Showing papers on "Petroleum reservoir published in 2008"

Wettability Determination of the Reservoir Brine−Reservoir Rock System with Dissolution of CO2 at High Pressures and Elevated Temperatures

Abstract: An experimental method has been developed to determine the wettability, i.e., the contact angle, of a reservoir brine−reservoir rock system with dissolution of CO2 at high pressures and elevated temperatures by using the axisymmetric drop shape analysis (ADSA) technique for the sessile drop case. Prior to the experiment, a rock slide is horizontally placed in a specially designed rock slide holder in a see-through windowed high-pressure cell, which is subsequently filled with CO2 at a prespecified pressure and a constant temperature. Then, a reservoir brine sample is introduced by using a syringe delivery system to form a sessile brine drop on the rock slide inside the pressure cell. The sequential digital images of the dynamic sessile brine drop are acquired and analyzed by applying computer-aided image acquisition and processing techniques to measure the dynamic contact angles at different times. It is found that the dynamic contact angle between the reservoir brine and the reservoir rock remains almost...

Rock Typing: Keys to Understanding Productivity in Tight Gas Sands

Abstract: This paper presents a work-flow process to describe and characterize tight gas sands. The ultimate objective of this work-flow is to provide a consistent methodology to systematically integrate both large-scale geologic elements and small-scale rock petrology with the physical rock properties for low-permeability sandstone reservoirs. To that end, our work-flow integrates multiple data evaluation techniques and multiple data scales using a core-based rock typing approach that is designed to capture rock properties characteristic of tight gas sands. Fundamental to this process model are identification and comparison of three different rock types — depositional, petrographic, and hydraulic. These rock types are defined as: ● Depositional — These are rock types that are derived from core-based descriptions of genetic units which are defined as collections of rocks grouped according to similarities in composition, texture, sedimentary structure, and stratigraphic sequence as influenced by the depositional environment. These rock types represent original large-scale rock properties present at deposition. ● Petrographic — These are rock types which are also described within the context of the geological framework, but the rock type criteria are based on pore-scale, microscopic imaging of the current pore structure — as well as the rock texture and composition, clay mineralogy, and diagenesis. ● Hydraulic — These are rock types that are also defined at the pore scale, but in this case we define "hydraulic" rock types as those that quantify the physical flow and storage properties of the rock relative to the native fluid(s) — as controlled by the dimensions, geometry, and distribution of the current pore and pore throat structure. Each rock type represents different physical and chemical processes affecting rock properties during the depositional and paragenetic cycles. Since most tight gas sands have been subjected to post-depositional diagenesis, a comparison of all three rock types will allow us to assess the impact of diagenesis on rock properties. If diagenesis is minor, the depositional environment (and depositional rock types) as well as the expected rock properties derived from those depositional conditions will be good predictors of rock quality. However, if the reservoir rock has been subjected to significant diagenesis, the original rock properties present at deposition will be quite different than the current properties. More specifically, use of the depositional environment and the associated rock types (in isolation) to guide field development activities may result in ineffective exploitation.

Method for increased 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.

Comparison of high/low salinity water/oil relative permeability

Abstract: There is much published data in the literature showing that waterflood recovery is dependent on the composition, especially the salinity, of the injection brine. Some of this published data have shown the characteristics of coreflood tests at reduced conditions with dead crude and brines. Relatively few have discussed tests performed at reservoir conditions with live fluids. This paper describes characteristics of full reservoir condition waterfloods with live crude oil and brines (both high and low salinity) on reservoir plug samples from many global oil producing basins. Experimental procedures and reservoir condition waterflood characteristics are presented in this paper from both secondary (low salinity injection into a plug sample at initial water saturation (Swi)) and tertiary injection (low salinity injection into samples which have already seen high salinity injection). This simulates both low salinity injections in new waterfloods and also in mature waterfloods. Fully interpreted reservoir condition water/oil relative permeability are also presented. High and low salinity relative permeability data measured on the same reservoir rock types are compared from similar Swi values. The characteristics of injecting low salinity brines after high salinity waterfloods are also discussed.

Methods for optimizing petroleum reservoir analysis

Abstract: Described herein are methods for optimizing petroleum reservoir analysis and sampling using a real-time component wherein heterogeneities in fluid properties exist. The methods can help predict the recovery performance of oil such as, for example, heavy oil, which can be adversely impacted by fluid property gradients present in the reservoir.

An overview of reservoir quality in producing Cretaceous strata of the Middle East

Abstract: A compilation of average porosity and permeability data for Cretaceous petroleum reservoirs of the Middle East reveals important differences between the two main tectonic provinces. The Arabian Platform is characterized by inverse correlation of average porosity with burial depth in both carbonates and sandstones, whereas the Zagros Fold Belt (almost exclusively carbonates) has distinctly lower porosity and no depth correlation. These contrasts are suggested to reflect the fact that Arabian Platform strata are mostly near their maximum burial depth, whereas Zagros strata have experienced varying uplift and erosion following maximum burial in mid-Tertiary time. The carbonate reservoirs show no correlation between average porosity and average permeability, probably because of wide differences in the dominant pore types present, and permeabilities tend to be much higher for sandstones than for carbonates. Existence of the Arabian Platform porosity–depth correlation, despite an apparently wide diversity of depositional settings and early diagenetic porosity modifications among the individual reservoirs, illustrates and confirms some fundamental generalities about how burial diagenesis controls the overall porosity evolution of reservoir rock bodies. Although porosity commonly shows enormous small-scale heterogeneity in both carbonates and sandstones, the average pre-burial porosity of larger stratigraphic intervals tends to be very high. Burial diagenesis progressively destroys this porosity by chemical compaction and associated (stylolite-sourced) cementation. Thus, all portions of the affected rock body move toward the zero limit as depth increases, although the rates of porosity occlusion vary greatly, depending on rock fabric and early diagenesis. Average reservoir porosity therefore tends to correlate inversely with maximum burial depth, regardless of initial lithological heterogeneity.

Method for determining the properties of hydrocarbon reservoirs from geophysical data

Abstract: A hydrocarbon exploration method is disclosed for developing a model of at least one effective material property of a subsurface reservoir as a function of the composition and structure of the reservoir rock. In one embodiment, the method comprises: obtaining a 3D image (102) of a rock sample characteristic of a reservoir of interest (101); segmenting the 3D image into compositional classes (103) based on similarities in mineralogy, structure and spatial distribution; selecting a model (105) that relates an effective material property of interest to the volume fractions of each compositional class; and determining the parameters of the model (106). The model may be used to assess the commercial potential of the subsurface reservoir (107).

Method for determining volume of organic matter in reservoir rock

Abstract: A method for calculating the volume of various predetermined organic end-members in samples of rock at various depths in oil reservoir rock is utilized to produce one or more graphic displays that are use to interpret the data to identify, eg, tar mats, in order to improve the efficient production of hydrocarbons from the well Data is collected from the samples by known pyrolysis and compositional modeling methods; additional data is obtained by elemental analysis to determine weight percentages of C, H, N, S and O in the selected end-members and characterization of physical properties of representative samples of the reservoir rock, eg, from core samples; the data is then processed in accordance with the method to provide a series of data points used to produce the graphic displays for visual interpretation

Gas evolving oil viscosity diminishing compositions for stimulating the productive layer of an oil reservoir

Abstract: The invention is directed to a chemical system of gas evolving oil viscosity diminishing compositions (GEOVDC) for stimulating the productive layer of an oil reservoir, that is to chemical compositions for a thermochemical treatment of an oil reservoir, more specifically for initiating a chemical reaction in the productive layer zone of the oil reservoir to produce heat and evolve gases so that the extraction of oil (petroleum) is improved. The invention is further directed to a method of thermochemically treating an oil reservoir by means of this chemical system, and to an apparatus for performing thermochemical treatment of an oil reservoir.

Reservoir potential of a lacustrine mixed carbonate / siliciclastic gas reservoir: the lower triassic rogenstein in the netherlands

Abstract: 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 (φ= 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.

Analysis of stress sensitivity and its influence on oil production from tight reservoirs

Abstract: This paper presents a study of the relationship between permeability and effective stress in tight petroleum reservoir formations. Specifically, a quantitative method is developed to describe the correlation between permeability and effective stress, a method based on the original in situ reservoir effective stress rather than on decreased effective stress during development. The experimental results show that the relationship between intrinsic permeability and effective stress in reservoirs in general follows a quadratic polynomial functional form, found to best capture how effective stress influences formation permeability. In addition, this experimental study reveals that changes in formation permeability, caused by both elastic and plastic deformation, are permanent and irreversible. Related pore-deformation tests using electronic microscope scanning and constant-rate mercury injection techniques show that while stress variation generally has small impact on rock porosity, the size and shape of pore throats have a significant impact on permeability-stress sensitivity. Based on the test results and theoretical analyses, we believe that there exists a cone of pressure depression in the area near production within such stress-sensitive tight reservoirs, leading to a low-permeability zone, and that well production will decrease under the influence of stress sensitivity.

Upper Jurassic updip stratigraphic trap and associated Smackover microbial and nearshore carbonate facies, eastern Gulf coastal plain

Abstract: The development of Little Cedar Creek field in the eastern Gulf coastal plain of the United States has shown that the current exploration strategy used to find hydrocarbon-productive microbial and high-energy, nearshore carbonate facies in the Upper Jurassic Smackover Formation requires refinement to increase the probability of identifying and delineating these potential reservoir facies. In this field, the petroleum trap is a stratigraphic trap characterized by microbial boundstone and packstone and nearshore grainstone and packstone reservoirs that are underlain and overlain by lime mudstone and dolomudstone to wackestone and that grade into lime mudstone and dolomudstone near the depositional updip limit of the Smackover Formation. Reservoir rocks trend from southwest to northeast in the field area. The grainstone and packstone reservoir is thickest in the central part of the field. The boundstone reservoir is thickest in local buildups that are composed of thrombolites in the southern part of the field and is absent along the northern margin. These reservoir facies are interpreted to have accumulated in water depths of approximately 3 m (10 ft) and in 5 km (3 mi) of the paleoshoreline. In contrast to most other thrombolites identified in the Gulf coastal plain, these buildups did not grow directly on paleohighs associated with Paleozoic crystalline rocks. The characterization and modeling of the petroleum trap and reservoirs at Little Cedar Creek field provide new information for use in the formulation of strategies for exploration of other Upper Jurassic hydrocarbon productive microbial and related facies associated with stratigraphic traps in the Gulf coastal plain.

Behavior of Flow Through Low-Permeability Reservoirs

Abstract: While pores and throats of low-permeability reservoir rock are very tiny, they have significant influence on flow behavior in those reservoirs. There may be large differences in throat sizes and their distribution in low-permeability formations, even though they have similar storage space and flowing channels. Equivalent radii of flowing throats for low-permeability reservoirs with similar permeabilities may be very different. Stronger liquid-solid interaction within finer pore throats having a large interface area and abundant hydrophilic clay tends to prevent water from flowing through. This paper presents a systematic study of flow behavior in low-permeability reservoirs using (1) a constant-rate mercury injection test, (2) a nuclear magnetic resonance (NMR) core analysis, and (3) a seepage experiment. NMR results show that mobile fluid saturation in low-permeability formations is very different from that in normal reservoirs. In general, the less clay content and larger throat radii of the low-permeability rock, the larger the mobile fluid saturation. We conducted a series of seepage tests, with the results showing that at low velocity, the flow rate in low-permeability rock is not linearly correlated with pressure gradient, but rather is a function of pressure gradient. Based on experimental results, we propose a modified Darcy's law for describing the observed nonlinear flow phenomenon, which is implemented into a black-oil model simulator. Simulation results incorporating the nonlinear flow-behavior show that effective permeability near production and injection wells is higher, whereas the permeability further away from the wells is lower. Well performance predicted by the linear model overestimates production rates, while that predicted by the new, nonlinear model better matches the field production data.

Chapter 9 – Coal as a Petroleum Source Rock and Reservoir Rock

Abstract: Publisher Summary Coal is defined as a rock composed of more than 50% organic matter by weight and is thus by definition the rock type that is richest in organic matter. For this reason, coal is considered an important petroleum source rock, and the ways in which petroleum compounds can be generated and expelled from coal is a subject of vigorous debate. Coal is also an important reservoir for natural gas, and gaseous hydrocarbons produced from coal are commonly referred to as coalbed methane. Coal also contains significant quantities of other gases, such as carbon dioxide and nitrogen. These gases occur in coal naturally, and the potential exists to inject gases into coal for environmental and economic benefit. The chapter explains that coal contains diverse forms of organic matter spanning a broad range of chemical composition, and this compositional variability combined with geologic history determine what types of hydrocarbons can be generated.

Examination of the Importance of Self Diffusion in the Transportation of Gas in Shale Gas Reservoirs

Abstract: Since gas is very compressive, a gradient in gas pressure directly results in a gradient in gas concentration. In other words diffusive and advective transport processes are coupled. In the following, the coupled transport equations are written in terms of an effective transport coefficient that is the sum of a permeability term and a diffusion term. The relative values of these terms are evaluated for shale gas reservoir rocks both under temperature and pressure conditions typical of Bamett shale reservoirs. Measurements in the laboratory are also discussed. Evaluation of the diffusion term for Bamett type shale gas reservoirs shows that self diffusion in the gas phase is not an important transport process except for the lowest permeability rocks.

Characteristics and genetic mechanism of deep-buried clastic eureservoir in China

Abstract: Systematic researches to the clastic reservoirs in various types and various geological ages basins in China indicate that the present burial depth of deep buried clastic eureservoir ranges from 3000 to 6000 m, and its geological ages from Paleozoic, Mesozoic to Cenozoic. It mainly deposited in delta (including braid delta, fan delta, normal delta), river, also shore, shallow lake, gravity flow channel and turbidity fan facies. The quartzose sandstone is the main reservoir rock of deep-buried clastic eureservoir in the shore facies in Paleozoic, but the arenite and arkose sandstones are the main reservoir rock types in delta, river, shallow lake and gravity flow facies in Mesozoic and Cenozoic. The porosity of most of deep-buried clastic eureservoir is more than 10% and permeability more than 10×10−3 μm2. The formation of the deep-buried eureservoir was related to the paleotectonics, paleotemperature, sedimentary environment, the deep dissolution caused by organic acid or carbonic acid, burial style, the abnormal high pore fluid pressure, early hydrocarbon charging, gyprock sealing, hot convective fluid flow and the mode of sand-mud interbedded, etc. The paleotectonics controls the burial style of sandstones, and the paleotemperature controls the diagenesis process. The sedimentary environment is the precondition and foundation, the dissolution is the direct reason to generate the deep buried clastic eureservoir. The abnormal high pore fluid pressure, gyprock sealing, the mode of sand-mud interbedded, early hydrocarbon charging and the structure fractures were the assistant factors of generating the deep buried clastic eureservoir.

Geochemical aureoles around oil and gas accumulations in the zechstein (upper permian) of poland: analysis of fluid inclusions in halite and bitumens in rock salt

Abstract: Fluid inclusions in halite and bitumens in rock salt in Upper Permian Zechstein evaporites in West Poland were studied in locations where the evaporites lie above oil and gas reservoir rocks. The samples were taken from halite intercalated within the Basal Anhydrite; this unit lies above the Main Dolomite which serves as both source rock and reservoir. Samples came from a depth of 2.3–3.2 km. A characteristic feature of the fluid (gas-brine) inclusions was their high methane content together with the occasional presence of bitumen globules of near-spherical form. Geochemical analyses of the bitumen in bulk samples of rock salt (including content and distribution of n-alkanes and isoprenoids, and carbon isotope ratios) suggest an algal origin, similar to that of the oil in the underlying source rocks. For comparison, we studied fluid inclusions in halite from Zechstein evaporites in northern Poland, where hydrocarbon accumulations do not occur in underlying strata and where mostly single-phase (brine) inclusions with a low methane content have been recorded. However, published data indicate that similar inclusions to those occurring in the Zechstein of West Poland (comprising brine with a high methane content, bitumen films and/or oil droplets) are present in other salt-bearing sequences, where their origin is related to the thermal degradation of organic material dispersed within the salt itself. Accordingly, such fluid inclusions in an evaporite succession can only be considered to form a geochemical aureole where the bitumens in the rock salt (including those in the fluid inclusions in halite) can be compositionally linked to those in the associated oil accumulation.

Primär och sekundär migration av hydrokarboner

Abstract: The purpose of this literature study is to explain the primary and secondary migration of hydrocarbons. Primary migration is the process when hydrocarbons, after their maturation in the source rock, are migrating to the reservoir rock. The main reason for primary migration is supposed to be cracking within the source rock or transportation with subsurface waterflows acting to a depth of about 2000 m. In the reservoir rock the secondary migration takes place where the hydrocarbons under favourable conditions may get trapped. The movement of hydrocarbons in the reservoir is due to density differences, float-force and capillary pressure. Some cases in the North Sea, Norwegian Sea and Baltic Sea have also been examined and their evolution described. The study has shown there are differences in the basin history.

The Khazzan gas accumulation, a giant combination trap in the Cambrian Barik Sandstone Member, Sultanate of Oman: Implications for Cambrian petroleum systems and reservoirs

Abstract: Khazzan is a giant tight-gas accumulation located in northern Oman. The accumulation is associated with Cambrian Barik Sandstone Member reservoirs, in a semiregional combination (stratigraphic-structural) trap. This article outlines the background to the discovery of Khazzan and describes our understanding of its geology and petroleum systems and the study work used to support screening, appraisal, and development strategies for the Khazzan accumulation. The stratigraphic element of the trap is associated with a northerly thinning and transition of continental, fluvial braid-plain and shoreface sandstones into offshore mud rocks. The structural element of the trap formed as a result of the compactional drape of these reservoir units and the later structuring associated with an underlying, long-lived intrabasin high. The integration of multiple correlation techniques (well-log correlation, recognition of changes in core facies and ichnofacies and magnetostratigraphy) has helped to define an intrareservoir correlation framework for the Barik Sandstone Member, with a resolution of approximately less than or equal to 1 m.y., allowing detailed insights into stratigraphic and areal controls on hydrocarbon compositional variations, trapping mechanisms, reservoirs, and reservoir connectivity. Fluvial sandstones within the Khazzan stratigraphic pinch-out form better reservoirs. The stratigraphic framework developed indicates that these fluvial units are associated with discrete, geographically extensive, progradation events. The association of production with discrete reservoir levels and areas allows a robust semipredictive regional model for targeting better reservoirs and highlights a scope for an additional intra-Barik stratigraphic trapping potential regionally. Enhanced reservoir quality within the more productive reservoirs is attributed to depositional and possibly hydrocarbon charge controls on secondary porosity, and it is complex. Subtle crest-to-flank compositional variations in hydrocarbon type across the gas accumulation hint at complex hydrocarbon charge and mixing between two structural domains and petroleum systems before and during Barik deposition. John Millson holds a B.Sc. (honors geology) degree and a Ph.D. from Aston University in Birmingham, United Kingdom and the University of Wales, Abersytwyth. Joining the oil industry as a petroleum geologist in 1985, he has worked in the United Kingdom, Nigeria, Netherlands, and Oman, with some 11 years of working on various aspects of the geology of Oman. His main interests include tectonostratigraphy and unconventional hydrocarbon resources. Jamie Quin is a geologist for Statoil-Hydro. Since joining the oil industry in 2001, he has worked on assets in Oman (for Badley Ashton and Associates), Libya (for Repsol YPF), and Norway (Statoil). He holds a B.Sc. degree from the University of Glasgow, an M.Sc. degree from Royal Holloway, University of London, and a Ph.D. from Trinity College Dublin. Erdem Idiz is currently a global exploration adviser for Exploration New Ventures with Shell International Exploration and Production in the Netherlands. He received his M.Sc. degree in geology (1981) and Ph.D. in geochemistry (1987) from the University of California, Los Angeles (UCLA). After a postdoctorate at the Institut Francais du Petrole, he joined Shell in 1988, working in research and applications as a geochemist and basin modeler in the Netherlands, Germany, and Canada. His research interests are petroleum systems analysis, biomarkers, and stable isotopes. Peter Turner holds degrees from Cardiff and Leicester Universities and was a reader in earth sciences at the University of Birmingham in the United Kingdom from 1988 to 2006 where he was head of the Petroleum Geoscience Group. His research includes paleomagnetism, sedimentology, and hydrocarbon reservoirs, and since retiring from university life, he has worked as a full-time consultant focusing on exploration in north and west Africa and China. No details available.

The Effect of Geologic Parameters and Uncertainties on Subsurface Flow: Deepwater Depositional Systems

Abstract: The application of reservoir simulation as a tool for reservoir development and management is widespread in the oil and gas industry. Moreover, it is recognized that the results of any reservoir simulation model are strongly influenced by the underlying geologic model. However, the direct relationship between geologic parameters and subsurface flow is obscure. In this paper we explore this relationship in a deepwater depositional system using data from two reservoir analogs: the shallow seismic dataset from the Mahakam Fan and outcrop data from the Brushy Canyon Formation of West Texas. Shallow seismic data from the Mahakam Fan area shows a high-resolution deepwater channel-levee system consisting of 10 migrating channels. Using an experimental design framework and a series of three increasingly complex models, we investigated the effect of nine different geologic factors on several different measures of the flow behavior. Our results show that, as expected, different geologic factors influence different measures of the flow. Most significant is the clear effect that the proportion and organization of the different internal facies making up the channels have on the recovery factor and net oil production. The Brushy Canyon outcrops used in this work represent sand-rich proximal deposits of a distributary lobe complex. Here we built models on a very small length scale to investigate the effects of sheet-like reservoir architecture as well as internal facies distribution of the sheets on subsurface flow. Again, an experimental design framework was employed, this time to examine the influence of 11 input variables. The proportion and organization of the internal lobe facies has a significant influence on the subsurface flow here but in these distributary lobe complexes other variables, including the stacking of the lobes, were also found to be important. The models in this study address flow behavior in deepwater, sparse well environments. Using models from the simple to the complex, we found that several parameters incorporated in the complex models, and not in simple models, had a significant impact on the predicted flow. Introduction The use of reservoir modeling and simulation is common in the oil and gas industry. Indeed, virtually every major oil and gas reservoir is studied or managed using earth modeling and reservoir simulation. Nevertheless, the relationship between input geologic elements and subsurface flow is not generally obvious. The objective of this work is to examine this relationship in detail for deepwater depositional settings. The link between geology and subsurface flow has been examined extensively in the literature. For example, Larue and coworkers have looked at fluvial systems using both conceptual models and the Meren reservoir. They examined a large number of models in an effort to investigate the largest possible variety of geologic interpretations and found a very wide range of resulting behavior (200% variation in breakthrough time and a factor of two variation in oil recovery). They also established that less ‘complex’ models could be built and capture the full range of subsurface performance results in their study. In another example, Jones and co-workers looked at both low and high net-to-gross fluvial reservoirs. In their study of low

Characteristics and Genetic Type of the Oils in the Tazhong Uplift

Abstract: The central uplift of Tarim Basin (Tazhong Uplift) has become a hot exploration target in western China. Totally 104 oil samples were sampled and analyzed by conventional geochemical as well as compound specific isotopic approaches. The oil were divided into four genetic types. Type-Ⅰ is characterized by relatively heavier values of n-alkanes carbon isotope (-29.6‰~-29.1‰) , and generally a reversed "L" shape of relative abundance of C27, C28 and C29 regular steranes with 4-metyl sterane and dinosteranes as well as gammacerane relatively enriched whereas diasteranes and diahopanes less developed. This type of oil shares typical features of Cambrian-low Ordivican derived oil (TD2, ∈-O1) in the Tarim basin. Type-Ⅱ has relatively lighter carbon isotope values of n-alkanes (-34‰~-35.6‰), and is poor in dinosteranes with "V" shape of C27, C28 and C29 regular steranes. This type of oil correlates well middle-upper Ordovician derived oil (YM2, O1) in the basin. Type-Ⅲ is distinguished from other oils by completely high concentrations of dibenzothiophene, which was primarily situated in TZ4 and TZ1-6 Blocks. Type-Ⅳ is mixed oil of type-Ⅰ and Ⅱ, and characterized by an intermediate carbon isotope value of type-Ⅰ and Ⅱ. This type oil is predominant in amount and widely distributed in the Tazhong Uplift. Oil -oil correlations showed that the oil analyzed was sourced from at least two sets of source rocks (i.e., ∈-O1 and O2+3 , respectively). The un-consistency of the biomarkers (indicating ∈-O1 genetic affinity ) and the compound specific compounds of n-alkanes (indicating more of O2+3 genetic affinity ) in some oils analyzed indicates that the oils were widely mixed with different sources. The physical and chemical properties of the oils vary with tectonic belt and horizons suggest such typical characteristics of composite basin as multi-source and multi-stage of hydrocarbons migration and accumulation of the oils as well as obvious heterogeneities of carbonatite reservoir rock. The oil-mixing model suggested in this study is significant for further oil exploration.

The Mississippian Leadville Limestone Exploration Play, Utah and Colorado-Exploration Techniques and Studies for Independents

Abstract: The Mississippian (late Kinderhookian to early Meramecian) Leadville Limestone is a shallow, open-marine, carbonate-shelf deposit. The Leadville has produced over 53 million barrels (8.4 million m{sup 3}) of oil/condensate from seven fields in the Paradox fold and fault belt of the Paradox Basin, Utah and Colorado. The environmentally sensitive, 7500-square-mile (19,400 km{sup 2}) area that makes up the fold and fault belt is relatively unexplored. Only independent producers operate and continue to hunt for Leadville oil targets in the region. The overall goal of this study is to assist these independents by (1) developing and demonstrating techniques and exploration methods never tried on the Leadville Limestone, (2) targeting areas for exploration, (3) increasing deliverability from new and old Leadville fields through detailed reservoir characterization, (4) reducing exploration costs and risk especially in environmentally sensitive areas, and (5) adding new oil discoveries and reserves. The final results will hopefully reduce exploration costs and risks, especially in environmentally sensitive areas, and add new oil discoveries and reserves. The study consists of three sections: (1) description of lithofacies and diagenetic history of the Leadville at Lisbon field, San Juan County, Utah, (2) methodology and results of a surface geochemical survey conducted over the Lisbon and Lightning Draw Southeast fields (and areas in between) and identification of oil-prone areas using epifluorescence in well cuttings from regional wells, and (3) determination of regional lithofacies, description of modern and outcrop depositional analogs, and estimation of potential oil migration directions (evaluating the middle Paleozoic hydrodynamic pressure regime and water chemistry). Leadville lithofacies at Libon field include open marine (crinoidal banks or shoals and Waulsortian-type buildups), oolitic and peloid shoals, and middle shelf. Rock units with open-marine and restricted-marine facies constitute a significant reservoir potential, having both effective porosity and permeability when dissolution of skeletal grains, followed by dolomitization, has occurred. Two major types of diagenetic dolomite are observed in the Leadville Limestone at Lisbon field: (1) tight 'early' dolomite consisting of very fine grained ( 100-250 {micro}m), rhombic and saddle crystals that discordantly replace limestone and earlier very fine grained dolomite. Predating or concomitant with late dolomite formation are pervasive leaching episodes that produced vugs and extensive microporosity. Most reservoir rocks within Lisbon field appear to be associated with the second, late type of dolomitization and associated leaching events. Other diagenetic products include pyrobitumen, syntaxial cement, sulfide minerals, anhydrite cement and replacement, and late macrocalcite. Fracturing (solution enlarged) and brecciation (autobrecciation) caused by hydrofracturing are widespread within Lisbon field. Sediment-filled cavities, related to karstification of the exposed Leadville, are present in the upper third of the formation. Pyrobitumen and sulfide minerals appear to coat most crystal faces of the rhombic and saddle dolomites. The fluid inclusion and mineral relationships suggest the following sequence of events: (1) dolomite precipitation, (2) anhydrite deposition, (3) anhydrite dissolution and quartz precipitation, (4) dolomite dissolution and late calcite precipitation, (5) trapping of a mobile oil phase, and (6) formation of bitumen. Fluid inclusions in calcite and dolomite display variable liquid to vapor ratios suggesting reequilibration at elevated temperatures (50 C). Fluid salinities exceed 10 weight percent NaCl equivalent. Low ice melting temperatures of quartz- and calcite-hosted inclusions suggest chemically complex Ca-Mg-bearing brines associated with evaporite deposits were responsible for mineral deposition. The overall conclusion from these analyses indicates late dolomitization, saddle dolomite, and dolomite cement precipitation, as well as sulfides and brecciation, may have developed from hydrothermal events that can greatly improve reservoir quality. The result can be the formation of large, diagenetic-type, hydrocarbon traps. The reservoir characteristics, particularly diagenetic overprinting and history, can be applied regionally to other fields and exploration trends in the Paradox Basin. Stable carbon and oxygen isotope data indicate that all Lisbon field Leadville dolomites were likely associated with brines whose composition was enriched in {sup 18}O compared with Late Mississippian seawater. The Leadville replacement dolomite's temperatures of precipitation ranged from about 140 to 194 F ({approx} 60 to 90 C). Saddle dolomite cements were precipitated at temperatures greater than 194 F (>90 C).

Experimental and Empirical Observations Supporting a Capillary Model Involving Gas Generation, Migration, and Seal Leakage for the Origin and Occurrence of Regional Gasifers

Abstract: Low-permeability reservoirs in which gas is the regionally continuous phase (gasifers) occur over large areas in the Alberta Basin in Canada and the Rocky Mountain basins in the United States. These tight-gas reservoirs have also been called deep basin and basin-centered gas systems and contain very large resources of natural gas. Observation and theory show that a gasifer, or a regional low-permeability gas system, can be developed in a four-stage process: genesis, transition, steady state, and imbibition. This process involves the generation, migration, and leakage of gas, accompanied by the regional dewatering of the system, even in the siltstones and shales. The genesis stage contains both conventional gas pools, early in the development of the gasifer, and unconventional gas pools later. Late genesis gas pools are characterized by tall gas columns, with normal downdip apparent gas–water contacts. These tall gas columns generate enough capillary pressure to drain very low-permeability reservoirs and establish gas as the continuous fluid over a very large part of the basin. At this point, the gasifer is developed. The transition stage has normal and underpressured gas, with tall columns that crosscut waterlines on pressure-versus-elevation plots. In the steady-state stage, gas is underpressured, and the tall gas columns have updip gas–water contacts. The imbibition stage marks the decline of the gasifer and is characterized by shorter, underpressured gas columns and underpressured waterlines. Laboratory experiments based on a simple capillary tube model support the four-stage development of the regional low-permeability gas system and defined both a normally pressured and overpressured gas–water system in the genesis stage. These experiments demonstrated that the mechanism for the underpressuring of the gasifer in the transition and steady-state stages was gas leakage, which confirmed the conclusions based on capillary theory. The combination of the empirical approach using pressure-versus-elevation plots and the capillary theory with the laboratory experiments leads to several interesting concepts. For example, a regional low-permeability gas system can be viewed as a source rock undergoing primary migration. Gas generation may be thermal or biogenic. Therefore, this four-stage process would also apply to the shallow biogenic gasifers in the Milk River and Horseshoe Canyon formations in southern and central Alberta. The genesis stage will contain some moveable water, and there will be an overprint of structural and stratigraphic traps with higher water production downdip. Reservoirs in the genesis stage will have variable water saturations, and therefore, relative permeability should be a concern. A basin may have any one of these stages well developed, or all four may be present at various levels of development, as is the case for the Alberta deep basin. By knowing the stages, the gasifer can be defined, and an effective exploration strategy can be developed.