Noel Tyler

Stratal slicing, Part I: Realistic 3-D seismic model

Two-dimensional, fenced 2-D, and 3-D isosurface displays of some realistic 3-D seismic models built in the lower Miocene Powderhorn Field, Calhoun County, Texas, demonstrate that a seismic event does not necessarily follow an impedance boundary defined by a geological time surface. Instead, the position of a filtered impedance boundary relative to the geological time surface may vary with seismic frequency because of inadequate resolution of seismic data and to the en echelon or ramp arrangement of impedance anomalies of sandstone. Except for some relatively time-parallel seismic events, the correlation error of event picking is large enough to distort or even miss the majority of the target zone on stratal slices. In some cases, reflections from sandstone bodies in different depositional units interfere to form a single event and, in one instance, an event tying as many as six depositional units (interbedded sandy and shaly layers) over 50 m was observed. Frequency independence is a necessary condition for selecting time-parallel reference events. Instead of event picking, phantom mapping between such reference events is a better technique for picking stratal slices, making it possible to map detailed depositional facies within reservoir sequences routinely and reliably from 3-D seismic data.

Depositional setting of the Salt Wash Member of the Morrison Formation, Southwest Colorado

ABSTRACT The Jurassic Salt Wash Member of the Morrison Formation, southwestern United States, is host to extensive uranium and vanadium mineralization. The ores occur in sandstones deposited in a complex fluvial system. The depositional geometry of the member is that of a wedge-fan. Detailed facies analysis of an area of the mid-paleoslope part of the member (the Slick Rock Uranium District) documents three major sandstone facies interbedded within a sequence of mudstones, siltstones, and thin sandstones. A large-scale trough cross-bedded facies, characterized by broad and generally thin trough crossbeds which rest locally on giant crossbeds as much as 6 m thick and 50 m wide, is the dominant sandstone facies. Paleocurrent azimuths are unimodal and have low consistency ratios indicating little variation in paleocurrent direction. This facies represents deposition in northeast-flowing, low-sinuosity trunk streams. The low-sinuosity streams were confined between leveed banks and probably had low-braiding indexes. Course change was primarily accomplished by avulsion. The second most abundant sandstone facies is primarily characterized by medium- to small-scale trough crossbedded sandstone within lensoid, fining-upward cycles. A progressive vertical decrease in the scale of structures and ariable paleocurrent orientations are characteristic of these depositional units. This facies represents the point bars of meandering streams that, according to paleocurrent and net sand map evidence, acted as tributaries to the low-sinuosity trunk channels. The third sandstone facies, interpreted as crevasse-splay deposits, contains coarsening-upward sandstone packages with variable structures and a distinctive convex geometry. The mudstone, siltstone, and thin sandstone facies averages 50 percent of the member and is subdivided into four subfacies. Oxidized red mudstone with numerous thin, laterally persistent, sandstone and siltstone interbeds represents well-drained floodplain deposits. Less abundant are depositional units composed of calcareous, oxidized silty mudstone with minor sandstone. These units represent sedimentation in shallow ephemeral lakes. Deeper water carbonaceous, gray-green mudstones deposited under anoxic conditions and clay plugs, representing abandoned channel fills, are rare in the district. Detailed analysis of sedimentary facies, sandstone distribution, and regional facies relationships leads to the conclusion that the Salt Wash Member in the Slick Rock District is the product of sedimentation on a fan apron marginal to an alluvial fan or coalesced fan complex. Sandstone thicks that transect the district represent depositional axes of this fluvial system.

Facies Mapping from Three-Dimensional Seismic Data: Potential and Guidelines from a Tertiary Sandstone-Shale Sequence Model, Powderhorn Field, Calhoun County, Texas

We generated a set of three-dimensional (3-D) seismic models of a lower Miocene progradational microtidal shore-zone system at the Powderhorn field, Calhoun County, Texas. These models were based on detailed lithological mapping of 250 m of stratigraphic section over an area of 13 × 9 km. The mapping was guided by detailed facies analysis based on wireline logs from 115 wells. Fourteen sandy depositional units averaging 3-30 m in thickness are encased in 15 shale units. Density-neutron and spontaneous potential (SP) logs in five recently drilled wells were used to calculate effective porosity and shaliness, which correlate well with P-wave velocity and bulk density logs. Those properties were then extended to older wells lacking acoustic, density, and other porosity ogs through regression with SP and resistivity logs to build 3-D properties models, including models of transit time and impedance. The impedance model was mapped from x, y, z to x, y, t, where t is two-way vertical time. The impedance model was converted to primary reflection coefficient series that were then convolved with zero-phase wavelets of different frequencies to produce the seismic models. The results show how the depositional facies at reservoir scale might be illustrated by 3-D seismic data, and how the seismic resolution of depositional facies changes with seismic frequency, stratigraphic position, and facies patterns. The Powderhorn reservoir sequence is interpreted as a barrier bar/lagoon depositional system associated with coastal stream plains, bayhead deltas, and small wave-dominated deltas corresponding to frequent relative changes of sea level. To detect these types of deposits, the seismic frequency should be selected such that the seismic data are tuned to the maximum thickness to establish a linear relationship between seismic amplitude and facies, and to achieve the best signal-to-noise ratio. The facies associated with the environments where main sandstones are surrounded by muddy deposits, such as coastal stream plain, bayhead delta, delta plain, and backbarrier/lagoon transition, are well illustrated in our seismic model. Lack of muddy deposits, for example in a wave-dominated delta, c uld result in obscure facies boundaries and therefore unclear lithofacies patterns. In this study, poorly compacted clean sandstone and pure shale have similar impedances, and consequently produce similar seismic responses. The resulting ambiguity may be reduced by careful analysis of facies relationships if some well data are available, and probably by the amplitude vs. offset (AVO) method. The stratal resolution of seismic imagery depends not only on wavelet frequency, but also on the stratigraphic position of a given reservoir, or the magnitude of geological interference.

Depositional Controls on Reservoir Properties in a Braid-Delta Sandstone, Tirrawarra Oil Field, South Australia

The Tirrawarra Sandstone contains 146 million bbl of oil in Tirrawarra field in the Cooper basin of South Australia. We used core, well logs, and petrophysical data to construct a depositional-facies-based flow-unit model of the reservoir, which describes rock properties and hydrocarbon saturations in three dimensions. Using the model to calculate volumes and residency of original and remaining oil in place, we identified an additional 36 million bbl of oil in place and improved understanding of past production patterns. The Tirrawarra Sandstone reservoir was deposited in a Carboniferous-Permian proglacial intracratonic setting and is composed of lacustrine and fluvial facies assemblages. The stratigraphic framework of these nonmarine facies is defined by distinctive stacking patterns and erosional unconformities. Mudstone dominated zones that are analogous to marine maximum flooding surfaces bound the reservoir. At its base a progradational lacustrine-delta system, composed of lenticular mud-clast-rich sandstones enclosed in mudstone, is truncated by an unconformity. Sandstones in these lower deltaic facies lost most of their porosity by mechanical compaction of ductile grains. Above the unconformity a braid-delta system, dominated by aggradational bed-load channel-fill sandstones, forms the core of he reservoir. Sediment reworking by channel migration and locally by shore-zone processes created quartz-rich, multilateral sandstones, which retained the highest porosity and permeability of all the reservoir facies and contained most of the original oil in place. The braid delta is erosionally truncated and overlain by a more proximal braid-plain system. Braided-channel sandstones, however, are overlain by lenticular meandering-channel sandstones, which in turn grade upward into widespread mudstones and coals. Thus, this uppermost part of the reservoir displays a retrogradational stacking pattern and upward-decreasing reservoir quality. On the basis of the systematic arrangement of facies within this stratigraphic framework, as well as facies-related differences in composition and texture, we identified reservoir flow units that have characteristic petrophysical properties. Our results demonstrate that depositional variables are the primary controls on reservoir quality and productivity in the Tirrawarra Sandstone.

Stratigraphic and structural controls on gold mineralization in the Pilgrim's Rest goldfield, eastern Transvaal, South Africa

Abstract Since 1872, approximately 185 metric tons of gold and a significant amount of silver have been won from numerous stratiform ore bodies within the Pilgrims Rest goldfield. The epigenetic stratiform ore bodies are found primarily in the Malmani Dolomite Subgroup, a laterally extensive Lower Proterozoic carbonate platform succession. A strong relationship exists between the presence of stratiform ore bodies and environment of deposition and structural deformation. Analysis of the host sediments indicates deposition in a retrogradational, followed by an aggradational, sequence that comprises supratidal (sabkha) siliciclastic sediments to midshelf carbonates. The retrogradational and aggradational sequences are characterized by numerous higher frequency transgressive and regressive cycles. Mineralization is, with few exceptions, restricted to shallow-water siliciclastic sediments; deeper water carbonates are barren. More importantly, siliciclastic mudstones and sandstones have acted as zones of detachment for thin-skinned thrust-fault deformation, resulting in the development of conformable passageways in which fluids concentrated their auriferous lodes. Evidence of shallow hinterland-dipping duplex, antiformal stack, and imbricate thrust systems abounds in several underground and field exposures. The gold-silver emplacement model for the Pilgrims Rest goldfield infers fluids derived from a deep-seated magmatic source. Oxygen-isotopic compositions of the mineralizing fluids, recalculated from δ18O quartz (+ 12.1‰ to + 19.5‰), point to a magmatic source and subsequent mixing with saline, evolved formation water. A magmatic origin is also supported by the high homogenization temperature gradient displayed by the fluid inclusions (100°C/km). The Bushveld Igneous Complex (Rustenburg Layered Suite) to the west of Pilgrims Rest is thought to be the source of the auriferous hydrothermal solutions, and its emplacement was the driving mechanism of thrust-fault deformation in the Pilgrims Rest goldfield.

Facies Architecture and Production Characteristics of Strand-Plain Reservoirs in North Markham-North Bay City Field, Frio Formation, Texas

The North Markham-North Bay City field, Matagorda County, Texas, produces oil and gas from multiple barrier and strand-plain sandstones of Oligocene age stacked over a rollover anticline in the Frio fault zone. Three principal oil reservoirs--the Cayce, Cornelius, and Carlson--account for 83% of the 49 million bbl produced from the field. All three were deposited in strand-plain systems and display considerable heterogeneity. The Cayce reservoir is composed of beach-ridge plain, distributary, and deltaic facies. Reservoir heterogeneity results in anisotropic fluid behavior. Water influx in the beach-plain deposits follows broad fronts, whereas water invasion in channel deposits is more restricted and erratic. The Cornelius reservoir was deposited in a system intermediate etween sand-rich beach plains and mud-rich chenier plains. Sandy beach ridges, separated by muddy swales, compose the productive framework of this class of strand-plain reservoir and act as conduits for early water influx. Sandstones, possibly of washover origin, in the intervening swales produce oil but are more rapidly drained than are beach-ridge sandstones. The Carlson reservoir produces from transgressed strand-plain deposits. The Carlson had a complex and episodic depositional history, yet water-influx and oil-production maps suggest isotropic fluid behavior. Modern sand-rich transgressive shore-zone deposits are characteristically sheetlike, as is the transgressive component of the Carlson reservoir. This distinctive morphology appears to have fostered reservoir productivity. Oil recovery follows predictable trends. Recovery efficiency is highest from the transgressive sheet sands of the Carlson, intermediate from the composite Cayce, and lowest from the depositionally complex and mud-rich Cornelius. Reservoir efficiency of strand-plain sandstones exceeds that of barrier and back-barrier deposits productive elsewhere in the Frio Formation of the central Texas Gulf Coast.

Reactivation of mature oil fields through advanced reservoir characterization: A case history of the Budare field, Venezuela

Budare field has produced 95 million bbl of oil since discovery in 1954, but a sustained 6 yr decline during the early 1990s reduced daily production to 3000 bbl of oil. Reactivation of the field as a result of this reservoir characterization study increased production by 13,000-16,000 BOPD, a rate that has been maintained in the 4 yr since the study was completed, resulting in an incremental recovery of more than 24 million bbl of oil. This increase in production was achieved through integrated reservoir characterization that identified the depositional heterogeneities and structural complexities responsible for intrareservoir entrapment of the bypassed oil in the field. The main producing zones are the Tertiary-age Merecure and Oficina reservoirs that are interpreted as the deposits of large-scale bed-load and mixed-load fluvial and wave-dominated deltaic depositional systems. The geologic analysis indicates that the large-scale systems are divided internally, or vertically stratified, by thin but widespread shale markers resulting from flooding episodes and that facies variability introduces lateral discontinuities. Syn- and postdepositional faulting further disrupts reservoir continuity. Trends in fluid flow established from engineering analysis of initial fluid levels, response to recompletion workovers, and pressure depletion data demonstrated that these geologic heterogeneities (flooding shale markers, lateral facies pinch-out, and faults) are effective barriers to lateral and vertical fluid flow. Considerable potential for sustained production exists at Budare field because the reservoir units are highly compartmentalized. Identification and targeting of the poorly drained and uncontacted compartments at Budare facilitated the development of a production optimization portfolio that encompassed four principal advanced-recovery opportunities: field extension or step-out; attic areas of the reservoir that are structurally higher than existing production and, hence, poorly drained; stratigraphically and structurally defined compartments that have not been tapped; and compartments that are poorly drained. Successful geologically targeted infill wells and strategic recompletions in these bypassed compartments achieved a sustained fivefold increase in daily production in the mature Budare field.

Styles of heterogeneity in dolomitized platform carbonate reservoirs: Examples from the central basin platform of the permian basin, southwestern USA

Abstract The Permian Basin of West Texas and southeastern New Mexico, southwestern U.S.A., is the premiere oil basin of the United States. At discovery, reservoiors in this prolific province contained more than 100 billion barrels of oil, almost a quarter of all the discovered in the U.S. Almost half of this resource (43%) was contained in a single reservoir type, dolomitized platform carbonate. Dolomitized platform carbonates were deposited on shallow shelves fringing the basin and on a horst block, the Central Basin Platform, that divides the basin and separates sites of deep-water siliciclastic sedimentation in the adjacent subbasins. The Central Basin Platform hosts many large combined structural/stratigraphic trap reservoirs in dolomitized platform carbonates. These range in size up to four billion barrels of original oil in place. Integrated geoscience and engineering characterization of four of these fields; Dune, Emma, Penwell, and Taylor-Link, allows comparison of the styles and scales of heterogeneities that influence recovery in this reservoir type. Facies composition and architecture exert fundamental controls on paths of fluid movement during production. Principal facies are extensive, deep subtidal fusulinid wackestones that shoal upward into shallow-subtidal and intertidal packstones and grainstones in which the dominant productive facies are grainstone bars and shoals, and shorezone systems that are dissected by dip-oriented tidal systems. Rapid lateral facies changes together with highly cyclic shoaling sequences result in pronounced permeability variations both laterally and vertically in the section. Superimposed on the depositional framework is a multi-event diagenetic overprint. These carbonate reservoirs are thoroughly dolomitized and partly cemented by sulfates. A post-burial leaching event increased permeability in some parts of these rocks. Karst processes have a large affect on reservoir quality in the southern part of the Central Basin Platform. Even though these carbonate reservoirs have undergone substantial diagenetic modification depositional facies still exert the primary control on remaining, and in particular, mobile, oil saturation.

Reservoir Architecture--A Critical Element in Extended Conventional Recovery of Mobile Oil in Heterogeneous Reservoirs: ABSTRACT

Sedimentological research during the last 20 years has defined models that support exploration and therefore focus on external geometry of reservoirs. These models understate the importance of the internal reservoir framework and are inadequate to explain internal reservoir seals and resultant compartmentalization as it controls hydrocarbon recovery. Development of models describing internal reservoir architecture, that is, facies composition, extents, three-dimensional geometries, orientations, and relations with surrounding facies, is critical for guiding well placement and completion interval to maximize hydrocarbon recovery from heterogeneous reservoirs. Reservoir architecture, a product of sedimentation style, governs mobile oil recovery efficiency. Wave-reworked depositional systems with simple architectures have high mobile oil recovery efficiencies. In contrast, strongly channelized systems with complex architectures, including fluvial, fluvial-dominated deltaic, and submarine fan reservoirs, have low to moderate mobile oil recovery. Carbonate reservoirs display a smaller range of mobile oil recovery efficiencies; however, large volumes of unrecovered mobile oil remain in highly stratified, laterally discontinuous platform carbonates in the Permian basin. In Texas reservoirs with complex architectures, 35 billion bbl of mobile oil will remain unrecovered at abandonment; nationally, this important and moderate-cost resource may be 80 to 100 billion bbl.

Oil Recovery in a Low-Permeability, Wave-Dominated, Cretaceous, Deltaic Reservoir, Big Wells (San Miguel) Field, South Texas

The Upper Cretaceous Big Wells (San Miguel) reservoir in Dimmit and Zavala Counties, south Texas, produces from a broadly lenticular, wave-dominated deltaic sandstone encased in prodelta and shelf mudstones. An updip porosity pinch-out coincides with a gentle undulation on a uniformly gulfward-dipping monocline and forms a structurally modified stratigraphic trap. The reservoir is relatively tight and has an average porosity of 21% and average permeability of 6 md; wells require fracturing to stimulate production. Ultimate recovery, based on current production trends and technology, is projected to be 57 million bbl, or 29% of the 198 million bbl field. The reservoir is subdivided into an upper, nonproductive, transgressive shelf sandstone and a lower, productive, but intensely bioturbated, deltaic sandstone. The tight, nonproductive upper sandstone seals the reservoir, which consists of four major internal facies. A dip-oriented distributary system carried sediment into the basin. Sediment was then transported along strike (dominantly to the southwest) by longshore drift. Wave action reworked the sands into a beach-ridge plain. The resultant distributary and beach-ridge plain complex exhibits an asymmetric cuspate geometry elongated to the southwest. Landward of the delta system lay a muddy coastal plain. Prodelta and lower shoreface silts and shelf muds were deposited seaward of the deltaic and shore-zone system. The northward transition from thicker and cleaner sandstones of the beach-ridge plain to argillaceous sandstones within and adjacent to the distributary system strongly affects oil recovery from the field. Reservoir permeability and induced-fracture half-lengths (the distance from the well bore to the fracture terminus or half the total length of induced fracture, calculated from pressure transient analysis) decrease dramatically to the north. Consequently, well performance peaks in the beach-plain sediments and decreases northward and updip and downdip into adjacent muddier sediments. Recovery efficiencies of the original oil in place average 50% in the southern half of the pool and drop to 20-30% in the north. However, recovery of movable (nonresidual) oil is highly efficient. About 88% of the nonresidual oil in the pool will be produced. Wave-dominated deltaic reservoirs are characterized by minimal well-to-well variability, excellent internal continuity, and, consequently, maximum efficiency of mobile-oil recovery.