Giant Oil Field Research Articles

Abstract: The Ursa Project, A Geologic and Developmental Overview of a Giant Oilfield in the Deepwater, Gulf of Mexico

Abstract: The Ursa Project, A Geologic and Developmental Overview of a Giant Oilfield in the Deepwater, Gulf of Mexico

Oil Migration in a Major Growth Fault: Structural Analysis of the Pathfinder Core, South Eugene Island Block 330, Offshore Louisiana

The Pathfinder core, collected in the South Eugene Island Block 330 field, offshore Louisiana, provides an outstanding sample of structures associated with a major growth fault that abuts a giant oil field and that is thought to have acted as a conduit for hydrocarbon migration into the producing reservoirs. Where cored, the growth-fault zone cuts semiconsolidated Pliocene-Pleistocene mudstone and is over 100 m wide. The fault zone in the core consists of three structural domains, each characterized by a distinct rock type, distribution of fault dips and dip azimuths, and distribution of spacing between adjacent faults and fractures. Although all of the domains contain oil-bearing sands, only faults and fractures in the deepest domain contain oil, even though the oil-barren fault domains contain numerous faults and fractures that are parallel to those containing oil in the deepest domain. The deepest domain is also distinguished from the other two domains by a greater degree of structural complexity and by a well-defined power-law distribution of fault and fracture spacings. Sediments in this domain behaved as competent rock with respect to fault and fracture spacing, whereas the departure from power-law distribution of fault and fracture spacing in the other two domains may reflect deformation of unconsolidated sediment. This departure from a power-law spacing distribution in the upper two domains, combined with stable isotope data that indicate low-temperature water-rock interaction within a gouge zone that separates these two fault domains, indicates that the faults in those domains may have been active only early in the history of the growth fault zone, when the sampled sediments were at shallow burial depths. Thus, these faults may predate oil migration. In contrast, the faults in the oil-bearing domain appear to have been active later in the fault zone’s history, when the sediments faulted as competent rock and when geologic and organic geochemical investigations indicate oil migrated into the Block 330 reservoirs. Even though oil is present in sands throughout the core, its restriction to faults and fractures in the youngest sampled portion of the fault zone implies that oil migrated only through that part of the fault that was active during the time when oil had access to it. The absence of oil in fractures or faults in the other, probably older, fault domains indicates that the oil was never sufficiently pressured to flow up the fault zone on its own, either by hydraulic fracture or by increased permeability as a result of decreased effective stress. Instead, fluid migration along faults and fractures in the Pathfinder core was enhanced by permeability created in response to relatively far-field stresses related to minibasin subsidence.

Geochemical Study of Upper Jurassic (Volgian) Black Shales from the Russian Platform

A geochemical study of Upper Jurassic black shales from the Russian Platform is presented. Samples were collected from Gorodische section, which is the type-section of the Russian 'Volgian' stage, located near Ulyanovsk along the Volga river. This section displays a 6 m thick series of black shales of Middle Volgian age (= Late Tithonian) which is a lateral equivalent of the so-called Bazhenova Formation, the main source rock of the West Siberian giant oil fields. Firstly, a bulk study by Rock-Eval pyrolysis of these black shales was performed, indicating TOC values ranging from 1 to 45% and HI between 25 and 700 mg HC/g TOC (Fig. 1) with slightly higher TOC and HI values in the higher part of the series. Such a

Abstract :Development, Optimization and Future Potential of a Giant Oil Field - A Case History: Weyburn Field Southeastern Saskatchewan

Abstract :Development, Optimization and Future Potential of a Giant Oil Field - A Case History: Weyburn Field Southeastern Saskatchewan

油田減退モデルによる世界の大型巨大油田の生産挙動に関する一試算

Oil production potential could be predicted by an Oil Field Depletion Model. Production calculated by the existing model declines earlier than field cases. Therefore we propose the following new model which is based on reserves and production data of 225 Large Giant Oil Fields (LGO) in the world(1) LGO can be classified by Production Ratio (PR): Cumulative production/Recoverable reserves, that is, PR>50%: Declining fields, PR=50%-10%: Plateau fields, PR<10%: New fields.(2) Production Profile ‘Stacking Theory’ can be recognized. A group of LGO sustain production until 60% of reserves have been produced, though single field declines production at 50% of the reserves produced. Plateau rate of the group is 60% of the sum of the peak rates of each oil field. Reserves vs. Production ratio (R/P) of the group is nearly doubled.(3) Decline curve defined by exponential decline of which rate is reciprocal of R/P at decline started, can be applied.(4) Build-up production may be assumed 10% of reserves.The model interprets each LGO groups:(1) 97 Declining group had declined since 1988 at the decline rate 6.25% per annum and will continue to decline exponentially.(2) 71 Plateau group will sustain its maximum production potential until the year 2014. Relatively smaller production rate results in slower decline of 3.6% per annum.(3) 57 New group would start production to fill up reduction of declining group. Ceiling of production rate will be calculated by R/P=16.A future production profile curve of the world LGO is illustrated by assuming 1.5% per year ascent of world oil demand. The curve may represent the production from the world proved oil reserves because remaining reserves and production rates of LGO are dominant, accounting for 66% and 58% of the world total, respectively.

Abstract: Geology &amp;amp; Production Implications of Debris Flows in the C &amp;amp; D Shale Reservoirs, Elk Hills Giant Oil Field, California&amp;nbsp;

Abstract: Geology &amp;amp; Production Implications of Debris Flows in the C &amp;amp; D Shale Reservoirs, Elk Hills Giant Oil Field, California&amp;nbsp;

Factors controlling the destruction or preservation of giant light oilfields

Study of a database of 350 giant oilfields show these to be dynamic short-lived phenomena, with a median age of 35 Ma. A third show evidence for post-entrapment destructive processes, particularly erosion, fault leakage, gas flushing and biodegradation. Many cases of biodegradation may occur prior to complete filling of the oilfield. Re-entrapment of oil released from spilling or breached traps is common. The main controls on oilfield preservation are post-entrapment tectonism and seal type, with temperature and hydrodynamic regimes being secondary factors. Destructive processes are concentrated in shallow and deep zones and in seepage-prone traps such as compressional anticlines. Such factors strongly influence the distribution of preserved light oilfields, with preservation potential maximized in tectonically quiescent basins with evaporite seals, e.g. the Middle East and the Permian Basin. More attention is required, particularly in older petroleum systems, to models involving post-entrapment leakage and re-migration.

Pattern Modification by Injection-Well Shut-ln: A Combined Cost-Reduction and Sweep-Improvement Effort

Summary The Rangely Weber Sand Unit is a mature giant oil field that is currently under tertiary recovery with CO2. The Rangely oil field has been developed in stages, as have most large oil fields. This staged development over 50 years has had a significant impact on the distribution of remaining movable oil. Simulation studies indicated that oil cut could be improved if injection patterns were modified by shutting in injection wells to take advantage of relative well maturity. A field pilot project based on these studies has yielded results that indicate improved economic performance because of lower operating costs related to improved oil cut and reduced well maintenance.

Evaluating Oil Quality and Monitoring Production from Heavy Oil Reservoirs Using Geochemical Methods: Application to the Boscan Field, Venezuela: ABSTRACT

Many oil fields worldwide contain heavy oil in one or more reservoir units. The low gravity of these oils is most frequently due to biodegradation and/or low maturity. The challenge is to find ways to economically recover this oil. Methods which reduce the operating costs of producing heavy oil add significant value to such projects. Geochemical techniques which use the composition of the reservoir fluids as natural tracers offer cost effective methods to assist with reservoir management. The low viscosity and gravity of heavy oil, combined with frequent high water cuts, low flow rates, and the presence of downhole artificial lift equipment, make many conventional production logging methods difficult to apply. Therefore, monitoring production, especially if the produced oil is commingled from multiple reservoirs, can be difficult. Geochemical methods can be used to identify oil/water contacts, tubing string leaks and to allocate production to individual zones from commingled production. An example of a giant heavy oil field where geochemical methods may be applicable is the Boscan Field in Venezuela. Low maturity oil, averaging 10{degrees} API gravity, is produced from the Eocene Upper and Lower Boscan (Miosa) Sands. Geochemical, stratigraphic and engineering data have helped to better define the controls onmore » oil quality within the field, identified new reservoir compartments and defined unique characteristics of the Upper and Lower Boscan oils. This information can be used to identify existing wells in need of workovers due to mechanical problems and to monitor production from new infill wells.« less

インドネシア共和国東カリマンタンのペチコガス田の探鉱

Peciko gas field is located in offshore area, southern part of Mahakam delta system, East Kalimantan, Indonesia. Mahakam delta has been developed in the region since the Oligocene to recent, and it had been proved as petroliferous area by the discovery of giant oil and gas fields. In the early delineation stage of Peciko gas field, northward deviation of the gas zones was recognized by the drilling results, and stratigraphic trap of sand pinch out was considered as the trapping mechanism to explain this phenomenon. But the accumulation of the formation pressure data and knowledge from the sequence stratigraphic study suggest that the distribution of Peciko gas zones are not controlled by the distribution of the sandstone layers, but by a hydrodynamic trapping mechanism. This trapping mechanism is generated by the expulsion of compaction water in prodelta muddy facies in the east and south of Peciko gas field. The recognition of hydrodynamic trapping mechanism in the early stage of delineation was significantly helped the field appraisal. Discovery of Peciko gas field by new play type of hydrocarbon accumulation highly graded up the potentiality of Mahakam delta, and the hydrodynamic trapping mechanism can be applied in other fields.

Episodic Migration of Natural Gas: A Worldwide Phenomenon of Dynamic Filling of Oil and Gas Fields: ABSTRACT

Natural gases form through bacterial and thermogenic conversion of organic matter over extended geological time. The isotopic properties of methane and C2+hydrocarbons are controlled by temperature dependent kinetic fractionation during maturation and mixing during migration and in reservoirs. Gas fields which are actively and repeatedly charged over extended periods of gas formation will receive compositionally and isotopically variable charges of natural gases that can mix in different proportions in single reservoirs. Episodic migration and multiple filling of reservoirs is a ubiquitous phenomenon observed in small and giant gas fields throughout the world. The following case histories from own research and from the literature will be discussed to illustrate this phenomenon: Gulf of Mexico: Pervasive mixing of bacterial and thermogenic gas charges results in large variations in isotopic signatures on a field and reservoir scale. Major formation and migration episodes are (1) Bacterial gases form in rapidly subsiding mini basins and migrate and accumulate around rising sell structures and active growth faults and (2) Following multiple charges of thermogenic gases mix in various proportions with bacterial gases. Angola: Giant oil fields off-shore Cabinda contain thermogenic gases with different isotopic signatures in the gas cap and the oil leg, indicating a multimore » phase migration of thermogenic; gases from mature to post-mature sources. The gas/oil columns are in some cases variable and suggest compartmentalization and/or unmixed oil hydrocarbon columns. Yacheng Gas Field: Gas composition and isotopic signatures of methane change from west to east in this giant field in the S. China Sea. Inert gas contents also vary vertically in the reservoir suggesting a late charge of a CO[sub 2] rich gas into the structure. South ltaly. Pliocene reservoirs in the Apulian Basin are mixtures of thermogenic and bacterial gases.« less

Design and Installation of an Ultra Deepwater Subsea System: How To Minimize Risks and Costs

Summary The world's deepest Subsea Tree was successfully installed offshore Brazilat a water depth of 1027m. The "psychological" barrier of 1000m was fmally broken. Actually, subsea completion technology reached a point where the fundamental question is no longer whether fields located at water depths beyond 1000m can be profitably completed. The key issue now is: is there a better and safer way to do it? PETROBRAS has pursued an aggressive strategy m research and development concept evaluations and various field studies aiming at a continuous decrease in both CAPEX and OPEX. This paper primarily describes the major subsea completion achievements, resulting from this great effort, which among other topics include:implementation of an standardization program; sharp reduction of both subseacompletion and drilling time; a new flowline connection method which combines the advantages of both lay-away and pull-in methods; design and future installation of the world first subsea electrical submersible pump; completion equipment simplification and resulting cost reduction. Also addressed are the key safety aspects related to deepwater completions and the equipment design improvement necessary to safely conduct those operations. Introduction Since its first Subsea Tree installation in June, 1979 on the RJS-3 8 well in 189m (620ft) water depth, PETROBRAS has been overcoming challenges towards deeper waters, basically motivated by its necessity of producing in increasingly water depths, where the latest important giant oil fields were discovered. Although presently only 22.5% (160000 bpd) of the production comes from wells that are located deeper than 400m, this figure is expected to reach61% by the year 2003. Since that first one up to now, 219 Subsea Trees have already been installed, breaking some remarkable barriers. In September, 1984 the first diverless Subsea Tree was run on the Pirauna-02well at 307m (1007ft) water depth, breaking the divers operational limits.

Crustal Oxidation State, Subduction Slab Segmentation, and Giant Oil Fields: ABSTRACT

Crustal Oxidation State, Subduction Slab Segmentation, and Giant Oil Fields: ABSTRACT

Sand Body Geometry and Permeability Areal Distribution in Fluvial Sandstones Reservoir: ABSTRACT

This paper describes as the integration between geological and reservoir engineering activities led to a more accurate definition of permeability areal distribution in a giant oil field where depositional environment retains a fundamental control on reservoir petrophysical characteristics. The data source was: well-log and well-test data of 60 wells, laboratory analyses and sedimentological studies of about 10 fully cored wells, more than 20 years of field performance. The sedimentological study pointed out the presence of three non-marine environments: low-sinuosity braided channel, overbank splay and flood basin. The areal distribution of these environments was controlled by the synsedimentary tectonic movement. Permeability/porosity correlations were investigated on the basis of core data and the continuous permeability profile was estimated. Based on these data the arithmetic, geometric and harmonic average were calculated to investigate the flow characteristics of the individual reservoir units by comparing the log permeability with the well-test permeability assumed as the reference value. The results of this comparison led to a further analysis of the sedimentological and electrofacies data. The following conclusions were drawn: the areas characterized by the arithmetic average correspond to over bank splay environment where low permeable sandstones with high lateral continuity sedimented; the areas characterized by themore » geometric and harmonic average correspond to channel environment where more permeable sandstones with poor lateral continuity sedimented. The permeability maps, optimized according to these sedimentological concepts, gave a fundamental improvement to the history match process.« less

Facies Variation, Diagenesis, and Exploration Potential of the Cretaceous Rudist-Bearing Carbonates of the Arabian Gulf

The Cretaceous rudist-bearing carbonates of the Arabian Gulf region are proven exploration targets for hydrocarbons and form the reservoirs of a number of giant fields, including Bu Hasa, Fateh, Fahud, Idd El Shargi, Rumaila, Shaybah, and Shah. Rudist buildups occur in three principal formations: (1) Aptian Shuaiba, (2) Cenomanian Mishrif, and (3) Maastrichtian Simsima. A regional subaerial unconformity marks the upper boundary of each of these formations. Associated with the rudists that dominate the Shuaiba Formation are calcareous algal crusts, foraminifera, and echinoid plates, which accumulated in mudstone, packstone, and carbonate sands. These rudists are mainly caprinids, with a lesser number of caprotinids, monopleurids, and requienids, deposited in a normal-marine shallow-shelf setting. The Mishrif Formation contains mollusk fragments, bioclastic packstones to grainstones, miliolid and nonrudist bivalves in muddy limestones, and rudist (mainly radiolitids and caprinids) conglomeratic floatstones, with fragmented rudists mixed with wackestone lithoclasts. The Mishrif sediments accumulated as a progradational, low-energy leeward margin formed in marginal slope, shoal-backshoal, and lagoonal settings. The Simsima Formation consists of bioclastic grainstone to packstone, and dolomitic lime mudstones to wackestone. These are rich in bioclastic grains (Loftusia, rudist and rudist debris, coral, and foraminifera) deposited on a restricted to semirestricted shallow-marine shelf that was exposed to moderate energy conditions. The excellent reservoir porosity and permeability of the rudist deposits and their associated sediments are the products of primary and secondary diagenesis. Freshwater leaching during post-Aptian, post-Cenomanian, and post-Maastrichtian erosion enhanced the secondary moldic porosity. Fracturing locally improved porosity and permeability. Other porosity types that occur include interparticle, intraparticle, vuggy, growth framework, shelter, intercrystalline, and karstic. Because of their favorable depositional and postdepositional conditions, the Cretaceous succession of rudists in this region contains many giant oil fields.

Devonian and Carboniferous Carbonates of Southern Kazakhstan: Depositional Analogs for Coeval Giant Oil and Gas Fields in the North Caspian Basin, Western Kazakhstan: ABSTRACT

Devonian and Carboniferous Carbonates of Southern Kazakhstan: Depositional Analogs for Coeval Giant Oil and Gas Fields in the North Caspian Basin, Western Kazakhstan: ABSTRACT

Petroleum Geology of Giant Oil and Gas Fields in Turpan Basin, Xinjiang, China: ABSTRACT

Petroleum Geology of Giant Oil and Gas Fields in Turpan Basin, Xinjiang, China: ABSTRACT

Geologic Evolution of a Pliocene-Pleistocene Salt-Withdrawal Minibasin: Eugene Island Block 330, Offshore Louisiana

The spatial and temporal distributions of reservoir sands are documented within the context of an evolving Pliocene-Pleistocene salt-withdrawal shelf minibasin. The Eugene Island Block 330 field, a giant oil and gas field in offshore Louisiana, is contained within the minibasin. Based on the stratigraphic and structural analyses, we present a sequence-stratigraphic and tectonic-stratigraphic model for reservoir prediction in complex shelf Gulf of Mexico minibasins. The minibasin evolved in three phases: prodelta, proximal deltaic, and fluvial. In the prodelta phase, bathyal and outer neritic shales and turbidites loaded and mobilized an underlying salt sheet. During the proximal deltaic phase, salt continued to withdraw from beneath the minibasin, and lowstand shelf margin deltas remained at a regional fault zone on the northern margin of the minibasin. Sediment accumulation and fault slip rates were high as thick sequences of deltaic sands were deposited adjacent to the fault system. During the final fluvial phase, salt withdrawal waned; consequently, the creation of accommodation space within the minibasin ceased. The basin infilled and, during lowstands, deltaic systems prograded southward. Unconformities developed in the minibasin during the e lowstands. During transgressions, thick packages of shallow-water deltaic and fluvial sands (capped by shales) were deposited on top of the unconformities. One major reservoir, the Lentic, was deposited during the prodelta phase. The hydrocarbons are trapped by deep early faults within this geopressured sand. Most of the major exploited reservoirs of the Block 330 field were deposited in the proximal deltaic phase. Reservoirs deposited in this phase are laterally extensive proximal deltaic sands that have good lateral seals because of the amount of fault activity that occurred in this interval. Only one major reservoir was deposited in the fluvial phase. This reservoir was deposited while the basin-bounding faults were still active, so the reservoir has four-way closure. Sands deposited later in the fluvial phase tend to lack lateral seals and structural closure.

A Structurally Complex and Dynamic Reservoir Description for Reservoir Simulation, Kuparuk River Field, Alaska: ABSTRACT

The Kupanuk River Field is a structurally complex giant oil field adjacent to the Prudhoe Bay Field on Alaska`s North Slope. Oil is reservoired within two Early Cretaceous shallow marine sandstone formations, separated stratigraphically by an erosionally truncated marine silt/shale. Subjected to several phases of tectonism, this highly compartmentalized reservoir has been developed on regular 160 acre direct line drive patterns. An integrated team of geoscientists and engineers from BP Exploration (Alaska) Inc. and ARCO Alaska Inc. is presently quantifying the benefits of infill drilling at Kuparuk, and identifying the best locations for well placement. The two primary reservoir characteristics believed to impact the effectiveness of infill drilling are large-scale reservoir heterogeneity, and reservoir comparmentation due to faulting. Multiple thin pay zones within the two reservoir intervals are isolated laterally by faults with magnitudes greater than pay zone thickness. A process and tools designed to construct and maintain a structurally complex reservoir description, shared by the geoscientists and reservoir engineers, are described. Cross-discipline integration is aided by the use of Tech*Logic`s IREX 3-D reservoir modeling and visualization application. The unique architecture of the IREX model allows for representation of very complex structural geometries, and facilitates iteration between reservoir description andmore » simulation, along the seismic to simulation continuum. Modifications to the reservoir description are guided by well-level history matching within the constraints of all available geoscience information. The techniques described will be of particular interest to those working on reservoir description and simulation of structurally complex fields.« less

Revisiting Our Predictions of Petroleum Reservoir Properties, U.S. East Coast Mesozoic Offshore: ABSTRACT

In the early 1980`s the major international oil corporations were focusing on potential giant oil fields in the U.S. frontiers. The offshore U.S. East coast Mesozoic shelf edge was one such frontier play area. The oil industry was preoccupied by an apparent continuous Mesozoic shelf edge build-up which appeared in seismic records. At the time there were no wells that penetrated the seismic build-up. Additionally, the shelf edge prospects were in water depths exceeding 1500 meters making difficult drilling technological problems and associated extremely high expenses. What made the U.S. East Coast so attractive was that if carbonate reservoirs did exist the oil potential would be in the ten`s of billions of barrels range. In the June 1983 issue (volume 67/6) of the A.A.P.G. Bulletin, Gerald Friedman and the author published an article applying modern carbonate diagenetic findings in conjunction with the global seismic stratigraphy of P.R. Our article predicted porous carbonate build-ups formed during low sea-level stand in the Middle Jurassic, Late Jurassic, and Lower Cretaceous Age rocks. In the mid 1980`s, Shell Oil Corporation drilled seaward off the continental shelf edge. The wells encountered Jurassic and Cretaceous carbonate shelf edge oolitic grainstones, coral stromatoporoid grainstones and boundstones. Core,more » and log analysis reveal that reservoir quality carbonates do exist with the Jurassic and Cretaceous Age carbonate rocks. He suggested the porosity was formed during various subaerial exposures caused by low sea level stands. In summary, our integration of global seismic stratigraphy and modern carbonate diagenetic models help predict reservoir quality in a totally undrilled area of continental proporations. Unfortunately, thus far the tested prospect was water saturated (wet). In the foreseeable future with the price of crude oil at its current level it is unlikely any further drilling will take place.« less