Showing papers on "Petroleum reservoir published in 2003"

Petroleum geology and potential hydrocarbon plays in the Gulf of Suez rift basin, Egypt

Abstract: The Gulf of Suez in Egypt has a north-northwest–south-southeast orientation and is located at the junction of the African and Arabian plates where it separates the northeast African continent from the Sinai Peninsula. It has excellent hydrocarbon potential, with the prospective sedimentary basin area measuring approximately 19,000 km 2 , and it is considered as the most prolific oil province rift basin in Africa and the Middle East. This basin contains more than 80 oil fields, with reserves ranging from 1350 to less than 1 million bbl, in reservoirs of Precambrian to Quaternary age. The lithostratigraphic units in the Gulf of Suez can be subdivided into three megasequences: a prerift succession (pre-Miocene or Paleozoic–Eocene), a synrift succession (Oligocene–Miocene), and a postrift succession (post-Miocene or Pliocene–Holocene). These units vary in lithology, thickness, areal distribution, depositional environment, and hydrocarbon importance. Geological and geophysical data show that the northern and central Gulf of Suez consist of several narrow, elongated depositional troughs, whereas the southern part is dominated by a tilt-block terrane, containing numerous offset linear highs. Major prerift and synrift source rocks have potential to yield oil and/or gas and are mature enough in the deep kitchens to generate hydrocarbons. Geochemical parameters, sterane distribution, and biomarker correlations are consistent with oils generated from marine source rocks. Oils in the Gulf of Suez were sourced from potential source rock intervals in the prerift succession that are typically oil prone (type I), and in places oil and gas prone (type II), or are composites of more than one type (multiple types I, II, or III for oil prone, oil and gas prone, or gas prone, respectively). The reservoirs can be classified into prerift reservoirs, such as the Precambrian granitic rocks, Paleozoic–Cretaceous Nubian sandstones, Upper Cretaceous Nezzazat sandstones and the fractured Eocene Thebes limestone; and synrift reservoirs, such the Miocene sandstones and carbonates of the Nukhul, Rudeis, Kareem, and Belayim formations and the sandstones of South Gharib, Zeit, and

A plant and a method for increased oil recovery

Abstract: A method for increasing oil recovery from an oil reservoir by injection of gas into the reservoir, is described. The method comprises separation of air into an oxygen-rich fraction and a nitrogen-rich fraction, reformation of natural gas together with oxygen to produce a synthesis gas for production of methanol or other oxygenated hydrocarbons or higher hydrocarbons. The raw synthesis products and a waste gas from the synthesis are separated, and the nitrogen-rich fraction and at least a part of the waste gas are injected into the oil reservoir to increase the oil recovery from the reservoir. A plant for performing the method is also described.

Modelling of Stress Development and Fault Slip in and around a Producing Gas Reservoir

Abstract: Many gas fields are currently being produced in the northern Netherlands. Induced seismicity related to gas production has become a growing problem in the Netherlands in the past two decades. To date, a few hundred induced seismic events occurred. Induced seismicity is generally assumed to be the result of induced reactivation of discontinuities in the subsurface. Field data of the Groningen and Annerveen gas fields as well as other Rotliegend gas fields in the Netherlands are analysed. A large amount of seismic cross sections through seismic events is studied. It is very likely that the seismic events are the result of reactivation of existing discontinuities (like faults) in or near the reservoirs. The objective of the research presented in this dissertation is to obtain a better understanding of the mechanisms of gas production induced reactivation of faults by means of 3D geomechanical modelling of gas reservoirs. It is a step towards future assessment of expected seismic energy release when (further) developing gas fields in the Netherlands. Furthermore, attention is given to the development of several quantification methods, used for the analysis of the calculation results. Quantification methods include relative shear displacements, seismic moment, stress paths, mobilised shear capacity and total stress changes per unit depletion. The geomechanical models represent the geometries found in the seismic cross sections. The models contain a disk-shaped gas reservoir in an extensional stress regime. A steeply dipping normal fault plane intersects the reservoir and divides it into two compartments: a footwall and a hanging wall reservoir compartment. Stress development and fault slip during gas depletion are analysed. Gas depletion can lead to both normal and reverse fault slip on the same fault plane. In the given setting of a steeply dipping normal fault in an extensional stress regime, normal fault slip due to differential reservoir compaction is the dominant mechanism, rather than reverse fault slip. The effect of differential reservoir compaction is most pronounced for a configuration, where the top of the hanging wall reservoir compartment is positioned exactly opposite to the bottom of the footwall reservoir compartment, resulting in a relatively large amount of fault slip over a narrow area. Normal fault slip is supported by equal depletion of both reservoir compartments. Reverse fault slip is supported by differential pore pressure development due to reservoir compartmentalisation. Especially the combination of a relatively stiff surrounding rock and differential pore pressure development due to reservoir compartmentalisation can result in relatively large amounts of reverse fault slip. Both normal and reverse fault slip are promoted by a Young's modulus or Poisson's ratio of the surrounding rock larger than those of the reservoir rock (Esur > Eres or I½sur > I½res). The initial state of stress is relatively closer to the failure line than in case of a smaller stiffness contrast. Esur < Eres and I½sur < I½res oppose the reactivation of the fault. Values of I½sur lower than 0.2 seem to have no significant influence on the calculated maximum normal fault slip. Calculations indicated that the Young's modulus of the surrounding rock is a more important parameter influencing gas depletion induced fault slip than the Poisson's ratio of the surrounding rock. Calculations with a 3D anisotropic tectonic stress field show a strong dependency of the amount of calculated fault slip on the direction of the maximum horizontal stress with respect to the fault strike direction. Most normal fault slip occurs when the maximum horizontal stress is directed parallel to the fault strike. Minimum normal fault slip is calculated for a maximum horizontal stress direction perpendicular to the strike direction of the fault. A larger horizontal stress component parallel to the azimuth of the fault has a limiting effect on the fault slip. Total fault slip can consist of a dip slip and a strike slip component. In case of a horizontal reservoir, no significant strike slip is observed when the fault strike direction is a principal stress direction. A certain amount of strike slip is observed for calculations with an angle between the maximum horizontal stress direction and the fault strike direction of 31°, 45° and 59°. Strike slip contributes to both normal and reverse fault slip.

Improved Models for Petrophysical Analysis of Dual Porosity Reservoirs

Abstract: The analysis of vuggy and fractured reservoirs has been an area of significant interest in the past few past years. Several researchers have studied the characterization of these reservoirs and have looked for means of estimating values of the porosity exponent m for use in calculations of water saturation. We have found that some of the models for non-connected vugs fail for certain combinations of matrix and non-connected vug porosities. The reason for the failures is an improper scaling of the matrix porosity. The same scaling problem is present in some of the models to analyze naturally fractured reservoirs but the magnitude of the error in the calculation of m is very small for most cases of practical importance. We present an improved model for reservoirs with non-connected vugs that is shown to hold for all combinations of matrix and non-connected vug porosities. The model is validated with data for carbonate reservoirs published previously in landmark works by Lucia (1983, 1995). We also present an improved model for reservoirs with natural fractures and/or connected vugs.

Halite Scale Formation in Gas-Producing Wells

Abstract: In Northern German gas reservoirs, the precipitation of salt from the reservoir water is observed to an increasing extent as recovery progresses. The resulting halite scale causes a significant decrease in production rate, all the way to complete blockage of the flow paths and ultimately the abandonment of wells. In order to remove salt deposits as well as prevent the precipitation of salt in the zone immediately surrounding the well, fresh water treatments are performed at regular intervals during production operations. This paper addresses the entrainment of reservoir water from gas reservoirs, even in reservoirs without active edge-water drive, and the halite precipitation in depleted gas wells on the basis of theoretical considerations. The discussion includes a description of chemical parameters determined from analysis of reservoir water for the early detection of salt precipitates in the reservoir rock. Besides the implementation of the fresh water treatment in practice, special attention is paid to the dissolution behaviour of halite scale. The ionic distribution in the back-produced treatment fluid is evaluated with reference to the prevailing reservoir conditions. During the past 17 years, a large number of fresh water stimulations have been conducted in Northern German gas reservoirs. The results of these operations are explained in detail. The success of the stimulation based on the change in productivity index is evaluated and interpreted for parameters such as treatment volume and shut-in time.

Northern Tunisia Thrust Belt: Deformation Models and Hydrocarbon Systems

Abstract: The integrated use of the geological, geophysical, and geochemical data of northern Tunisia onshore and offshore led to an inversion model from the Tethyan rifting and subsequent evolution of the North African passive margin to the Late Cretaceous–Tertiary orogeny, inducing the fold and thrust belt and associated foreland deformations. Respective deposits characterize each tectonic cycle; Triassic synrift and Jurassic–Cretaceous open-marine series are related to the Mesozoic opening, and Paleogene–Neogene clastic sequences are closely controlled by the Tertiary shortening. For hydrocarbon prospectivity and despite its early stage of exploration, this domain could be considered as an emerging area with encouraging ingredients, particularly three fractured carbonate reservoirs, two sandy reservoirs, five source rocks, and numerous potential structural and stratigraphic traps. The main feature in this area is the close relationship between the Tertiary tectonics and the evolution of the petroleum systems. Hence, the Numidian turbidites identified both as reservoir and source rock were deposited in a foredeep directly generated by the Paleogene thrusting and later displaced as far-traveled nappes above the Ypresian fractured limestones defined also as a source rock and reservoir. The maturity of these source rocks is closely related to the nappes displacement, which assumes the overburden and increases the heat flow. Fracturing is also generated by these events.

Reservoir rock classification, Arab-D reservoir, Ghawar field, Saudi Arabia

Abstract: An integrated petrographic and petrophysical study of Arab-D carbonates in Ghawar field has provided a new reservoir rock classification. This classification provides a simple but practical method of dividing the complex carbonate rocks of the Arab-D into meaningful reservoir rock types. Each rock type has a distinct pore network as defined by porosity-permeability relationships and capillarity expressed as pore-size distributions and J-function curves. The classification divides the Arab-D carbonates into seven limestone and four dolomite rock types. The amount of matrix (lime mud) and the pore types are the primary controlling parameters for the limestones. The dolomites are divided according to their crystal texture. The seven limestone reservoir rock types are based on the values of five petrographic parameters: (1) the amount of cement, (2) the amount of matrix (lime mud), (3) the grain sorting, (4) the dominant pore type, and (5) the size of the largest molds. The amount of matrix is the most important of these five parameters. In general terms, six of these seven types fall into two broad families, A and B, each of which can then be subdivided into three members (Types I, II, and III) according to their matrix content. The first family, A, is a fairly coarse-grained, poorly sorted rock with relatively large molds. The second family, B, is a generally fine to medium-grained, well sorted rock with few or small molds. The seventh rock type contains more than 10 percent cement which modifies the pore size distribution enough to warrant a separate reservoir rock type. Each of the reservoir rock types exhibits a distinctive pore-size distribution and, in turn, Leverett J-function or capillarity. The seven types are also characterized by distinctive porosity-permeability relationships. The four dolomite reservoir rock types are classified according to their dolomite crystal texture, although stratigraphic position and porosity can also be effective in their classification. The four textures are: fabric preserving (Vfp), sucrosic (Vs), intermediate (Vi) and mosaic (Vm). The Vfp dolomite is only found in Zone 1 of the Arab-D where it is the major dolomite type. Vs dolomite occurs in dolomites with more than 12 percent porosity, Vm less than 5 percent and Vi between 5 and 12 percent. Vfp dolomites have pore systems similar to their precursor limestone but the pore systems of the other dolomite types are unique. A significant finding of this evaluation is that the micropore system in all major limestone rock types in Zones 1 and 2 (upper Arab-D) is consistently an order of magnitude larger than for the same rock types in Zones 3 and 4 (lower Arab-D). The increase in size is believed to be a result of increased leaching in the upper Arab-D. This difference suggests that rocks of similar type from the upper and lower Arab-D will behave differently in terms of their fluid flow and saturation characteristics, and will have different ultimate recoveries.

Fully coupled modeling of seabed subsidence and reservoir compaction of North Sea oil fields

Abstract: This paper focuses on the aspects of fully coupled continuum modeling of multiphase poroelasticity applied to the three-dimensional numerical simulations of the Ekofisk oil reservoir in the North Sea (56°29′–34′N, 03°10′–14′E). A systematic presentation is chosen to present the methodology behind fully coupled, continuum modeling. First, a historical review of the subsidence phenomena above an oil and gas reservoir is given. This will serve as a background against which the relevance of the present approach to compaction and subsidence modeling will be demonstrated. Following this, the governing equations for a multiphase poroelasticity model are briefly presented. Particular attention is paid to the analysis of the pore-compressibility term usually used in an uncoupled approach for characterising the host-rock deformation. A comparative numerical analysis is carried out to contrast and highlight the difference between coupled and uncoupled reservoir simulators. Finally, a finite-element numerical model of the Ekofisk field is presented and a significant result is a contour map of seabed subsidence which is in general agreement with the shape of the subsidence contours based on past bathymetric surveys. Analysis of the simulation reveals that, due to the downward movement of the overburden, oil migration occurs from the crest of the anticline in which the field is situated, towards the flank. The pore-pressure depletion in the reservoir is significantly delayed due to the replenishment of the reservoir energy via the formational compaction. Horizontal movement in the reservoir, which is neglected in traditional modeling, can be significant and comparable in magnitude to the vertical subsidence.

Palaeo-carbonate seep structures above an oil reservoir, Gryphon Field, Tertiary, North Sea

Abstract: Petrographic and geochemical analyses performed on a North Sea core from the Gryphon Field reveal the presence of palaeo-degassing features surrounded by injected sandstones in the Eocene interval. The injected sandstones are oil-stained and poorly cemented by carbonate and quartz. 18O isotope analyses indicate that carbonate cementation occurred during shallow burial (likely less than about 300 m). Depleted 13C (around −30‰ V-PDB) carbonate cement suggests that bicarbonate was derived from the microbial oxidation of oil and gas. Late quartz overgrowths enclose oil present in the injected units. The tubular degassing conduits are composed of zoned cements and have δ18O and δ13C isotope values similar to the injected sandstones, indicating that oil and gas seepage induced the precipitation of authigenic carbonate in the shallow subsurface. Oil inclusions in inter- and intra-crystal cement sites in both injected sandstones and degassing conduits indicate that oil seepage was an ongoing feature at shallow burial. A proposed model involves oil and gas seepage and the formation of the degassing conduits, followed by a sand injection phase. It seems likely that oil and gas continued to leak towards the seabed by exploiting the network of permeable injected sandstones and the horizons of porous degassing features.

Major oil plays in utah and vicinity

Abstract: Utah oil fields have produced a total of 1.2 billion barrels (191 million m{sup 3}). However, the 15 million barrels (2.4 million m{sup 3}) of production in 2000 was the lowest level in over 40 years and continued the steady decline that began in the mid-1980s. The Utah Geological Survey believes this trend can be reversed by providing play portfolios for the major oil producing provinces (Paradox Basin, Uinta Basin, and thrust belt) in Utah and adjacent areas in Colorado and Wyoming. Oil plays are geographic areas with petroleum potential caused by favorable combinations of source rock, migration paths, reservoir rock characteristics, and other factors. The play portfolios will include: descriptions and maps of the major oil plays by reservoir; production and reservoir data; case-study field evaluations; summaries of the state-of-the-art drilling, completion, and secondary/tertiary techniques for each play; locations of major oil pipelines; descriptions of reservoir outcrop analogs; and identification and discussion of land use constraints. All play maps, reports, databases, and so forth, produced for the project will be published in interactive, menu-driven digital (web-based and compact disc) and hard-copy formats. This report covers research activities for the first quarter of the first project year (July 1 through September 30, 2002). This work included producing general descriptions of Utah's major petroleum provinces, gathering field data, and analyzing best practices in the Utah Wyoming thrust belt. Major Utah oil reservoirs and/or source rocks are found in Devonian through Permian, Jurassic, Cretaceous, and Tertiary rocks. Stratigraphic traps include carbonate buildups and fluvial-deltaic pinchouts, and structural traps include basement-involved and detached faulted anticlines. Best practices used in Utah's oil fields consist of waterflood, carbon-dioxide flood, gas-injection, and horizontal drilling programs. Nitrogen injection and horizontal drilling programs have been successfully employed to enhance oil production from the Jurassic Nugget Sandstone (the major thrust belt oil-producing reservoir) in Wyoming's Painter Reservoir and Ryckman Creek fields. At Painter Reservoir field a tertiary, miscible nitrogen-injection program is being conducted to raise the reservoir pressure to miscible conditions. Supplemented with water injection, the ultimate recovery will be 113 million bbls (18 million m{sup 3}) of oil (a 68 percent recovery factor over a 60-year period). The Nugget reservoir has significant heterogeneity due to both depositional facies and structural effects. These characteristics create ideal targets for horizontal wells and horizontal laterals drilled from existing vertical wells. Horizontal drilling programs were conducted in both Painter Reservoir and Ryckman Creek fields to encounter potential undrained compartments and increase the overall field recovery by 0.5 to 1.5 percent per horizontal wellbore. Technology transfer activities consisted of exhibiting a booth display of project materials at the Rocky Mountain Section meeting of the American Association of Petroleum Geologists, a technical presentation to the Wyoming State Geological Survey, and two publications. A project home page was set up on the Utah Geological Survey Internet web site.

Onshore otway basin carbon dioxide accumulations: co2-induced diagenesis in natural analogues for underground storage of greenhouse gas

Abstract: The study of natural carbon dioxide (CO2) accumulations, such as those found in the onshore Otway Basin, is necessary for the validation of underground long-term storage technology as an option for decreasing greenhouse gas emissions. The investigation of natural CO2 occurrences is being investigated as part of the Geological Disposal of Carbon Dioxide (GEODISC) research program. This study identifies the effects of CO2 on reservoir rock’s mineralogy through time as well as its porosity and permeability. The Otway Basin CO2 accumulations display variations in reservoir type, CO2 concentration and time of injection. A range of typical reservoirs types for the CO2 accumulations occurs in the Otway Basin, including feldspathic litharenites, subfeldsarenite and quartz arenite. CO2 concentrations in the Otway Basin vary greatly in the accumulations studied, ranging from 10 mol% within the Port Campbell Field to 99 mol % in the Caroline Field. The source of the CO2 is degassing of the deep-seated magmas of the Newer Volcanics, with CO2 influx occurring between ~2 million to as recently as 5,000 years ago. This study investigated three areas of the Otway Basin; Penola Trough—Ladbroke Grove, Katnook (non-CO2) Port Campbell Embayment—Boggy Creek, Langley, Port Campbell; and Gambier Sub-Basin—Caroline Due to their close proximity and similar geological history prior to CO2 influx, the Ladbroke Grove-Katnook gas accumulations are particularly useful for examining differences between a CO2-rich (Ladbroke Grove) and a CO2-absent field (Katnook) and for developing a post- CO2 diagenetic history. Variation in grain size and CO2 concentration affects the degree of reaction of CO2 with the reservoir rock. Petrology and formation water chemistry of these fields indicate that CO2 has modified the rock properties. In all CO2-rich reservoirs examined (>10 mol % CO2), dissolution and alteration of lithic and felsic framework grains has occurred (e.g. albite dissolution). Clays and cements throughout most of the Otway Basin CO2 accumulations are modified to minerals more stable in the changed gas compositions (e.g. chlorite to kaolin). The change in mineralogy after the recent CO2 influx shows that the Pretty Hill Formation with high amounts of reactive minerals and smaller grain size is an effective reservoir unit for mineral storage of CO2. Longterm storage in the Waarre Sandstone quartz-rich reservoirs also displays the effectiveness of CO2 storage in pore space. This study of natural accumulations of CO2 has demonstrated that geological storage of CO2 is a viable option. Understanding of the mineral reactions involved with CO2 in reservoir rock is vital for selection of storage sites and modelling the behaviour of CO2 in the subsurface.

Carboniferous-Rotliegend total petroleum system; description and assessment results summary

Abstract: The Anglo-Dutch Basin and the Northwest German Basin are two of the 76 priority basins assessed by the U.S. Geological Survey World Energy Project. The basins were assessed together because most of the resources occur within a single petroleum system (the Carboniferous-Rotliegend Total Petroleum System) that transcends the combined Anglo-Dutch Basin and Northwest German Basin boundary. The juxtaposition of thermally mature coals and carbonaceous shales of the Carboniferous Coal Measures (source rock), sandstones of the Rotliegend sedimentary systems (reservoir rock), and the Zechstein evaporites (seal) define the total petroleum system (TPS). Three assessment units were defined, based upon technological and geographic (rather than geological) criteria, that subdivide the Carboniferous-Rotliegend Total Petroleum System. These assessment units are (1) the Southern Permian Basin-Offshore Europe Assessment Unit, (2) the Southern Permian Basin Onshore Europe Assessment Unit, and (3) the Southern Permian Basin Onshore United Kingdom Assessment Unit. Although the Carboniferous-Rotliegend Total Petroleum System is one of the most intensely explored volumes of rock in the world, potential remains for undiscovered resources. Undiscovered conventional resources associated with the TPS range from 22 to 184 million barrels of oil, and from 3.6 to 14.9 trillion cubic feet of natural gas. Of these amounts, approximately 62 million barrels of oil and 13 trillion cubic feet of gas are expected in offshore areas, and 26 million barrels of oil and 1.9 trillion cubic feet of gas are predicted in onshore areas.

Upper Jurassic (Oxfordian) Smackover carbonate petroleum system characterization and modeling, Mississippi Interior Salt Basin area, northeastern Gulf of Mexico, USA

Abstract: The Upper Jurassic (Oxfordian) Smackover Formation is a prolific oil and gas reservoir in the northern Gulf of Mexico, including the Mississippi Interior Salt Basin area. The Smackover petroleum system is categorized as a giant petroleum system and ranks fourth among recognized Upper Jurassic petroleum systems. In the Mississippi Interior Salt Basin area, the components of the Smackover petroleum system include pre rift, syn rift and post rift siliciclastic, evaporite, and carbonate underburden and overburden rocks, Smackover subtidal lime mudstone source rocks, uppermost Smackover anhydrite and Buckner Anhydrite Member subaqueous saltern and sabkha seal rocks, and upper Smackover shoal complex and tidal flat complex packstone, grainstone, boundstone and dolostone reservoir rocks. The critical events include the initiation of the generation of crude oil, the commencement of hydrocarbon expulsion, the initiation of hydrocarbon migration, and the entrapment of hydrocarbons during the Early to Late Cretaceous. The critical moment for the Smackover petroleum system is the time of peak hydrocarbon expulsion in the mid to late Early Cretaceous in basin center areas and mid to latest late Cretaceous in areas along the northern basin margin. *** DIRECT SUPPORT *** A00QA034 00003

Barracuda and Roncador Giant Oil Fields, Deep-water Campos Basin, Brazil

Abstract: The Barracuda and Roncador giant oil fields, located in the Campos Basin, southeastern Brazil, represent two of the most important worldwide discoveries in the last decade, containing estimated reserves of almost 4 billion BOE accumulated in siliciclastic turbidites. Both fields are located in deep and ultradeep waters, with water depth extending from 600 to 2100 m.The Barracuda field was discovered in April 1989 by the 4-RJS-381 well in a water depth of 980 m. It covers an area of about 157 km2, in water depths ranging between 600 and 1200 m. It produces from Tertiary turbidite reservoirs. Seismic attribute analysis discriminates oil-saturated Paleocene, Eocene, and Oligocene sandstones encased in shale and marls, mainly in stratigraphic traps. This giant oil field contains in-place volumes of 2.7 billion bbl, and the total reserves achieved 659 million bbl (for Oligocene reservoirs) and 580 million bbl (for Eocene reservoirs).The Barracuda field is under development along with the Caratinga field because of their geographic proximity. The development strategy foresees an ongoing pilot system (concluded in October 2002) and a definitive one (being implemented). The pilot system started production in 1997 through a floating production, storage, and offloading (FPSO)-type stationary production unit. Production by means of the definitive system is expected to start in the second semester of 2004 and comprises 20 production and 14 injection wells. The loading, processing, and offloading of the oil and gas from the field will be through an FPSO unit with processing capacity of 150,000 BOPD and 4.8 million m3/day of gas. The peak production is expected in 2006.The Roncador field, discovered in October 1996 by the 1-RJS-436A wildcat, is in water depths ranging from 1500 to 2100 m. This giant field contains large volumes of hydrocarbons (9.2 billion bbl of oil in place and total reserves of 2.6 billion BOE) accumulated in Upper Cretaceous (Maastrichtian) turbidite reservoirs.The discovery well found total net pay of 153 m of Maastrichtian reservoirs divided into five main zones, separated by interbedded shales. Only the uppermost reservoir zone shows a seismic amplitude anomaly that can be detected on seismic profiles. The other four reservoirs do not show acoustic impedance contrasts with the interbedded shales, and thus they have no amplitude anomalies.During the appraisal activities, different types of oil (18–31.5 API) and a high reservoir complexity were verified. The external geometry is defined to the north and east by dipping and to the south and west directions by pinch-out. The trap is a combined structural and stratigraphic trap. The field is cut by some major faults to form three main blocks: an upthrown southwestern block, an upthrown northern block, and a downthrown southeastern block.Because of the size of the field and large volumes of hydrocarbon production, development of the Roncador field is envisaged to occur in four modules. Production peak will reach 500,000 BOPD in 2011. Production module I is being implemented to produce oil from the northern and eastern blocks, including 21 subsea production and 7 subsea water injection wells. Module II will develop the western block (heavy oil); two production units are planned (one deep-draft caisson vessel [SPAR] and one floating production, storage, and offloading [FPSO] unit). Peak production is expected to reach 180,000 BOPD from 31 wells in 2 yr.

Relationship of reservoir properties for shaly sandstones based on effective porosity

Abstract: Effective porosity is the proportion of total porosity that contributes to fluid flow in a reservoir. Reservoir properties such as permeability and capillary pressures are related to effective porosity. The presence of clay minerals in shaly sandstones introduces microporosity, and thus makes it difficult to estimate accurately the permeability. We find that previous estimates of clay microporosity permit more accurate predictions of effective porosity, permeability, and capillary displacement pressures for shaly sandstones. In this study, a single data set from the literature is used to illustrate the relationship between effective porosity and permeability, and capillary pressure. The data set consists of 14 samples, which were drawn deliberately from a larger sample population of 44 petroleum reservoir sandstones. These samples cover a range of porosity and air permeability ranging from 8.45-to-26.5% and 0.031-to-1173 millidarcy, respectively. Our results indicate that effective porosities can be applied to predict permeability and capillary displacement pressure for a wide range of shaly reservoir sandstones. The prediction of permeability by the widely used Kozeny-Carman equation can also be improved by effective porosity. The basis for the correlation between permeability and effective porosity is the strong relationship between the latter and median pore-throat diameter.

Reservoir geometry of fluvial distributary channels-implications for northwest shelf, Australia, deltaic successions

Abstract: The exploration and development of stratigraphically trapped hydrocarbons requires detailed knowledge of the morphologies and reservoir characteristics of the stratigraphic body. Fluvial distributary channels are important exploration targets because they are typically isolated reservoirs, laterally and vertically sealed by delta plain and abandoned channel mudstone, and thus form excellent stratigraphic traps. The morphology and reservoir characteristics of fluvial distributary channels have been confused with fluvial channels in the past. Knowing the characteristics of fluvial distributary channels and their difference from fluvial channels is the key to the successful exploration and development of distributary channel reservoirs. Fluvial distributary channels, formed by mixed-load systems, are commonly rectilinear channel segments found only on the delta plain between the head of passes and the depositional mouthbars. While fluvial channel reservoirs are mainly sandstone deposits of meander pointbars or braided sheets, fluvial distributary channel reservoirs are typically elongated sandy channel sidebars attached to morphologically rectilinear channel walls. The sidebars form by both lateral and downstream accretion resulting from flow in a confined, but lowsinuosity thalweg, which may be filled with organic mud following channel abandonment. On 3D seismic data the morphology of a fluvial distributary channel is often slightly sinuous and can easily be mistaken for part of a meander channel belt. Fluvial distributary channels are usually thinner and shallower compared to their updip fluvial channel belts. Width-thickness ratios for fluvial distributary channel reservoirs are on average 50:1 (range 15:1 to 100:1), while meandering fluvial channel reservoirs have widththickness ratios typically >100:1, and braided river reservoirs show ratios of 500:1 or higher. Examples from the Mahakam Delta are used to illustrate these issues. Implications for exploration and development of deltaic deposits on the North West Shelf of Australia are discussed.

Petroacoustic Characterization of Reservoir Rocks for Seismic Monitoring Studies. Laboratory Measurement of Hertz and Gassmann Parameters

Abstract: The production of oil and gas reservoirs, or the storage of gas in geological formations, always has direct repercussions on the fluid content and pore pressure, and hence on the seismic properties of reservoir rocks. This article describes the laboratory methods used to measure the effect of variations in differential pressure and saturating fluid on elastic wave propagation velocities in reservoir rocks. The pressure effect is easy to measure in the laboratory, via the Hertz coefficient, exponent of the power function linking the velocity to the differential pressure. It is difficult to estimate the representativity of core samples that have undergone the sudden stress relaxation caused by coring. A statistical comparison of the measurement results on surface samples and core samples confirms the reality of this damage. The values measured in the laboratory are often values from above. They are very useful for setting the upper bounds of the anticipated effect of differential pressure. This effect is often negligible in many limestone reservoirs. It may be high or overpressurized in shallow sandstone reservoirs (underground storage facilities). The effect of the saturating fluid is quantified by the Gassmann formula, the value of which is usually confirmed by experiment. The use of this formula requires the knowledge of certain elastic properties of the rock. These moduli can be determined at the laboratory. We propose an original method that is also simple in principle, based on the experimental measurement of the quasi linear relation predicted by the Biot-Gassmann theory, between the bulk modulus Ksat of the saturated rock and the bulk modulus Kfl of the saturating fluid. In sandstones, during substitution experiments, the liquids used must not disturb the clay minerals (and weathered feldspars). Apart from the case of perfectly clean sandstones, it is therefore highly preferable to preserve an irreducible saturation of brine (Swi) and hence to work with two-phase saturation (brine/hydrocarbons). In limestones, which usually contain no clay, fluid substitution experiments are facilitated by the possibility of single-phase flushing by liquids with highly varied bulk modulus. The advantage procured by this experimental expedient is unfortunately diminished by the difficulty of signal processing caused by the "path dispersion" mechanism corresponding to the scattering on heterogeneities of nonnegligible size compared with wavelength. These heterogeneities (obviously associated with the complex diagenesis of limestones) are omnipresent but not always detectable by a conventional petrographic study. The use of phase velocities in processing transmitted signals is the safest means to help solve this difficulty. In the case of rocks of simple mineralogical composition (limestone, clean sandstone), the knowledge of the bulk modulus of the solid matrix Kgrain offers an excellent means to check the results, thereby substantially facilitating interpretation.

How many relative permeability measurements do you need? A case study from a North African reservoir

Abstract: While there are published methods for estimating the appropriate number of samples for estimating the mean permeability within a workable tolerance, there exist no formal guidelines for the selection of the number of relative permeability samples. In this paper, we examine this issue for a clastic reservoir in North Africa. Rock properties (essentially the porosity and permeability relationships) are adequately characterized by a number of rock types in the glacio-marine reservoir. For this reservoir, seven have been found appropriate, using either Hydraulic Unit or Winland criteria. In a sector simulation model, the impact of the different relative permeability curves is examined. The simulation models showed less than 5% variation in total oil production for all the relative permeability scenarios investigated. This shows that, for this field, the selection of relative permeability curves from the more important rock types, defined as those making up the dominant transmissive and storage units in the reservoir, can be sufficient. The timing of the modeling study may also be important. If a screening or scoping study is required, this could be reduced to just two sets of curves. The approach to studying the number of relative permeability curves required, based on geological analysis, rock typing, heterogeneity analysis, and flow simulation is considered to be a framework for the selection of the appropriate material for special core analysis.

Estimation of oil and gas column heights in prospects using probabilistic basin modelling methods

Abstract: Source rock and reservoir rock properties are often poorly constrained in the exploration for oil and gas. Geological analogues may be used to create source rock and reservoir rock models in areas with only sparse well data coverage. Exploration risks are often influenced by uncertainties in the rock facies models. This paper outlines a methodology for assessing the consequences of using two or more source and reservoir models on hydrocarbon phase distributions in prospects. Each source rock and reservoir rock scenario is represented by computerized maps (grids) of thickness, porosities and other properties. The uncertainties of each scenario are described using probabilistic properties. The reservoir thickness may be represented by a uniform distribution with the mean described using a map (grid) with a standard deviation of, for example, 50 m. A Monte Carlo simulation is carried out for this part of the petroleum system and the resulting probabilities of oil and gas in prospects are compiled by weighting each run to calibration wells. The results can be plotted as a map of most likely oil and gas column heights. An uncertainty map is also plotted. The results can be used to rank drilling locations with respect to large oil columns and low uncertainties. The oil and gas column probabilities can be estimated for each well location. As (more) wells are drilled within a petroleum system the best match simulations can be used to further refine predictions as well as to create an updated map of the petroleum system.

Z-99 Secondary migration in a 2D visual laboratory model

Abstract: Reservoirs and cap-rocks undergo burial dwing geological time. Hydrocarbons migrate into and fill traps during periods of active expulsion from source rocks. The supply of oil and gas can be abundant until deep burial stops the supply. Capillary leakage of oil and gas from the trap can then potentially decrease the size of the accumulation. A laboratory study of filling into and leakage out of a trap has been undertaken with a visual 2D laboratory model. The model defined a synthetic cap rock having a finite entry pressure overlying a permeable reservoir rock. The trap was formed by imbedding a pyramid-shaped layer of smaller glass beads in a pack of larger glass beads.