Hydrocarbon Column Research Articles

Fault-Zone Seals in Offshore Trinidad Oil Fields

Hydrocarbon columns in Pliocene sands of offshore SE Trinidad occur in 3-way closure, primarily in the footwall of normal faults. Multiple reservoir sands and numerous fault blocks result in a large number of individual hydrocarbon accumulations. Fault-plane sections demonstrate that fault sealing is unrelated to juxtaposition of intercalated shales. These fault-zone capillary seals were studied by (1) inferring their fluid-flow properties from the pattern of trapped hydrocarbons and (2) direct examination and measurement of cored faults. Buoyancy pressures for hydrocarbon columns were calculated from fluid property data for each reservoir and fault block. Buoyancy pressures range widely, increasing nonlinearly with fault displacement and percent shale in the faulted section, but do not vary systematically with stratigraphic position or depth. Small-displacement faults observed in core are narrow zones of cataclasis within porous sandstone. Mercury injection tests indicate fault-zone displacement pressures that coincide with buoyancy pressures calculated for hydrocarbon columns sealed by large-displacement faults. The agreement between measured displacement pressures and calculated buoyancy pressures indicates that (1) the reservoirs are filled to their capacity, dictated by the displacement pressure of the fault zones, and (2) the fault-zone seals are primarily the product of deformation of the sands, with some enhancement by incorporation more » of argillaceous material into the fault zones. The observed relationship between fault displacement and calculated buoyancy pressure of the hydrocarbon columns implies that fault-zone continuity is a factor that needs to be assessed in fault-zone seal analysis. « less

The Alwyn North Field, Blocks 3/9a, 3/4a, UK North Sea

Abstract Abstract: Situated in the southeastern part of the East Shetland Basin, the Alwyn North Field produces oil and gas from Brent Group reservoirs and gas and condensate from the Statfjord Formation. The structural style is of tilted and eroded fault blocks dipping to the west and aligned north-south conforming to the principal normal fault trend. NE-SW cross elements further separate the hydrocarbon accumulations. The hydrocarbon columns are restricted to the Tarbert and upper part of the Ness Formation of the Brent Group, in sediments associated with the retreat of the Brent delta. The Statfjord Formation was deposited in an alluvial, fan-delta setting with increasing marine influence towards the top of the formation.

The South Brae Field, Block 16/7a, UK North Sea

Abstract South Brae Oilfield lies at the western margin of the South Viking Graben, 161 miles northeast of Aberdeen. Oil production began in July 1983 from a single platform located in 368 ft of water. The field originally contained 312 MMBBL of recoverable reserves, and in May 1990, cumulative exports of oil and NGL reached 219 MMBBL. The reservoir lies at depths in excess of 11800 ft TVSS, has a maximum gross hydrocarbon column of 1670 ft, and covers an area of approximately 6000 acres. The reservoir is the Upper Jurassic Brae Formation which is downfaulted against tight sealing rocks of probable Devonian age at the western margin of the field. The other field margins are constrained by a combination of structural dip and stratigraphic pinchout. The reservoir is capped by the Kimmeridge Clay Formation, which is also the source of the oil.

The Murchison Field, Block 211/19a, UK North Sea

Abstract The Murchison oil field forms part of the Brent oil province in the East Shetland Basin, northern North Sea. The field, which straddles the UK-Norway international boundary, was discovered in 1975 and began production with Conoco (UK) Ltd as Operator, in 1980. Like many oil accumulations in the East Shetland Basin the trap consists of a northwesterly dipping rotated fault block of Jurassic-Triassic age sourced and sealed by unconformable Upper Jurassic shales. The productive reservoir consists of Middle Jurassic Brent Group sandstones which represent the south to north progradation of a wave/tide influenced delta system. The Brent Group on Murchison has an average thickness of 425 ft with average porosities of 22% and permeabilities in the 500-1000 md range in producing zones. The maximum hydrocarbon column thickness is approximately 600 ft. The oil is undersaturated and no gas cap is present. Recoverable reserves are 340 MMBBL from a total oil in place figure of 790 MMBBL. Oil production which is via a single steel jacket platform peaked at 127 000 BOPD in 1983 and currently averages 45 000 BOPD. Economic field life is expected to be at least 20 years. The Murchison Field is located in the East Shetland Basin, northern North Sea at approximate latitude 61° 23' N, longitude 1° 43.5' E, 120 miles northeast of the Shetland Islands (Fig. 1). The field straddles the UK-Norway international boundary with the greater portion in the UK Block 21 l/19a and the lesser portion in Norway Block 33/9. Water depth is -512 ft BMSL. In the context of the North Sea the field is of medium size with an areal closure of approximately 7 square miles and contains 790 million barrels of oil in place. The productive reservoir consists of coastal deltaic sandstones of the Middle Jurassic Brent Group which lie between the marine shales of the Lower Jurassic Dunlin Group and the marine, organic-rich shales of the Upper Jurassic Humber Group. The trap is structural comprising a single, northwesterly dipping rotated fault block which has been sourced and sealed by the overlying Upper Jurassic shales. The field is named after the Scottish geologist Sir Roderick Impey Murchison (1792-1871), who is best known for his contribution to Palaeozoic stratigraphy.

Reservoir Characteristics of Putnam Zone (Silurian Interlake Formation) Lithofacies, Southwestern Williston Basin

Reservoirs in the Putnam zone (lower Interlake Formation) in the southwestern part of the Williston basin include oolitic-pellet dolomite grainstone, fossil-pellet grainstone, and a wide spectrum of reef-related, fossil-corral dolomite packstones and coral-stromatoporoid rudstone/boundstones. Each of these potential reservoirs has a unique pore system and, thus a different set of petrophysical properties which define their reservoir characteristics. Oolitic grainstones have a homogeneous intercrystalline-micro-crystalline pore system, whereas the fossil-pellet dolomite grainstone facies consists of separate mesovugs dispersed in well-interconnected intercrystalline porosity. Capillary pressure curves indicate that pore-throat heterogeneity is greater, and entry pressures lower, for reefal lithofacies than for pelletal grainstones. These curves also demonstrate why many of the producing fields tend to have high water cuts. In many oolitic-pellet grainstone units, irreducible water saturations of 10% would not be reached until a hydrocarbon column of 700 ft was reached. High water production characteristics are therefore expected because Red River/Interlake structures attain only 50-100 ft of closure. This, however, does not mean that Putnam is not an economic zone, especially as a secondary objective. Wells in Putnam and Crane fields, for instance, have reserves in excess of 300,000 bbl of oil. The reservoirs here may be dominated by the reef-related facies,more » which have an extremely high relative permeability to oil.« less

Petrophysical Properties of Seals

Seals are defined as generally ductile rocks with a very high capillary entry pressure that can dam up hydrocarbons. Petrophysical and petrographic studies of conventional and sidewall cores from known seal-reservoir couplets of hydrocarbon-producing reservoirs provide a basis to quantify the capacity of a rock to seal a hydrocarbon column. The most important property of a seal is its pore-size distribution as measured in thin section, scanning electron microscope, and very high pressure (up to 50,000 psi) air-mercury capillary pressure curves determined across bedding surfaces in vertical plugs. Seal quality or capacity is determined by pore-size distribution and interconnection and ductility. Using the density difference of normal saline water and 35{degree} API oil as a standard, an arbitrary scale of seal types has been developed. Comparators of known seal types composed of samples of the rock type, SEM photographs, and capillary pressure curves are used to estimate seal type under a binocular microscope at 50X magnification. A catalog of seal petrophysical properties and microphotographs allows one to make reliable estimates of seal capacity of unknown samples in cores and cuttings with a binocular microscope.

Jupiter's north and south polar aurorae with IUE data

Observations of Jupiter's auroral H2 emissions with the IUE spacecraft, from 1978 through 1990, show that aurorae at the two poles are similar in several respects: (a) emission intensity is modulated with magnetic longitude, north peak emission at λIII(1965) ∼ 200°; south peak at λIII(1965) ∼ 20°; (b) emission intensity and degree of modulation are comparable for both poles; (c) attenuation by hydrocarbons varies in phase with the intensity, peak attenuation coinciding approximately with peak emission. Increases in the hydrocarbon column are an indicator of either enhanced penetration depth and thus energy of the auroral primaries, or of increases in the high‐altitude hydrocarbon content caused by modification of the local atmosphere.

Hydrocarbon Columns, Buoyancy and Seals: Comparisons of California and Colorado-Montana-Wyoming Accumulations: ABSTRACT

Hydrocarbon Columns, Buoyancy and Seals: Comparisons of California and Colorado-Montana-Wyoming Accumulations: ABSTRACT

Pore-Level Reservoir Heterogeneity in Carbonates: Lisburne Reservoir, Prudhoe Bay Field, North Slope, Alaska: ABSTRACT

The heterogeneity of the pore system in the Lisburne reservoir at Prudhoe Bay, Alaska, can be related to the variability of reservoir properties in this giant oil field. The reservoir consists of four petrographically defined pore types. The most common, pore type 1, is microporosity occurring within limestone grains. A characteristic of these microporous rocks is their high porosities and low permeabilities. Due to the great hydrocarbon column at Prudhoe Bay, much of this microporosity is oil filled, but unproducible in the absence of fractures. Pore type 2 consists of moldic and/or intraparticle pores in limestones that commonly result in pay intervals with good porosity and fair permeability. Pore type 3 comprises intercrystalline pore networks in dolomite that, depending on pore throat size, also contribute to pay. Pore type 4 is an intercrystalline pore network in dolomite, with more than 10% of the total porosity in the form of molds or vugs. Pore type 4 commonly has the most favorable reservoir properties and, as indicated by production tests, contributes the majority of the reservoir's flow. Lisburne pore types owe their origin to a combination of depositional and diagenetic processes. Early diagenetic dolomitization of mudstones and wackestones created pore type 3more » layers that acted as permeable conduits for later diagenetic solutions. These solutions dissolved limestone grains within the dolomites to produce pore type 4, as well as leaching adjacent lime packstones and grainstones to produce pore types 1 and 2. The geometry of pore types 1 and 2, which form halos around pore types 3 and 4, is the basis for defining flow units within the Lisburne reservoir.« less

Reservoir Characterization of a Permian 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 a deep-water environment 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 interpreted to exhibit an intricate reservoir geometry. Thirteen lithofacies are identified. Primary reservoirs are found in massive channel sandstones, and beds of lesser reservoir quality are present in laminated overbank/interchannel sandstones. Original depositional fabric modified by diagenetic cements and authigenic clays created three petrophysical rock types. Type I reservoirs contain intergranular macroporosity relatively free of carbonate cement and authigenic clay. Types II and III reservoirs contain mesoporosity and abundant microporosity created by moderate to abundant carbonate cementation and plugging of pore throats by authigenic grain-coating chlorite and pore-bridging fibrous illite. Depositional and diagenetic factors combine with insufficient oil column height to yield low initial oil saturations that decrease with depth in a hydrocarbon-water transition zone. Mercury injection capillary pressure measurements illustrate the vertical stratification of petrophysical rock types that exist in the section; reservoirs which contain all water are interbedded with reservoirs containing mostly oil. Subsequently, a slight change inmore » height above free water can drive production from all water to all oil. Hydrocarbon column heights greater than 60 ft are required to establish water-free oil production. 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 water cuts can be predicted to maximize deliverability.« less

Compositional Effects in Gravity-Dominated Nitrogen Displacements

Summary In this paper, the role of compositional effects during secondary, gravity-stable nitrogen displacements in (dipping) light-oil reservoirs, such as the Statfjord reservoir in the Brent field, is discussed. Displacements of both a gas condensate from the top of the Statfjord hydrocarbon column and a volatile oil from a more downdip location in this column are discussed. The main compositional effects in such vaporizing-gas-drive-type displacements are the following. The displacing vapor at the displacement front is not nitrogen, but a rich hydrocarbon gas liberated from the reservoir fluid upon contact with nitrogen. This hydrocarbon vapor is miscible with the reservoir fluid in the case of the gas condensate, but just fails to develop miscibility in the case of the oil-like reservoir fluid. The remaining oil is a degassed, more viscous oil than the original reservoir fluid. In addition to equation-of-state (EOS) programs, both a compositional simulator and an analytic, dispersion-free model for vaporizing-gas drives have been used to quantify the effect of phase behavior on recovery efficiency. These compositional calculations indicated that next to the phase behavior, the longitudinal dispersion level and, in the case of the oil-like fluid, the degree of gravity segregation at the displacement front are key factors determining displacement efficiency. Results are presented of a systematic investigation into the relative contributions of phase behavior, physical dispersion, and gravity drainage to the recovery process. A comparison of predicted results and slim-tube and coreflood experiments is made. The extent to which these laboratory experiments might be representative for reservoir-scale displacements is also briefly discussed.

Birba Field PVT Variations Along the Hydrocarbon Column and Confirmatory Field Tests

This paper describes a practical application of thermodynamic modeling that indicated that the PVT properties of the reservoir fluid in the Birba field were strongly depth-dependent, explaining the presence of significantly undersaturated oil only 200 m (655 ft) below a gas cap. Field tests confirmed the thermodynamic model to be correct. Furthermore, this paper discusses the options for field development, including the consideration of possible benefits of (developed) miscibility when gas is injected.

THE INTRA-LATROBE PLAY : A CASE HISTORY FROM THE BASKER/MANTA BLOCK (VIC/P19), GIPPSLAND BASIN

In 1981 Shell and its co-venturers were the successful applicants for gazettal block V80-3, now permit VIC/P19, on the north-eastern margin of the Gippsland Basin where, subsequently, 10 exploration wells were drilled. At the time of the award, the offshore Gippsland Basin had been explored for some 20 years, and the conventional 'Top Latrobe' play even then was considered to be largely exhausted although a few small traps of doubtful economic viability remained untested. Thus, from the outset, exploration in VIC/P19 also emphasised the intra-Latrobe play. While the existence of the intra-Latrobe play has long been recognised, its extent and limiting parameters are less well documented.Recent exploration results in the southern part of VIC/P19 indicate that the main phase (peak) of generation and expulsion of hydrocarbons from intra- Latrobe source rocks occurs at depths of 4 to 5 km for oil and 5 to 6 km for gas. Large-scale vertical migration of hydrocarbons (up to 2 km or more) is probably occurring in many parts of the central Gippsland Basin and has charged faulted intra- Latrobe traps, such as found at Basker-1 and Manta-1. These accumulations are characterised by multiple stacked reservoirs (fluvial and alluvial sandstones) and thin hydrocarbon columns. However, similar adjacent traps are dry, despite the presence of equivalent reservoirs (e.g. Basker South-I and Chimaera-I), probably due to inadequate lateral fault seals. Lateral sealing may occur along the fault plane itself or by favourable juxtaposition of lithologies, both cases being demonstrated in the Manta accumulation. The petrology and reservoir characteristics of Latrobe Group sandstones vary considerably, depending largely on sedimentary facies. Sands of fluvial or alluvial origin are generally inferior to those deposited in shoreline environments. An effective intra-Latrobe reservoir 'floor' lies at around 4 km burial depth for both fluvial and alluvial sandstones.

Theoretical aspects of cap-rock and fault seals for single- and two-phase hydrocarbon columns

Cap-rock seals can be divided genetically into those that fail by capillary leakage ( membrane seals) and those whose capillary entry pressures are so high that seal failure preferentially occurs by fracturing and/or wedging open of faults ( hydraulic seals). A given membrane seal can trap a larger oil column than gas column at shallow depths, but below a critical depth (interval), gas is more easily sealed than oil. This critical depth increases with lower API gravity, lower oil GOR and overpressured conditions (for the gas phase). These observations arise from a series of modelling studies of membrane sealing and can be conveniently represented using pressure/ depth ( P/D) profiles through sealed hydrocarbon columns. P/D diagrams have been applied to the more complex situation of the membrane sealing of a gas cap underlain by an oil rim; at seal capacity, such a two-phase column will be always greater than if only oil or gas occurs below the seal. These conclusions contrast with those for hydraulic seals where the seal capacity to oil always exceeds that for gas. Moreover, a trapped two-phase column, at hydraulic seal capacity will be less than the maximum-allowed oil-only column, but more than the maximum gas-only column. Unlike membrane seals, hydraulic seal capacity should be directly related to cap-rock thickness, in addition to the magnitude of the minimum effective stress in the sealing layer and the degree of overpressure development in the sequence as a whole. Fault-related seals are effectively analogous to membrane cap-rocks which have been tilted to the angle of the fault plane. Consequently, all of the above conclusions derived for membrane cap-rocks apply to both sealing faults sensu stricto (fault plane itself seals) and juxtaposition faults (hydrocarbon trapped laterally against a juxtaposed sealing unit). The maximum-allowed two-phase column trapped by a sealing fault is greater than for equivalent oil-only and gas-only columns, but less than that predicted for a horizontal membrane cap-rock under similar conditions. Where a two-phase column is present on both sides of a sealing fault (which is at two-phase seal capacity), a deeper oil/water contact (OWC) in one fault block is associated with a deeper gas/oil contact (GOC) compared with the adjacent fault block. If the fault seal is discontinuous in the gas leg, however, the deeper OWC is accompanied by a shallower GOC, whereas a break in the fault seal in the oil leg results in a common OWC in both fault blocks, even though separate GOC's exist. Schematic P/D profiles are provided for each of the above situations from which a series of fundamental equations governing single- and two-phase cap-rock and fault seal capacities can be derived. These relationships may have significant implications for exploration prospect appraisal exercises where more meaningful estimates of differential seal capacities can be made. The membrane sealing theory developed herein assumes that all reservoirs and seals are water-wet and no hydrodynamic flow exists. The conclusions on membrane seal capacity place constraints on the migration efficiency of gas along low-permeabiligy paths at depth where fracturing, wedging open of faults and/or diffusion process may be more important. Contrary to previous assertions, it is speculated that leakage of hydrocarbons through membrane seals occurs in distinct pulses such that the seal is at or near the theoretically calculated seal capacity, once this has been initially attained. Finally, the developed seal theory and P/D profile concepts are applied to a series of development geological problems including the effects of differential depletion, and degree of aquifer support, on sealing fault leakage, and the evaluation of barriers to vertical cross-flow using RFT profiles through depleted reservoirs. It is shown that imbibition processes and dynamic effects related to active cross-flow across such barriers often preclude quantitative analysis and solution of these problems for which simulation studies are usually required.

The Geophysical Development Of The Jabiru Field

The Jabiru field, located within AC/L1 off the N.W. coast of Australia was discovered in August 1983 by BHP Petroleum and its co-venturers when the wildcat well Jabiru-1A intersected a 57 metre gross hydrocarbon column within sandstones of Jurassic age. The structure lies within the Jabiru Turnstone horst, one of a series of parallel horsts trending N.E./S.W. on the eastern side of the Cartier Trough (Fig. 1).

A Dry Hole or Reservoir Damage? What We Need to Know: ABSTRACT

Stories abound in the industry about the oil or gas field drilled and abandoned by one company, only to be discovered by a second company that evaluated the data from a different perspective. The Elmworth field (Canada), and Beeville, North Resenberg, and Running Duke fields (Texas) are all examples where the initial well penetrated the hydrocarbon column but was not completed, or was completed, tested, and abandoned. Numerous explanations exist as to why fields are abandoned and then rediscovered. Often contributing to this cycle is a lack of understanding of the reservoir's pore geometry, and of the effects of drilling or completion-induced damage on production or pressure performance measured by drill-stem tests, repeat formation testers, and well logs. Additionally, the inability to tell the difference between a low-permeability noncommercial reservoir and a damaged commercial reservoir results in a lot of missed field discoveries. In my lecture, I discuss the causes of formation damage, as well as factors that signal the reservoir's vulnerability to damage (e.g., small pore throats, authigenic clays, low reservoir pressure). I also include case examples of conventional tests that, by routine analysis, show the zone to be noncommercial when, in fact, the well was completed and produced commercially. Understanding the type of reservoir system being tested and using all available tools and data are the key to determining reservoir behavior. End_of_Article - Last_Page 1440------------

Geological Controls on Heterogeneous Reservoir Behavior in Complex Deltaic Sediments, Brent Field, Northern North Sea: ABSTRACT

The Brent field is the largest oil field in the United Kingdom sector of the northern North Sea, and its discovery in 1971 pioneered development in the area. The field contains some 3.4 billion bbl of oil in place, trapped in two reservoirs in a simple rotated fault block on the western margin of the Viking graben failed rift system. Three-fifths of the oil is found in an 800-ft section of deltaic deposits of the Middle Jurassic Brent Group, with a single oil water contact and an 850-ft hydrocarbon column. The lower part of this reservoir is a sand-rich, wave-dominated delta-front sequence overlain by delta-plain sediments. The first oil was produced in 1976 under a downflank artificial water drive. Three dominant controls on the reservoir geologic framework have been identified: (1) individual delta lobe progradation and abandonment, (2) irregular periods of rapid subsidence followed by relative sea level stillstand, and (3) crestal collapse. The first two primary depositional controls combined to produce a layered reservoir in the delta-plain sequences characterized by fieldwide coals marking delta-lobe abandonment. Extensive shales resulted from the periods of rapid subsidence. These shales now form vertical permeability barriers defining subreservoirs highlighted by repeat formation tester profiles.more » Late Jurassic graben-associated tectonics initiated the fault block rotation and allowed crestal unroofing and erosion. Instability in the underlying plastic marine shales created complex rotational faulting in the Brent sediments. These crestal features complicate reservoir behavior, especially in the gas cap. Continued fault movement created a number of unconformities and condensed sequences in the overlying Upper Jurassic and Lower Cretaceous reservoir sealing shales.« less

Diagenetic Traps in Sandstones

Diagenesis may be an important agent in trapping hydrocarbons in sandstones by formation of reservoirs or seals. Reservoirs are formed by the creation of secondary porosity during burial. Seals are formed by heavy cementation, which may allow sandstones to retain large hydrocarbon columns. Formation of a diagenetic trap requires that parts of the sandstone unit react differently from each other during burial. This can be caused by differences in (1) detrital mineralogy--resulting from grain size or depositional environment controls; (2) early diagenetic mineralogy--largely depositional environment controlled; (3) burial history--structural movement induced; and (4) fluid content--hydrocarbon or water saturation. Each of these factors can lead to differences in porosity and permeability of the sandstone sufficient to form reservoirs and seals. In the correct configuration, diagenetic traps may be formed. Basin-center gas accumulations result from diagenetic trapping in some instances.

An Approach To Predict Tarmat Breakdown in Minagish Reservoir in Kuwait

Minagish Oolite reservoir, Minagish Field in Kuwait is characterized by tarmat presence at the oil-water contact. A water flooding project is planned for the reservoir. This paper discusses the possibility of tarmat break-down upon water injection below it. It was found that differential pressure at tarmat would be mainly due to water injection and that differential pressure due to oil production would be negligible. This paper suggests a technique to predict tarmat break-down time, response time at the nearest producer or observation well and the time at which water injection should be switched from below tarmat to above it. Also, the technique could be used to predict the differential pressure at tarmat anywhere in the reservoir.

The Valhall Field: a geological overview

The Valhall Field is located within the Central Graben in the southern part of the Norwegian North Sea. The discovery well, 2/8-6, was drilled in 1975 and the field went on production in 1982. Production is currently 55 000 barrels of oil per day. The Valhall Field structure trends NW-SE and has an areal closure in excess of 60 000 acres. The hydrocarbon column measures ∼200 m. The structure is located on an elongate anticlinal feature called the Lindesnes Ridge, which developed during Late Cenomanian to Oligocene tectonic movements. The geophysical evaluation of the field is complicated by the existence of a gas-charged Tertiary section which obscures the deeper seismic reflections. Vertical seismic profiles (VSPs) have been utilized in an attempt to resolve the reservoir configuration. Reservoirs occur both in the Tor Formation (Maastrichtian), and in the underlying Hod Formation (Turonian-Coniacian). The Tor Formation is represented by a largely allochthonous chalk facies which thins regionally to the southwest. A crestal graben is developed in which the Tor Formation is locally thick. Autochthonous chalks are characteristic of the Hod Formation. Primary porosity of the chalk varies between 36 to 50% on the crest of structure. Preservation of such high porosity is primarily due to formation overpressure inhibiting mechanical compaction of the chalk. The field contains paraffinic oil of 36 API gravity. It originated from the Upper Jurassic Kimmeridge Clay Formation, which is at peak oil generating capacity under the field at present day.