Showing papers on "Petroleum reservoir published in 1992"

Geological Applications of Capillary Pressure: A Review

Abstract: Capillary pressure concepts can be used to evaluate reservoir rock quality, expected reservoir fluid saturations and depths of fluid contacts, thickness of transition zone, seal capacity, and pay versus nonpay, and to approximate recovery efficiency. Mercury-injection capillary pressure is typically favored for geological applications, such as inferring the size and sorting of pore throats. The differences between mercury injection and withdrawal curves can provide information on recovery efficiency. The height above free water level can be determined by comparing capillary pressure data to hydrocarbon shows and measured fluid saturations. Capillary pressure data can also be used to distinguish reservoir from nonreservoir rocks and pay from nonpay on the basis of nonwetti g-phase saturations. Other applications of capillary pressure data include relating capillary pressure to absolute and relative permeabilities, and using porosimetry to investigate pore-level heterogeneity. This paper reviews geological applications and interpretation of capillary pressure in reservoir studies.

The Geological modelling of hydrocarbon reservoirs and outcrop analogues

Abstract: Part 1 Quantitative data collection: quantitative clastic reservoir geological modelling - problems and perspectives alluvial architecture in a sequence stratigraphic framework - a case history from the upper cretaceous of southern Utah, USA sedimentary architecture of field analogues for reservoir information (SAFARI): a case study of the fluvial Escanilla formation, Spanish Pyrenees quantitative facies analysis of coal-bearing sequences in the Bowen basin, Australia - applications to reservoir description quantification of turbidite facies in a reservoir analogous submarine-fan channel sandbody, southern-central Pyrenees, Spain outcrop studies of shale smears on fault surfaces predicting reservoir sandbody orientation from dipmeter date - the use of sedimentary dip profiles form outcrops applications of the formation micro-scanner to modelling of Palaeozoic reservoirs in Oman permeability patterns in point bar deposits - Tertiary Loranca basin, central Spain knowledge base development for the estimation of reservoir rock properties in the interwell area - examples from the Texas Gulf coast. Part 2 Modelling methods: sedimentary flow units in hydrocarbon reservoirs - some shortcomings and a case for high-resolution permeability data the use of 3-D seismic in reservoir geological modelling the use of length distributions in geological modelling a theoretical study of fluvial sandstone body dimensions stochastic modelling of fluvial sandstone bodies a 3-D modelling approach for providing a complex reservoir description for reservoir simulations.

The Paleozoic Petroleum Geology of Central Arabia

Abstract: Exploratory drilling in central Saudi Arabia has established significant Paleozoic petroleum potential in this region. In recent discoveries, the Permian interval of the Unayzah Formation has been identified as the primary oil and gas reservoir. The Unayzah Formation consists of alluvial and fluvial to shallow marine siliciclastic sandstones and siltstones that were deposited on a major pre-Unayzah unconformity. Saudi Arabian Paleozoic oil is a high-gravity (43-53 degrees API) crude with low sulfur content (usually less than 0.07%) that is classified as Arabian Super Light oil. Gas with condensate has also been discovered in the Unayzah Formation. The identified Paleozoic traps are moderate-relief, fault-generated structures, with generally 30-100 m of closure. Unayzah structural traps developed primarily during the Triassic to Early Jurassic; however, an earlier phase of significant pre-Unayzah structural development is also indicated between the Devonian and Late Carboniferous, and is related to a "Hercynian" structural event. Post-Triassic structure in central Arabia is mainly regional and results principally from Late Cretaceous to Tertiary development of the Central Arabian arch. The established source rock is the basal Qusaiba Shale, a widespread organic-rich shale that was deposited following regional deglaciation in the Early Silurian. Migration occurred regionally updip through Unayzah Formation reservoirs from the underlying Qusaiba Shale subcrop and/or vertically along fault-bounded zones on the flanks of structures from the underlying Qusaiba Shale. Interbedded Upper Permian shales and evaporites provide a top seal for the Unayzah and form the basal sequence of the overlying transgressive Khuff carbonate. Pre-Qusaiba reservoir targets include the Cambrian-Ordovician Saq Sandstone, the Ordovician Qasim Formation, and Upper Ordovician to Lower Silurian periglacial clastics of the Zarqa and Sarah formations. High-gravity, low-sulfur oil has also been discovered in this pre-Qusaiba clastic section. The reservoirs of the pre-Qusaiba structures are fault bounded and sources laterally by the down-faulted Qusaiba Shale.

New Core Analysis Methods for Measuring Reservoir Rock Properties of Devonian Shale

Abstract: In this paper, the authors develop a new method involving crushed core samples to measure porosity and fluid content accurately in the black, organic-rich Devonian shales in the Appalachian basin. In the four wells studied, average core bulk volume of gas and porosity ranged to 4% and 8%, respectively, values substantially higher than previously reported.

Material flux and porosity changes during sediment diagenesis

Abstract: UNDERSTANDING the changes in porosity that occur during burial of sediments is of importance both in modelling fluid flow in sedimentary basins and for prediction of petroleum reservoir quality. When deposited, up to 50% of the volume of sands is intergranular pore space. Porosity generally decreases with depth because of compaction and precipitation of diagenetic minerals, but some sandstones retain an anomalously high porosity. Whether this is due to dissolution and removal of material or to its local redistribution is not clear. We originally intended to quantify losses of major chemical components during burial of a complete sedimentary unit. We have investigated ten reservoir sandstones, of Permian to Tertiary age, from oilfields worldwide. These show consistent results, and here we present detailed data from four of them. We found that the silica content of these sandstones actually increased, by 220 to 350 kg m−3, following compaction. No statistically significant changes were observed for aluminium, potassium or sodium. The flux of silica cannot be modelled satisfactorily using currently accepted values of permeability, silica solubility and flow rates, posing a challenge for existing models of fluid flow and ore emplacement.

Stable isotope geochemistry and origin of waters in sedimentary basins

Abstract: Formation waters with salinit~es ranging from about 5,000 mg/1 to more than 350,000 mg/l dissolved solids play a fundamental role in the physical and chemical processes that occur in sedimentary basins. These waters are particularly important in: (a) the generation, transport, accumulation and production of petroleum, (b) the chemical aspects of mineral diagenesis, including dissolution, precipitation and mineral transformations leading to major increases and/or decreases in the porosity and permeability of reservoir rocks, (c) the transport and precipitation of Cu, U, and especially sediment-hosted Mississippi Valley-type Pb-Zn ore deposits, (d) tectonic deformations, (e) the transport of thermal energy for the geothermal and geopressured-geothermal systems, and (f) the interaction, movement and ultimate fate of large quantities of hazardous wastes injected into the subsurface. Despite clear economic and scientific importance, and about a century of investigations, there is still controversy regarding the origin and evolution of these saline waters (Hanor et al., 1988).

Microbial composition of carbonate petroleum reservoir fluids

Abstract: Production fluids from four single‐zone completion wells in carbonate petroleum reservoirs were examined chemically and microbiologically to investigate the potential for microbially enhanced oil recovery in carbonate reservoirs. The water analysis indicated a lack of soluble nitrogen and phosphorus in these reservoir fluids. Three of the wells were highly saline, as expected, but one produced water containing <0.5% sodium chloride. Microorganisms with metabolisms useful for microbially enhanced oil recovery were enriched from the highly saline water produced from these three wells. A small, but metabolically diverse, microbial community was detected in each of the produced water samples. Although reservoir temperatures ranged from 44 to 63 °C, the highest viable counts were obtained at mesophilic temperatures. The results from this study are consistent with a hypothesis that, physical conditions permitting, carbonate petroleum reservoirs contain microbial populations that could be stimulated for...

Geohistory analysis and petroleum reservoir characteristics of Lower Cretaceous (Neocomian) sandstones, eastern Kopet-Dagh Basin, northeastern Iran

Abstract: The eastern part of the Kopet-Dagh basin of northeastern Iran contains over 4000 m of Upper Jurassic through Tertiary strata deposited in a variety of shallow-marine and terrestrial environments. Geohistory diagrams from well and outcrop data provide a useful mechanism with which to relate the stratigraphic framework of this part of the basin to the tectonic history of the region. During some episodes of regional tectonic uplift (e.g., episodes occurring 99-95 Ma, 74-70 Ma, and 63-54 Ma), sediment accommodation space continued to be created in the basin due to sediment loading and compaction of increased amounts of fine-grained sediments, in some cases concomitant with eustatic sea level rises. Much of the post-Jurassic subsidence in this part of the Kopet-Dagh basin was aused by sediment loading rather than tectonism. The effects of basin geohistory on petroleum reservoir properties were studied using the Lower Cretaceous (Neocomian) Shurijeh Formation as an example. Detailed petrologic, sedimentologic, and geohistory analyses done on this formation show that the petroleum reservoir properties of Shurijeh sandstones were affected by their depositional settings and the subsequent subsidence of these units through meteoric and compactional hydrogeologic regimes in this part of the Kopet-Dagh basin. These rocks consist mostly of sublitharenitic red beds deposited during a regressive phase of sedimentation dominated by rapid siliciclastic sediment supply. The lower and middle parts of the interval studied were deposited in low-sinuosity braided fluvial systems, and the upper part was deposited in high- inuosity meandering systems. By relating the paragenetic sequence of the Shurijeh sandstones to the geohistory of this formation, we determined the timing of both porosity-destroying and porosity-enhancing diagenetic processes and related these processes to the timing of petroleum generation.

A Two-Stage Stochastic Model Applied to a North Sea Reservoir

Abstract: This paper presents a two-stage stochastic model that caters to the large-scale geological heterogeneities resulting from different rock types and the inherent spatial variability of rock properties. The suggested approach combines several elements from a variety of models, methods, and algorithms that have emerged during the last few years. This two-stage procedure can be used to generate several geologically sound realizations of an oil or gas reservoir in an efficient manner. Stage 1 preserves the important geological architecture, while Stage 2 provides small-scale variability in the rock properties. At both stages, the stochastic models are conditional on the actual values observed in wells. Hence, every realization honors the observations. An example from a highly heterogeneous North Sea reservoir, deposited in an upper shore-face environment illustrates application of the model.

Permeability Transects of Eolian Sands and Their Use in Generating Random Permeability Fields

Abstract: This paper reports on observations derived from more than 10,000 permeability measurements taken from eolian sands and their use in generating permeability fields for reservoir simulation input. Results show that classification and statistical measures of variability and spatial correlation (but not mean permeability) are portable between the outcrop and the subsurface.

Relative permeability measurements for two phase flow in unconsolidated sands

Abstract: This paper presents the results of laboratory measurements of relative permeability for two phase flow in partially saturated samples of unconsolidated sands. Relative permeabilities for tap water and air, de-aired water and nitrogen were measured using a steady—state technique. Three different sand samples (fine sand, heterogeneous sand and coarse sand) were tested.

Chapter 4 Diagenesis and Origin of Porosity

Abstract: Publisher Summary This chapter discusses the most important aspects of diagenesis as they relate to the processes and spectrum of geologic environments by and in which porosity in carbonate sediments and rocks can be modified. Diagenetic alterations of carbonate sediments and rocks are known to occur in environments from subaerial meteoric to shallow and deep marine, and shallow to progressively deeper burial subsurface zones. Porosity in limestones and dolomites forms by a myriad of complex processes operative from the time of deposition (eogenetic) and continuing into deep-burial (mesogenetic) and subsequent meteoric exposure (telogenetic) environments. Porosity systems in carbonate rocks likewise are complex, and reservoirs typically are composed of several pore types, including those that are of primary as well as secondary origin. Such complexity in the modes of porosity evolution commonly results in extreme lateral and vertical heterogeneity in carbonate reservoirs. Porosity may or may not be coincident with particular depositional facies and, similarly, pores created or occluded in one diagenetic environment may conversely be occluded or exhumed later in another diagenetic environment.

Carbonate reservoir characterization : a geologic-engineering analysis, part 1

Abstract: 1. Introduction (G.V. Chilingarian, S.J. Mazzullo, H.H. Rieke). Important, relatively new concepts. Traditional concepts: classification schemes. Reserve analysis of carbonate reservoirs. Reserve calculation methods. Fractured reservoir rocks and fractures. Relative permeability concepts. Prediction of overpressured formations in carbonate reservoirs. Appendices: Material balance equation. Application of petrography and statistics to the study of some petrophysical properties of carbonate reservoir rocks. 2. Carbonate Rock Classifications (S.J. Mazzullo, G.V. Chilingarian, H.J. Bissell). Classification of limestones. Classification of dolomites. Classification of dolomites of marine origin. 3. Depositional Models of Carbonate Reservoirs (S.J. Mazzullo, G.V. Chilingarian). Stratigraphic traps in carbonate rocks: a review. Depositional facies in marine carbonate rock reservoirs. Platform types. 4. Diagenesis and Origin of Porosity (S.J.Mazzullo, G.V. Chilingarian). Overview of concepts. Methods of diagenetic study. Porosity characteristics of carbonate sediments and rocks. Formation of secondary matrix porosity in limestones. Porosity in dolomites. Reservoir examples. 5. Carbonates as Hydrocarbon Source Rocks (R.J. Cordell). Characteristic lithologies of carbonate source beds. Depositional environments. Environmental interpretations from geochemistry. Diagenesis. Source-bed geochemistry. Maturation.Effects of clay minerals. Maturation examples. Migration mechanisms. Matching source with reservoir. 6. Pore Geometry of Carbonate Rocks and Capillary Pressure Curves ( Basic Geologic Concepts ) (R.L. Jodry). Classification of carbonate porosity. Capillary pressure curve interpretation. Interrelation between pore geometry and rock types. Application of pore geometry characteristics to exploration. Pore geometry of dolomites. 7. Interrelationships among Surface Area, Permeability, Porosity, Pore Size, and Residual Water Saturation (G.V. Chilingarian, J. Torabzadeh, H.H. Rieke, M. Metghalchi, S.J. Mazzullo). Theoretical and empirical equations relating porosity, permeability, and surface area. Statistical technique of determining specific surface area. Interrelationships among surface area, rock granulometric composition, porosity, permeability, and residual water saturation. 8. Permeability and Relative Permeability of Carbonate Reservoirs (M.M. Honarpour, G.V. Chilingarian, S.J. Mazzullo). Relationship between effective and absolute permeability. Permeability parallel to bedding versus permeability perpendicular to bedding. Effects of rock properties on relative permeability. Effects of saturation history on relative permeability. Effects of temperature on relative permeability. Laboratory- measured relative permeability examples. Three-phase relative permeability of carbonate rocks. Empirical correlation. 9.Compressibility (G.V. Chilingarian, J. Torabzadeh, J.O. Robertson, H.H. Rieke, S.J. Mazzullo).

Sanaga Sud Field, Offshore Cameroon, West Africa

Abstract: The Sanaga Sud field, offshore Cameroon, is located just northwest of the coastal town of Kribi in the northern part of the Douala basin. The discovery well, Sanaga Sud A-1, was drilled in 1979 to test an apparent horst block that contained a prominent horizontal seismic amplitude. The Douala basin is one of a series of passive margin basins located along the coastline of central and southern Africa, and formed during the rifting of Africa and South America during the Early Cretaceous. Drilling results showed that the amplitude was a gas/water contact. Two appraisal wells, SSA-2 and SSA-3, were drilled in 1981. All three wells tested gas and condensate. Total recoverable hydrocarbons for the field are estimated to be approximately 1 tcf of gas. The trap in this field is composed of tilted and rotated fault blocks composed of interbedded Aptian to Albian sandstones, siltstones, and shales. The fault blocks were truncated by erosion (breakup unconformity) and later buried by a considerable thickness of onlapping Upper Cretaceous and Tertiary shale. The late Albian erosional unconformity forms the top of the trap over most of the field. Geochemical studies indicate a Lower Cretaceous source for the hydrocarbons. The gross pay thicknessmore » averages 250 m with an average porosity of 23% and an average permeability of 142 md. Reservoir lithologies range from well-sorted, massive sandstones to poorly sorted fine sandstones and siltstones containing shaly laminations that are carbonaceous and micaceous. The field is located predominantly in Block PH-38, but part of the field is in the Londji concession. Mobil Producing Cameroon, Inc., is the operator of PH-38 and Total Exploration and Production Cameroon is the operator of the Londji concession.« less

The Use of Routine and Special Core Analysis in Characterizing Brent Group Reservoirs, U.K. North Sea

Abstract: This paper describes the use of core analysis data, both routine and special, in characterizing the Brent Group reservoirs in the U.K. North Sea. The results of various special core analysis tests conducted over the years indicate that coring fluid, core preservation, and laboratory procedures are important in defining relative permeability and capillary pressure. Examples are given of the effect of oil-based mud filtrate on rock wettability; the effect of extraction, drying, and test procedures on laboratory waterflood performance; and variation of relative permeability among facies. Results also suggest how petrography may be used in assigning relative permeabilities by facies. Analysis of routine core data shows complexity within the Brent Group reservoirs even within relatively uniform sands.

Regional-scale porosity and permeability variations, Peace River arch area, Alberta, Canada

Abstract: This study examines the large-scale variability of porosity and permeability of the sedimentary rocks in the Phanerozoic succession in the Alberta part of the Peace River arch area of the Western Canada sedimentary basin. The study is based on about 450,000 core analyses at approximately 22,000 wells in an area of more than 165,000 km{2}. Plug-scale porosity and permeability values are scaled up to the well scale by hydrostratigraphic unit, resulting in two sets of about 16,000 values each for porosity and permeability, unevenly distributed both areally and with depth. The permeability frequency distributions are lognormal for most of the units or parts of the units. The regional-scale variability of porosity and permeability is quite high, between 1 and 38% for porosity, and 0.001 md and 3 d for permeability. The clastic units of the foreland basin exhibit a relatively high correlation between permeability and porosity. Several areal trends and patterns are identified for groups of hydrostratigraphic units, patterns that change gradually from one group to another. It is hypothesized that the observed variability is caused by the dominance of the Peace River arch, carbonate deposition, or compaction at various times throughout the evolution of the basin. Based on the predominant controlling factor, the geological history can be divided into four periods: arch influence during the Early to Middle Devonian, reefal carbonate-deposition influence during the Middle to Late Devonian, passive margin influence during the Late Devonian to Middle Jurassic, and orog nic influence since the Middle Jurassic.

Petrophysical evaluation of a slope fan/basin-floor fan complex: Cherry Canyon Formation, Ward County, Texas

Abstract: The Cherry Canyon Formation consists of a 925-ft (280-m) thick section of up to 25 different sandstone and siltstone units that were deposited in deep water in the Delaware basin. Lowstand sedimentation by fluid density currents with periodic turbidity currents resulted in a broad migrating channelized slope fan/basin-floor fan complex exhibiting a complex depositional architecture of reservoir sandstones. Original depositional fabric modified by diagenetic cements and authigenic clays create a range of petrophysical rock types. Type I reservoirs are found in channel sandstones; beds of lesser reservoir quality (type II) are present in laminated overbank/interchannel sandstones. A practical pore geometry classification scheme based on pore/grain shapes and pore throat rad i is used to understand fluid saturations and predict well performance within the context of the depositional framework and structural relief. Pore geometry factors combine with insufficient structural closure to create high water saturations throughout the oil column. Type I (macroporous) reservoirs exhibit oil-water transition zones, and are interbedded with type II (mesoporous to microporous) reservoirs which contain all or mostly water due to high capillarity associated with small pore throat size. Accurate reservoir water saturations can be derived using Archie's equation; when combined with a movable oil analysis and drainage relative-permeability/fractional-flow curves, initial watercuts can be predicted to maximize deliverability from optimal rock types. High original water saturations in the transition zone decrease average water saturations behind the waterflood front, resulting in inefficient secondary recovery. A combined application of sedimentological, petrophysical, logging, and reservoir engineering technologies is necessary to properly evaluate the Cherry Canyon reservoirs.

Draugen oil field, Haltenbanken Province, offshore Norway

Abstract: The Draugen oil field lies in Block 6407/9 in the Haltenbanken oil and gas province. The field is located 150 km off the coast of Norway and 200 km south of the Arctic Circle, in water depths of 240-280 m. The field was discovered in 1984 by well 6407/9-1. Five more exploration/appraisal wells and two-dimensional seismic assisted in delineating the reservoir. The field is hosted by a low-relief north-south-trending anticline measuring some 20 x 6 km. The reservoir lies at a depth of 1,600 m subsea, and has an oil column of 40 m. The main reservoir is the Late Jurassic Rogn Formation sandstones, interpreted as a shallow-marine sand bar. The formation pinches out to the west and east, and is capped by Spekk Formation shales. A separate, smaller accumulation has also been proved in Middle Jurassic Gam Formation sandstones in the western part of the field. Sand quality in both reservoirs is good to excellent. Field STOIIP is estimated at 180 million Sm{sup 3} of oil. Expectation of recoverable reserves is 67 million Sm{sup 3}. Government approval for field development was given in December 1988. The field will be developed with a concrete gravity base structure and offshore loading.more » The initial development plan calls for six oil producers and six subsea water injectors. The platform will be installed in the summer of 1993, with first oil shortly thereafter. The planned plateau production rate is 14,300 Sm{sup 3}/day dry oil. Pending a gas offtake solution for the Haltenbanken region, produced associated gas will initially be reinjected into a water-bearing structure in the western part of the field.« less

Chapter 7 Interrelationships Among Surface Area, Permeability, Porosity, Pore Size, and Residual Water Saturation

Abstract: Publisher Summary This chapter discusses the fundamental relationships for the porous medium of carbonate rocks, both from a pore-size portrait scale and at a macroscopic descriptive scale. There is a reasonable correlation between the porosity and permeability of cores having irreducible (immobile) fluid saturation in the minute pores, crevices, and so on, which do not have a major effect on the flow of fluids through the rock. Several correlations are developed that relate specific surface area of hydrocarbon-bearing reservoir rocks to other petrophysical properties (such as porosity, permeability, and pore size) and residual water saturation. Permeability is one of the most important parameters describing a porous medium, its measurement normally requires a rock sample that is of a suitable size (e.g., 5 cm x 5 cm x 5 cm) and has a simple geometric shape (for example, a cylinder or a cube). Correlations between the permeability and other easier-to-measure quantities, therefore, are discussed extensively both experimentally and theoretically. Several theoretical relationships between tortuosity and porosity have been developed for simplified models, two of which are presented.

Effects of capillarity and vapor adsorption in the depletion of vapor-dominated geothermal reservoirs

Abstract: Vapor-dominated geothermal reservoirs in natural (undisturbed) conditions contain water as both vapor and liquid phases. The most compelling evidence for the presence of distributed liquid water is the observation that vapor pressures in these systems are close to saturated vapor pressure for measured reservoir temperatures (White et al., 1971; Truesdell and White, 1973). Analysis of natural heat flow conditions provides additional, indirect evidence for the ubiquitous presence of liquid. From an analysis of the heat pipe process (vapor-liquid counterflow) Preuss (1985) inferred that effective vertical permeability to liquid phase in vapor-dominated reservoirs is approximately 10{sup 17} m{sup 2}, for a heat flux of 1 W/m{sup 2}. This value appears to be at the high end of matrix permeabilities of unfractured rocks at The Geysers, suggesting that at least the smaller fractures contribute to liquid permeability. For liquid to be mobile in fractures, the rock matrix must be essentially completely liquid-saturated, because otherwise liquid phase would be sucked from the fractures into the matrix by capillary force. Large water saturation in the matrix, well above the irreducible saturation of perhaps 30%, has been shown to be compatible with production of superheated steam (Pruess and Narasimhan, 1982). In response to fluid production the liquid phase will boil, with heat of vaporization supplied by the reservoir rocks. As reservoir temperatures decline reservoir pressures will decline also. For depletion of ''bulk'' liquid, the pressure would decline along the saturated vapor pressure curve, while for liquid held by capillary and adsorptive forces inside porous media, an additional decline will arise from ''vapor pressure lowering''. Capillary pressure and vapor adsorption effects, and associated vapor pressure lowering phenomena, have received considerable attention in the geothermal literature, and also in studies related to geologic disposal of heat generating nuclear wastes, and in the drying of porous materials. Geothermally oriented studies were presented by Chicoine et al. (1977), Hsieh and Ramey (1978, 1981), Herkelrath et al. (1983), and Nghiem and Ramey (1991). Nuclear waste-related work includes papers by Herkelrath and O'Neal (1985), Pollock (1986), Eaton and Bixler (1987), Pruess et al. (1990), Nitao (1990), and Doughty and E'ruess (1991). Applications to industrial drying of porous materials have been discussed by Hamiathy (1969) arid Whitaker (1977). This paper is primarily concerned with evaluating the impact of vapor pressure lowering (VPL) effects on the depletion behavior of vapor-dominated reservoirs. We have examined experimental data on vapor adsorption and capillary pressures in an effort to identify constitutive relationships that would be applicable to the tight matrix rocks of vapor-dominated systems. Numerical simulations have been performed to evaluate the impact of these effects on the depletion of vapor-dominated reservoirs.

The Geology of Heidrun: A Giant Oil and Gas Field on the Mid-Norwegian Shelf

Abstract: The Heidrum field is located in the Haltenbanken region on the mid-Norwegian continental shelf, 165 mi from shore in water depths of approximately 1,150 ft. The field is a giant Cimmerian structure with hydrocarbons trapped in Jurassic sandstone reservoirs. The field has 750 MM bbl recoverable oil reserves, with associated gas reserves of 0.45 tcf and free gas reserves of 1.3 tcf. The accumulation extends over 14.4 mi and was unitized in 1989 with 75% of the field in Block 6507/7 and 25% of the field in Block 6507/8. The 6507/7 block was acquired by Conoco Norway and partners in 1984 in the eighth round of licenses offered by the Norwegian government. The acquisition was based on extensive in-house exploration regional studies, which identified a Jurassic rift element in Haltenbanken and the potential for the generation of liquid hydrocarbons. The Heidrun structure is a large southwesterly plunging horst block on the southwestern flank of the Nordland Ridge and was formed during the Cimmerian extensional tectonic phase in the Late Jurassic-Early Cretaceous. The Heidrun reservoirs are severely truncated at the northern edge of the structure and are sealed by Cretaceous shales. The Heidrun Jurassic reservoir rock, the Fangst Group and themore » Tilje and Are Formations, were deposited on the southeastern flank of the developing northeastern Atlantic Rift domain. The shallow burial depth (< 8,100 ft) has limited compaction effects, and reservoir quality therefore is enhanced with permeabilities up to 10 d and porosities in excess of 30% in the cleaner sands of the Fangst. The primary sources for the petroleum is the Upper Jurassic Spekk Formation, which is mature in the downdip areas 3-10 mi southwest and west of Heidrun. Therefore, fairly long petroleum migration paths are inferred. A 5,000-km-high resolution three-dimensional seismic survey was acquired in 1986. The three-dimensional data set forms the basis for detailed geologic and reservoir models.« less

Improvement of Gravity Drainage by Steam Injection Into a Fractured Reservoir: An Analytical Evaluation

Abstract: This paper reports on analytical techniques that were used to study improvement of gas/oil gravity drainage by steam injection in a densely fractured dome-shaped low-permeability reservoir containing viscous oil. Aspects of the process studied include mixing of the steam and hydrocarbon gas, the temperature distribution in the caprock and reservoir, and oil production by thermal expansion and gravity drainage. The models developed are applied to the Qarn Alam reservoir of Oman, which may be a candidate reservoir. The steam-injection process appears very attractive for this reservoir; an oil/steam ratio of 0.5 m{sup 3}/Mg may be achieved.

October field: The latest giant under development in Egypt's Gulf of Suez

Abstract: October field, the third largest oil field in Egypt, produced 378 MMBO from its discovery in 1977 until January 1990. It is the northernmost giant oil field in the Gulf of Suez Rift basin. Twenty wells from five platforms in approximately 190 ft (58 m) of water currently drain over 3,238 ha. Recent successful field extensions demonstrate the viability of continuing exploration in this oil-rich area. This structurally trapped field is a complex of rotated fault blocks typical of rift basins worldwide. A northwest-trending normal fault with an approximate throw of 1,220 m has trapped an 335-m oil column on the upthrown eastern side. On the upthrown side, the Carboniferous through Oligocene prerift section dips gently to the northeast and is unconformably overlain by generally flat Miocene to Holocene clastics, carbonates, and evaporites. Severe multiple problems result from thick Miocene evaporites hampering seismic definition of the highly productive prerift section. These same evaporites serve as the ultimate seal in October field and throughout the Gulf of Suez. Although four layers are productive, approximately 95% of field reserves are within Carboniferous to Lower Cretaceous massive Nubia Sandstones. The remaining reserves are in more stratified Upper Cretaceous sandstones, basal Miocene rift-fill Nukhulmore » Formation clastics, and a Lower Miocene clastic in the upper Rudeis Formation. Several distinct reservoir accumulations exist, with the deepest and most significant original oil-water contact at {minus}10,670 ft subsea. October field oil gravities range from 14 to 34{degree} API, with an initial solution GOR of 134 to 474 SCF/STB. The hydrocarbon source for all October field oil as well as most Gulf of Suez oil is believed to be the Campanian Brown Limestone Member of the Sudr Formation. Average reservoir parameters for the Nubia Formation are 16% porosity, 236 md permeability, 137 m net pay thickness, and 5,506 psi original reservoir pressure.« less

An Integrated Interpretation for the Origin of the Patrick Draw Oil Field Sage Anomaly (1)

Abstract: The Patrick Draw oil field has been the site of research into surface and remote sensing methods for hydrocarbon exploration for nearly 10 yr. The oil field is a stratigraphic trap with conspicuous sage vegetation on the surface and an associated tonal anomaly within that sage (visible via Landsat") overlying the field's gas cap. This paper attempts to resolve the controversy of whether the Patrick Draw sage anomaly is related to oil field factors or to other independent factors. Geology and production history of the field show the sage die-out anomaly results from upward migration of injected gases and waters used to maintain reservoir pressures in the field. These gases and waters produced anoxic, low-Eh (oxidation potential), high-pH, and high-salinity soils that are toxic to the overlying sage population. Stunted sage associated with the anomaly commonly occurs in marginal terrains in the western United States and is not tied uniquely to oil fields. A velocity for the seeping gases of 250-1000 ft/yr (76-305 m/yr) was calculated from the reservoir to the surface. Failure to account for the lag time associated with movement of seepage to the surface has been a source of misinterpretation.

Integrated Geologic and Engineering Determination of Oil-Reserve-Growth Potential in Carbonate Reservoirs

Abstract: Leonardian restricted-platform carbonate reservoirs in the Permian Basin in West Texas and southeastern New Mexico exhibit abnormally low recovery efficiencies. Cumulative production form these mature reservoirs is only 18% of the original oil in place (OOIP), or about one-half the average recovery efficiency of Permian Basin carbonate reservoirs. Low recovery efficiency is directly related to high degrees of vertical and lateral facies heterogeneity caused by high-frequency, cyclic sedimentation in low-energy, carbonate platform environments and by equally complex postdepositional diagenesis. This paper reports that because of their geologic complexity, these reservoirs have high reserve-growth potential.

Chapter 6 Pore Geometry of Carbonate Rocks and Capillary Pressure Curves (Basic Geologic Concepts)

Abstract: Publisher Summary The pore geometry of a limestone or dolomite has as great an influence as porosity and permeability on the ability of the rock to contain and produce oil and gas. By studying the lithology and genesis of the rocks and comparing families of rocks with families of capillary pressure curves, studying a rock under the microscope, and with a knowledge of pore geometry in the area and with even rough values for the porosity and the permeability of the rock, it is possible to predict reasonably closely the productivity of the rock. This is frequently not possible when porosity and permeability data are used without consideration of the pore geometry. A study of the pore geometry, however, has consistently revealed that porous rocks, despite their very high porosities, would need at least 450 ft (135 m) of oil column to produce oil. Pore geometry studies also enable one to better understand some of the producing characteristics of cyclic layered rocks. Frequently, in limestone formations, alternating horizons of fine, highly porous and coarse, less porous rocks are found. It is not uncommon for the more porous, fine-grained rocks to yield water, whereas the coarse but denser rocks may produce water-free oil.

Chapter 8 Permeability and Relative Permeability of Carbonate Reservoirs

Abstract: Publisher Summary This chapter discusses permeability and relative permeability of carbonate reservoirs. The effective permeability of a porous medium to a fluid is a measure of the ability of the medium to transmit this fluid at the existing saturation, which is usually less than 100%. There is a simultaneous existence of more than one fluid phase in the majority of reservoirs: (1) oil and gas, (2) oil and water, (3) gas and water, or (4) oil, gas, and water. The magnitude of effective permeability depends on rock properties, saturation, and direction of saturation changes, wettability, and capillary forces. The relative permeability to a fluid is defined as the ratio of effective permeability at a given saturation of that fluid to the absolute permeability at 100% saturation. The relationship between absolute permeability, k a , and effective permeability, k e , to gas is presented. The effective permeability to gas is measured on cores containing irreducible water saturation. Relative permeability––saturation relations in carbonate rocks with intergranular porosity resemble relative permeability characteristics of sandstone formations. The hysteresis phenomenon that is related to the direction of saturation change in reservoirs is reported for both water–oil and gas–oil relative permeability ratio curves as well as for relative permeabilities of wetting and non-wetting phases in carbonate formations.