate a technique for making underpressured compartment traps viable exploration targets, because exploration strategies can be made significantly more effective if the mechanism of their formation is well understood.

A New Approach for Reservoir Characterization

Abstract: Predicting reservoir performance reliably requires an accurate model of the reservoir. For reservoir simulation, identifying and predicting flow units depend strongly on the permeability distribution. For reservoirs having few permeability measurements, such as most reservoirs in the Appalachian basin, statistical and artificial-intelligence techniques could identify flow units on the basis of limited core-analysis data supplemented by minipermeameter measurements, geological interpretations, and well-log data.

Future potential exploration domains in composite oil-gas accumulation zones of bohai bay basin

Abstract: Underwent 40 years' exploration and development history,the composite oil_gas accumulation zones in Bohai Bay Basin have come into mature stage.But the complicated characters of petroleum distribution in Bohai Bay Basin still show a further foreground to discover more potential resources.The exploration precision of petroleum system with the source rock as Tertiary should be improved,and also more attentions must be paid to the other petroleum system with the source rock as Mesozoic,Paleozoic and Mid_Upper Proterozoic.Generally,any stratigraphic series in the composite oil_gas accumulation zones in Bohai Bay Basin have the possibilities to generate and accumulate oil_gas,which makes us to discover and confirm more types of petroleum reservoir.

Petroleum geology of pre-salt sediments in the pre-caspian basin

Abstract: An integrated study on lithology, sedimentology and petroleum geology of Pre?Salt Sediments in the Pre?Caspian Basin are carried out in this paper The key point of oil and gas reservoir formation and distribution in the Pre?Salt Sediments is recognized By analysis of characters and distribution patterns of the found hydrocarbon pools, it is suggested that the Pre?Salt Sediments in Kraton?Tengiz Uplift and North Caspian?Azigiar Uplift are the favorable areas for petroleum exploration, followed by Yenbek?Zharkames and Zhanazhol areas (eastern part of the basin), and the southwestern and western slopes of the Astrakhan?Oktyabrsk Uplift zone (the western and southwestern parts of the basin), as well as Uzensk area (the northwestern basin) are of certain potential for petroleum exploration as well