Showing papers on "Petroleum reservoir published in 2001"

Geology of Petroleum

Abstract: A commemorative edition reprint of the classic volume originally published in 1967, this book remains a useful reference resource for working petroleum geologists as well as students. It covers the basics of reservoirs, including reservoir rock, pore space, fluids, traps, and mechanics, as well as describing the origin of petroleum and the migration and accumulation of petroleum.

In Situ Stable Isotopic Evidence for Protracted and Complex Carbonate Cementation in a Petroleum Reservoir, North Coles Levee, San Joaquin Basin, California, U.S.A

Abstract: Knowledge of the evolution of carbonate cementation in hydrocarbon reservoirs is key to understanding the history of fluid flow during petroleum accumulation. The Stevens sands is a sequence of marine shales and deep-sea fan sands that was deposited within the Miocene Monterey Formation in the south-central part of the San Joaquin basin, California, during the upper Miocene (10-6 Ma). Rapid, high-precision in situ oxygen and carbon isotopic analyses of carbonate phases using the ion microprobe operated in multi-collection mode, in conjunction with electron microprobe analyses, indicate that carbonate cement zones within the Stevens sands at North Coles Levee (NCL) have had a complex and protracted fluid history. Three main generations of carbonate cement were identified. The relative timing of carbonate cement precipitation within the Stevens sands at NCL was estimated using the thermal and burial history of the San Joaquin basin, in situ oxygen isotope data, and cementation temperatures derived from equilibrium oxygen isotope fractionation factors for calcite-water and dolomite-water. Precipitation of these cement zones began soon after sediment deposition ( 7 Ma) and is ongoing. Early dolomite was precipitated at a temperature of 10°C, near the sediment-water interface, and soon after sediment deposition. Calcite cements, which are the most abundant variety, precipitated semicontinuously between 4 Ma and 5 Ma, at temperatures between 50°C and 65°C, and depths of 800 m to 1300 m. Fe-dolomite, which is paragenetically late, appears to have precipitated at temperatures near 100°C in response to pore-pressure reduction, which accompanied exploitation of the gas cap within the last 35 years. Carbon in these cements was likely derived from several sources including marine, maturing hydrocarbons, and a zone of methanogenesis.

1000 M Long Gas Blow-Out Pipes

Abstract: This study presents seismic observation of pipe anomalies from offshore Nigeria, outcrops of blow-out pipes from Rhodes, Greece, and geophysical modelling of an acoustic pipe. The studies give insight into how pipes form, their internal structure, the seismic image and geophysical artefacts related to the pipes. Over one hundred seafloor craters, 100 m–700 m wide and up to 30 m deep, have been observed on the seafloor offshore Nigeria. They are underlain by interpreted cones and seismic pipe anomalies that can be traced down to reservoir zones at 1000 m–1300 m below the seafloor. The seismic pipe anomalies are 50 m–150 m wide and almost vertical. They are interpreted as up-scaled pipes found in outcrops on Rhodes, Greece. The outcrops show pipe-related structures at three levels. Lowest, the reservoir rock contains metre-sized cavities which are filled with a mixture of clay derived from the overlying cap rock. In the middle, several circular to oval structures in plane view of pipes are observed in the lowest part of the cap rock. Highest, 15 m into the clay cap rock, strongly sheared country rock forms circular structures with a core of structureless clay. Based on outcrop observation on Rhodes we constructed an acoustic model of a 50 m wide and 1000 m long pipe. Seismic modelling proves that such pipes would be expressed in seismic data, that they are similar to the seismic pipe anomalies offshore Nigeria but this study also revealed that prominent intra-pipe reflections are artefacts. A formation model for the pipes is suggested: High fluid overpressure in the reservoir generated hydro fractures from the reservoir to seafloor where a mixture of gas and fluid flowed at high speed to form pipes, cones and seafloor craters. After hours to weeks of gas and fluid flow through the pipe the pore pressure in the reservoir dropped and the blow-out terminated. Muddy slurry fell back and plugged the cavity in the reservoir and the pipe.

On the collapse behaviour of oil reservoir chalk

Abstract: Oil exploitation in North Sea Ekofisk oilfield started in 1971, the reservoir is located in a 150 m thick layer of porous chalk (n = 40 50%) at a 3000 m depth. Enhanced oil recovery procedure by sea water injection (waterflooding) was initiated in 1987. Starting from this date, seabed subsidence due to chalk compaction evolves at a fairly constant rate (i.e. 40 cm/year). Nowadays, the decrease of the seafloor level is of about 10 m. Reservoir management and production strategies are at the origin of the growing interest of petroleum industry in disposing of a comprehensive description of the chalk mechanical behaviour. In this note the subsidence due to waterflooding is interpreted within a framework taken from the mechanics of unsaturated soils. By considering oil as the non-wetting fluid and water as the wetting fluid, chalk compaction is depicted as a collapse phenomenon due to oil-water suction decrease. A series of suction controlled tests in the osmotic oedometer cell are presented. Water weakening effects and chalk compaction (collapse) seem likely to occur through the lost of strength of the inter-granular links existing in the oil saturated sample. The nature of these links includes both capillary and physico-chemical fluids-chalk interactions, and is well characterised by the oil-water suction.

Method for determining reservoir fluid volumes, fluid contacts, compartmentalization, and permeability in geological subsurface models

Abstract: The present invention is a method for using petrophysical data from a plurality of wells, in a plurality of reservoir regions, containing a plurality of reservoir rock types, in the context of a three-dimensional geological model, for identifying dimensionless capillary pressure functions and using these dimensionless capillary pressure functions for determining reservoir fluid volumes, fluid contacts, the extent of reservoir compartmentalization, and an improved estimate of reservoir permeability. The present invention is directed to the method and finished product of same.

Monterey Formation porcelanite reservoirs of the Elk Hills field, Kern County, California

Abstract: Oil and gas production from Monterey Formation porcelanite at the Elk Hills field in California's San Joaquin basin occurs from intervals that have quartz-phase mineralogy. However, characteristics differ from chert and porcelanite reservoirs of the coastal California Monterey Formation in that matrix porosity is more typical of the opal-CT phase, petroleum storage is mostly in the matrix, and natural fracture patterns are dominantly small scale. Several Elk Hills reservoirs located on two large anticlines produce from porcelanite. The 29R AB and 31S D are the most productive porcelanite reservoirs, each having cumulative oil production of about 40 million bbl. Although interbedded with siliceous shale, sandstone, and dolomite, most of the porous reservoir rock is laminated porcelanite. Porosity averages between 20 and 25% and is evenly distributed throughout the porcelanite as extremely small pores ranging in size from 1 to 10 µm. Matrix permeability averages 0.8 md, but flow of oil and gas is enhanced through fractures parallel with and perpendicular to bedding. Higher than anticipated porosity may be in part due to migration of hydrocarbons into the porcelanite reservoirs while still in opal-CT-phase mineralogy. The dissolution of opal-CT and precipitation of quartz occurs in place, and the resulting quartz-phase mineral structure mimicks the porous opal-CT framework.

Integrated Fractured Reservoir Characterization Using Neural Networks and Fuzzy Logic: Three Case Studies

Abstract: Two categories of natural fractures are generally recognized: regional orthogonal fractures and structure-related or tectonic fractures. Over the past eight years or so, we have developed a methodology using neural networks and fuzzy logic to assist with the characterization of naturally fractured reservoir rocks. Conventional methods use only one or two geological parameters to characterize a naturally fractured reservoir. However, an integrated approach that utilizes all the information available (including lithology, thickness, state of stress and fault patterns) is required. Our approach makes use of fuzzy logic to quantify and rank the importance of each geological parameter on fracturing; a neural network is used to find the complex, non-linear relationship between these geological parameters and the fracture index. Three case studies are described in this paper to illustrate the use of this methodology. They report respectively on a faulted limestone oil reservoir in North Africa which is deformed by fault-related fractures; a carbonate oil reservoir in New Mexico which is, characterized by fold-related fractures; and a sandstone gas reservoir in NW New Mexico which has regional orthogonal fractures. These three case studies illustrate fracture identification and prediction using static information (i.e. image logs) and/or dynamic information (i.e. well performance) as a fracture index. The results of these studies are described as they relate to infill drilling, understanding the fractured reservoir and improved reservoir simulation.

Application of boron isotopes to the understanding of fluid–rock interactions in a hydrothermally stimulated oil reservoir in the Alberta Basin, Canada

Abstract: Boron isotope ratios of reservoir minerals and fluids can be a useful geothermometer and monitor of fluid–rock interactions. In Cold Lake oil sands of northern Alberta, there is a large variation in δ11B of the produced waters generated during steam injection and recovery of oil and water. The higher temperature waters (∼ 200 °C) have isotopically light δ11B values (+ 3‰ to + 14‰) and high B contents (∼150 p.p.m.). It is inferred that the range of δ11B values of the hydrothermal fluids results from reaction with the reservoir rock, and is a function of the temperature of the fluid–rock interaction. The distinct B geochemistry of the produced waters can be used to show that there is no detectable mixing of the oil recovery waters with the regional formation waters or shallow groundwater aquifers containing potable water. Examination of B isotope ratios of reservoir minerals, before and after steam injection, allows the evaluation of sources of B in the reservoir. The only significant phase containing B is pumice. It shows generally positive δ11B values before steam injection and negative values after steam, with δ11B as low as − 28‰. Other possibly reactive phases include clay minerals and organic matter, but their abundance is not great enough to impact on the isotopic composition of the produced waters. This information makes it possible to evaluate the boron isotope fractionation equation derived from experimental data (Williams LB (2000) Boron isotope geochemistry during burial diagenesis. PhD Dissertation. The University of Calgary, Alberta, Canada; Williams LB, Hervig RL, Holloway JR, Hutcheon I (2001a) Boron isotope geochemistry during diagenesis: Part 1. Experimental determination of fractionation during illitization of smectite. Geochimica et Cosmochimica Acta, in press). The results show that the fractionation curve predicts the difference between δ11B of the pumice and hydrothermal fluids in the Cold Lake reservoir. This not only indicates that the reservoir fluids have approached boron isotope equilibrium with the reservoir rock, but also shows that B isotopes provide a useful geothermometer for hydrothermally stimulated oil reservoirs.

Transmission for an internal combustion engine

Abstract: In a transmission for an internal combustion engine including an oil sump and an oil pump operatively in communication with the oil sump, an oil reservoir is provided for receiving oil from the oil sump when the transmission is in direct drive and power is transmitted only through the main shaft of the transmission while the intermediate shaft is idling so that no friction is generated by the gears of the intermediate shaft being immersed in the oil of the oil sump.

Mapping permeable reservoir formations by measuring the elastic nonlinear interactions of a seismic wave as it propagates through the reservoir rock matrix and its pore fluids

Abstract: Permeability is one of the most important factors in influencing the commercial viability of a hydrocarbon reservoir. So far, permeability cannot be measured directly in-situ in reservoir formations. This invention relates to the field of estimating in-situ permeability of the reservoir rock formations. The measurements can be made across two wells or in a single well. Due to the morphology of their pore interconnections and the pore fluids in the rock, permeable rocks are elastically nonlinear. In a permeable rock, which is elastically nonlinear, the interactions between two elastic waves can be used in a unique way to map its physical properties. In this invention, the interaction of an elastic wave generated within the permeable rock with an externally generated seismic signal is used to determine the bulk tortuosity and bulk permeability of a reservoir rock formation.

Detection of Pay Zones and Pay Quality, Gulf of Mexico: Application of Geochemical Techniques

Abstract: Testing of stacked-sand pay zones in the Gulf of Mexico (GoM) and other basins with similar depositional systems (e. g., offshore Nigeria, Bohai Bay) is quite costly when up to 11 sands need to be evaluated in order to determine testing and completion intervals. Other reservoir types such as fractured shale, carbonate, and fresh water reservoirs present challenging interpretation problems as well, especially in terms of assessing native hydrocarbon quality prior to testing and completion. With high daily rig rates and test costs, the ability to minimize idle time and testing expenses has direct economic impact on the cost of operating a well. In addition, identifying any potential bypassed pay zones provides additional economic benefit. A variety of potential pay zone types is present in the GoM ranging from biogenic, thermogenic dry gas, wet gas, or condensate to normal, heavy, waxy, or biodegraded crude oils. Assessment of GoM sands is complicated by the fact that they are typically unconsolidated sediments and are often drilled with oil-based or synthetic muds, which make it difficult to evaluate the presence of reservoired hydrocarbons using conventional logging techniques. Simple and inexpensive geochemical analyses provide information on reservoir hydrocarbons directly from prospective reservoir rock samples in about 15 minutes, thereby enhancing well site decision-making processes. Geochemical analyses of frozen cuttings or sidewall core (SWC) samples confirm the presence of native hydrocarbons and provide an assessment of hydrocarbon type (gas or oil) and quality (e. g., GOR, viscosity, API gravity). The first goal of geochemical analyses for well site decision making is to identify or confirm prospective pay zones including any potential bypassed pay, in either water or oil-based mud systems. The second goal is to identify the likely type and quality of pay. Further, the comparison of condensates in rocks to produced fluids can be used to assess vertical fractionation of reservoirs, seal effectiveness, and for correlation or oil typing purposes. Finally, vertical connectivity of reservoirs, which may also play a role in completion decisions, can be assessed using these data.

Fluid–fluid and solid–fluid interfacial interactions in petroleum reservoirs

Abstract: The distribution and flow behavior of crude oil, gas and brine in the porous rock medium of petroleum reservoirs are controlled largely by the interactions occurring at the interfaces within the various fluids and by the interactions between the fluids and the rock surface. With an objective to correlate the macroscopic multiphase flow behavior with fundamental interfacial interactions, the recent developments in the field of fluid–fluid and solid–fluid interactions and their applications in petroleum engineering are presented in this contribution. A computerized drop shape analysis technique and its application to the measurement of fluid–fluid interfacial tension at elevated pressures and temperatures are discussed. A recently developed technique that is capable of measuring dynamic (advancing and receding) contact angles at realistic conditions encountered in petroleum reservoirs is presented. Its effectiveness in making reproducible and rapid measurements relative to the conventional techniques is dem...

Land Subsidence Spreading Factor of the Northern Adriatic Gas Fields, Italy

Abstract: The land subsidence spreading factor *** provides a useful straightforward indication on how much of a gas/oil reservoir compaction induced by field development migrate to ground surface with a possible adverse impact on the stability of low-lying coastal areas. This factor depends primarily on the ratio between the depth of burial and a representative horizontal dimension of the reservoir. However, an important influence is also exerted by the active bottom/lateral aquifer hydraulically connected to the field (called .waterdrive. in reservoir engineering) that may undergo an extensive depressurization also after the field abandonment, thus contributing to enhance the overall land settlement. In the Northern Adriatic basin, Italy, *** is evaluated using a nonlinear finite element model of three representative gas reservoir (Chioggia Mare, Dorotea, and Dosso degli Angeli) surrounded by important bottom/lateral aquifers in the interval depth between 1000 and 3300 m. Result show that . may easily approach and even exceed one for the deepest field as well, contrary to the prediction of land subsidence based on the compaction of the gas-bearing formations alone, that can thus be largely underestimated.

Acoustical imaging and mechanical properties of soft rock and marine sediments

Abstract: During this phase of the project the research team concentrated on acquisition of acoustic emission data from the high porosity rock samples. The initial experiments indicated that the acoustic emission activity from high porosity Danian chalk were of a very low amplitude. Even though the sample underwent yielding and significant plastic deformation the sample did not generate significant AE activity. This was somewhat surprising. These initial results call into question the validity of attempting to locate AE activity in this weak rock type. As a result the testing program was slightly altered to include measuring the acoustic emission activity from many of the rock types listed in the research program. The preliminary experimental results indicate that AE activity in the sandstones is much higher than in the carbonate rocks (i.e., the chalks and limestones). This observation may be particularly important for planning microseismic imaging of reservoir rocks in the field environment. The preliminary results suggest that microseismic imaging of reservoir rock from acoustic emission activity generated from matrix deformation (during compaction and subsidence) would be extremely difficult to accomplish.

Enhanced Reservoir Description of Heterogeneous Carbonate Reservoirs

Abstract: This study is conducted to test and evaluate the use of current methods of reservoir characterization, namely the permeability-prosity correlation, the J-function, and the Reservoir Quality Index (RQI) concepts, for reservoir description of heterogeneous carbonate formations. These approaches were compared with a new technique developed in this paper for improved reservoir description of carbonate reservoirs. This technique is called the Characterization Number (CN) technique and it is based upon considering fluid, rock, rock-fluid properties, and flow mechanices of oil reservoirs. To compare these reservoir characterization techniques, measurements of prosity, absolute permeability, oil and water relative permeability, and irreducible water saturation for 83 actual core samples extracted from eight different wells for a new oil reservoir in the U.A.E. were obtained. These experimental data are used first to developed a permeability-porosity correlation. Then, the J-function and the RQI concepts along with the newly developed CN approach are applied and evaluated for the reservoir description of the UAE carbonate reservoir under investigation. The results show that the Reservoir Quality Index concept is capable of identifying the flow units while the J-function concept is quite poor. Also, a more refined identification of flow units is obtained by using the newly-developed Characterization Number. This improved description for the Characterization Number approach may be attributed to the consideration of rock/fluid properties of flowing fluid(s) and flow dynamic conditions of its containing formation.

Unconformity-related chert/dolomite production in the Pennsylvanian Amsden Formation, Wolf Springs fields, Bull Mountains basin of central Montana

Abstract: Wolf Springs field (north and south pools) and South Wolf Springs field (a.k.a. Wolf Springs fields), located in Yellowstone County, Montana, were discovered in 1955 and 1957, respectively, and have produced more than 5.7 million bbl oil from the Pennsylvanian Amsden Formation. Amsden reservoir rocks in the area are fractured and brecciated cherts and dolomites that occur in several laterally persistent and mappable zones. The Amsden was deposited in a peritidal to sabkha setting where evaporite minerals, mainly anhydrite, were once common. These evaporites were partly replaced by silica (chalcedony and chert) soon after deposition. Later dissolution of the remaining evaporites soon after the silicification event, or during the pre-Middle Jurassic unconformity (PMJU), produced the solution-collapse chert breccias that now serve as the best reservoir facies in the field. Subtle variations in the diagenetic history of these breccias was a major factor in shaping reservoir quality. The Wolf Springs fields are unconformity-related combination structural and stratigraphic traps. The fields are located on a structural closure on the Custer anticline, where porosity and permeability development exhibit a northeast-southwest orientation perpendicular to structural strike of the anticline. The solution-collapse breccias pinch out laterally into either dense dolomites or anhydrite-plugged collapse breccias. The overlying shaly dolomite breccia of the Botts member (informal name) located just below the Piper unconformity and the Jurassic Piper Limestone provide an effective top seal. (Begin page 132) Understanding the geographic distribution of the chert/dolomite zones provides a key to exploration for these reservoirs. This must be coupled with analysis of available rocks and drillstem-test data and the integration of the regional hydrodynamic forces affecting the Amsden. These exploration tools should lead to the discovery of new Amsden reserves in the Bull Mountains basin and Central Montana platform.

Influences of asphaltene precipitation on capillary pressure and pore size distribution of carbonate reservoirs

Abstract: Asphaltene depositio n has profound effects on oil flow through porous medium. The investigation of the influences of asphaltene precipitation on carbonate reservoir rocks has minor interests in comparison to studies investigated sandstones ones. Therefore, this study is undertaken to provide accurate insights, especially for carbonate reservoirs of low permeability. In this study, two groups of experiments are undertaken. The first experimental group investigates effects of asphaltene precipitation on (a) petrophysical properties of carbonate rocks, including absolute permeability, effective porosity, and hydraulic radius, and (b) on oil-water relative permeability and water flooding performance. The second group searches for the effects of asphaltene precipitation on capillary pressure and pore size distribution of low permeability carbonate reservoirs. Conducted experiments are achieved using actual reservoir liquids of crude oil and brine, flowing through actual carbonate cores under similar reservoir...

3-D prestack depth migration in anisotropic media: A case study at the Lodgepole reef play in North Dakota

Abstract: A key problem in interpreting depth-migrated sections (prestack or poststack) is that seismic horizons almost never agree with well tops. Often, seismic events are on the order of 1000 ft deeper. Seismic anisotropy is mostly blamed for the discrepancy. In this paper, we show a case study at the Lodgepole reef play in North Dakota where, by incorporating strong seismic anisotropy in a 3-D velocity model, we can achieve good depth migration results and excellent well ties (within 50 ft). Our estimate of anisotropy parameters agrees with laboratory measurements on core samples. In 1996 Shell acquired 200 miles2 of 3-D seismic data in North Dakota to explore for Mississippian-age Lodgepole mounds. Structure in Williston Basin is relatively uncomplicated, but prospecting for subtle structures and for stratigraphic traps (which include the Lodgepole) is made more difficult by a number of geologic factors that affect both time and depth imaging. Exploration targets in the Lodgepole play (near Dickinson, North Dakota) lie at 9500-ft drill depths, about 1.9 s two-way time. The geologic section is relatively flat-lying and includes a broad range of lithologies and depositional environments. The upper half section is dominated by shales and sandstones and the lower half by carbonates. Typical succession and alternation of lithologies at a closer scale shows great variation. Numerous formations consist of anhydrite and halite, and in many areas salts have undergone partial or complete dissolution. The dissolution shows both time and areal variation, and the overlying formations carry this imprint into their original depositional and later diagenetic patterns. Other formations show significant lateral thickness variations due to sand dune distribution, or to local patterns of thins and thicks which result from widespread and intermittently active vertical fault systems interacting with frequent episodes of uplift and subsidence. Success in the Lodgepole exploration play has …

Modelling the progressive biodegredation of hydrocarbons trapped in an oil reservoir or trap, useful for determining the composition of oils in a deposit, comprises using the action of a bacterial population

Abstract: Modelling the progressive biodegredation of hydrocarbons trapped in a studied oil reservoir or trap, comprising: (a) dividing the reservoir into a net; and (b) iteratively adjusting the bacterial population in each mesh to the: (i) hydrocarbons available; (ii) available porous space; (iii) electron acceptors present; and (iv) degradation capacity of the bacteria, is new. Modelling the progressive biodegredation of hydrocarbons trapped in a studied oil reservoir or trap, comprising: (a) dividing the reservoir into a net where the height of each mesh is the thickness of the water/oil transaction zone; and (b) determining the proportion of heavy hydrocarbons in the reservoir by iteratively adjusting the bacterial population in each mesh to the: (i) hydrocarbons available; (ii) available porous space; (iii) electron acceptors present; and (iv) degradation capacity of the bacteria, is new.