Low-relief Structures Research Articles

Unusual reservoir connectivity revealed by data integration at the Sunrise field

The Sunrise gas-condensate field located in the Timor Sea is part of a planned liquefied natural gas (LNG) development. It is a broad, low-relief structure covering approximately 900 km2 with two main reservoirs in the Plover Formation. While previous studies suggested that the Sunrise field was likely well connected, there still existed a downside risk of compartmentalisation because of the high degree of faulting. New results from a multi-disciplinary investigation indicate that the Sunrise field is unusually well connected, both vertically and laterally across large distances of possibly up to 40 km. This is primarily because of the nature of the main reservoir, which is thought to be a laterally extensive shoreface facies, and the presence of conductive fault/fracture zones associated with fault reactivation in an active tectonic setting. The results of this study render unlikely the downside case of a highly compartmentalised field. Despite the relatively wide appraisal well spacing, there is confidence in these conclusions because of the consistent message obtained from the evaluation of a wide range of data. The combination of geochemistry and the modelling of convective mixing through geological time—a method rarely used in the past—give important insights not typically available from traditional methods. This work was also used to successfully guide further data collection, which has supported the initial conclusions regarding the degree of communication across the field.

Replacing Wireline Formation Pressure With Formation Pressure While Drilling in Long Horizontal Wells

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 12103, "Replacing Wireline Formation Pressure With Formation Pressure While Drilling in Long Horizontal Wells," by J.K. Larsen, SPE, Maersk Oil Qatar; C.J. Maeso, SPE, and F. Liu, SPE, Schlumberger; and R. Narayanan and R. Noman, SPE, Qatar Petroleum, prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed. A case history presents how formation-pressure-while-drilling (FPWD) technology effectively has replaced traditional pipe-conveyed wireline technology in long horizontal wells. The Al Shaheen field, offshore Qatar, in the Middle East, is developed with 20,000- to 30,000 ft-long horizontal wells, drilled in radial and line-drive patterns in one sandstone and two carbonate reservoirs. Eleven FPWD jobs were performed within the first year, and FPWD now is the preferred option for formation-pressure acquisition in Al Shaheen. Introduction Knowledge of the reservoir pressure is essential for understanding the behavior of the reservoir fluids. Fluid gradients are used to establish fluid contacts in the reservoir, and pressure data obtained during the production phase reveal important information about drive mechanisms and the geology. Traditionally, wireline formation testers have been used to obtain formation pressures. FPWD tools have advantages and disadvantages compared to wireline formation testers, depending on the type of well and the objectives of the logging program. Understanding these advantages and disadvantages and the objectives of the logging program is required, and is best achieved through a joint effort by the operator and the service company. The full-length paper details the transition of, and the considerations associated with, introducing FPWD in the Al Shaheen field. Al Shaheen Field The Al Shaheen field is a low-relief structure with an areal extent of approximately 40×60 km and is developed in three main reservoirs: Nahr Umr, Shuaiba, and Kharaib (known as Thamama B elsewhere in the region). The Nahr Umr formation is a thin sandstone reservoir normally less than 15 ft thick, with a target zone less than 3 ft thick. The high-permeability target zone often is unconsolidated. The Shuaiba formation is a highly heterogeneous carbonate reservoir with large permeability contrasts associated with facies changes. The Kharaib formation is a tight carbonate reservoir with uniform reservoir properties across the field. The Kharaib permeability ranges from 1 to 10 md. The 20,000- to 30,000 ft-long horizontal wells are drilled with geosteering to control the position of the wells in the reservoir. Optimal well spacing ranges from 600 ft in the tight Kharaib formation to 2,000 ft in the high-permeability Nahr Umr sandstone. Fig. 1 shows the well placement in the three reservoirs in the northeastern part of the Al Shaheen field. Water injection is used extensively for pressure maintenance in all three reservoirs.

World's First Gravel-Packed Inflow-Control Completion

Summary The Etame oil field, offshore Gabon, West Africa, has been producing since September 2002. The Etame oil reservoir is an oval-shaped, low-relief structure with a moderate aquifer drive. To maximize ultimate field recovery, the ET-6H well was drilled with a horizontal lateral positioned to traverse the reservoir near the structural crest and to be within the Upper Gamba sandstone throughout its length. The Gamba sandstone averages 45 ft in thickness and overlies a significant angular unconformity. The subcropping Dentale-aged sandstones and interbedded shales below this unconformity have dips to 12°. The oil column of approximately 170 ft extends below this unconformity. Previous wells in the field were completed using openhole horizontal gravel packs (OHGPs) and have experienced excellent sand-control performance. However, OHGPs offer no protection against early water breakthrough. The Gamba sand averages 30% porosity with a permeability range of 1 to 3 darcies. The Dentale sands are much more variable, with porosities of 18 to 30% and a permeability range of 50 to 1,000 md. Thus, if a portion of the lateral is situated immediately above a high-permeability Dentale sand, the well will be at risk of early water breakthrough and subsequent reduced recovery if it is completed with a standard OHGP. The operator gravel packed the ET-6H well and used a system that provides a near-uniform inflow profile along the entire lateral length to protect against early water breakthrough. The gravel packing of inflow-control devices (ICDs) presented some unique challenges because of their differences from standard sandcontrol screens. This paper describes the implementation of the world's first gravel packed inflow-control completion, including: ICD selection process, gravel-pack design, data from the gravel-pack operation, and resulting well performance.

Pool characterization of Ordovician Midale field: Implication for Red River play in northern Williston basin, southeastern Saskatchewan, Canada

The Upper Ordovician Midale field is located in the northern Williston basin in southeast Saskatchewan, Canada. Hydrocarbons are hosted mainly in the dolomite reservoirs with burrowed textures in the upper Yeoman Formation. These reservoirs are characterized by intercrystalline porosity in the dolomitized matrix, with variable amounts of vugs and fractures, and can be divided into four zones. Reservoir zones 1 and 2, typically 6–10 m (20–33 ft) thick in total, are situated in the upper part of the traps and commonly bear oil. Although the underlying zones 3 and 4 are thicker, they commonly contain only water because they are located below the spillpoint of the hydrocarbon traps.The seismic reflection of the Red River reservoirs in the Midale field is characterized by a weak- to medium-amplitude trough immediately above the positive reflection of the Winnipeg shale. Where all four zones are present, an additional peak occurs on the seismic profile above the original reservoir reflection. This additional peak, however, disappears where reservoir zones 3 and 4 pinch out. Where there is an increase in the thickness of reservoir zones 1 and 2 or amalgamation of zone 1 with zone 2, the Red River reservoirs are characterized by high-amplitude and high-frequency reflections on seismic profiles.The Ordovician oil pools in the Midale area are associated with low-relief anticline structures. These low-relief structures are interpreted as the compactional drape of Red River strata over local Precambrian basement highs. The source of hydrocarbons in the Red River reservoirs is Ordovician kukersites. A wide range of API fractions for the oils from the Midale pools suggests a mixing of low-maturity oils, sourced from local kukersite beds, and high-maturity oils that migrated over a long distance from the south. The hydrocarbon production from Red River Midale pools is characterized by the fast rise of water cut and high water output, which can be attributed to the small pool size and the fracture systems connecting oil and water zones.

The Camelot Fields, Blocks 53/1a, 53/2, UK North Sea

Abstract The group of gas accumulations known as the Camelot Fields straddle Blocks 53/1a and 53/2 of the UK Sector of the Southern North Sea on the southern margin of the Sole Pit Trough. The Camelot North Field was discovered in 1967 and development commenced from the Camelot A platform in 1989 (wells Al to A5). The Camelot Northeast Field came on-stream from the B platform (53/2-7 well) in 1992. The Cador accumulation, in the north of Block 53/1a, was subsequently developed through the A6 horizontal well in 1993. The current estimate of gas initially in place (GIIP) for the field is 280 billion cubic feet. Ultimate recovery factors are expected to be as much as 90% and since more than 80% of the GIIP has already been recovered, the Camelot Fields have proven to be prolific producers. This paper focuses on field history after 1988 and, in particular, on the recent exploratory drilling on the southern field margin beneath the South Leman Graben. In this area depth conversion is a major challenge with large velocity contrasts, low relief structures and thin hydrocarbon columns. Recent well results, following mapping of the new 3D seismic data set, indicate that fault reactivation occurred in late Cretaceous to early Tertiary times. Fault movements associated with this event resulted in trap readjustments and/or gas leakage and have exerted an important additional control on hydrocarbon spill points.

Along-Axis Segmentation and Growth History of the Rome Trough in the Central Appalachian Basin1

The Rome trough, a northeast-trending graben, is that part of the Cambrian interior rift system that extends into the central Appalachian foreland basin in eastern North America. On the basis of changes in graben polarity and rock thickness shown from exploration and production wells, seismic lines, and gravity and magnetic intensity maps, we divide the trough into the eastern Kentucky, southern West Virginia, and northern West Virginia segments. In eastern Kentucky, the master synthetic fault zone consists of several major faults on the northwestern side of the trough where the most significant thickness and facies changes occur. In southern West Virginia, however, a single master synthetic fault, called the East-Margin fault, is located on the southeastern side of the trough. Syndepositional motion along that fault controlled the concentrated deposition of both the rift and postrift sequences. The East-Margin fault continues northward into the northern West Virginia segment, apparently with less stratigraphic effect on postrift sequences, and a second major normal fault, the Interior fault, developed in the northern West Virginia segment. These three rift segments are separated by two basement structures interpreted as two accommodation zones extending approximately along the 38th parallel and Burning-Mann lineaments. Computer-aided interpretation of seismic data and subsurface geologic mapping indicate that the Rome trough experienced several major phases of deformation throughout the Paleozoic. From the Early(?)-Middle Cambrian (pre-Copper Ridge deposition), rapid extension and rifting occurred in association with the opening of the Iapetus-Theic Ocean at the continental margin. The Late Cambrian-Middle Ordovician phase (Copper Ridge to Black River deposition) was dominated by slow differential subsidence, forming a successor sag basin that may have been caused by postrift thermal contraction on the passive continental margin. Faults of the Rome trough were less active from the Late Ordovician-Pennsylvanian (post-Trenton deposition), but low-relief inversion structures began to form as the Appalachian foreland started to develop. These three major phases of deformation are speculated to be responsible for the vertical stacking of different structural styles and depositional sequences that may have affected potential reservoir facies, trapping geometry, and hydrocarbon accumulation.

Delineation of Essential Habitat for Juvenile Red Snapper in the Northwestern Gulf of Mexico

Seasonal habitat suitability index models were developed for juvenile red snapper Lutjanus campechanus in the western Gulf of Mexico. Habitat factors considered in the analysis included water temperature, salinity, and dissolved oxygen at the bottom; depth and density of offshore petroleum platforms; and low-relief bottom structures. High-value habitat for juvenile red snapper is characterized by depths between 18 and 64 m, water temperatures of 24–26°C, salinities around 35%, and dissolved oxygen levels of at least 5 mg/L. Density of low-relief structures was not a significant habitat element, and an inverse association was found between juvenile red snapper abundance and the density of offshore platforms. Results of the model analysis suggest that the step-like expansion of the hypoxic area (dissolved oxygen ≤ 2 mg/L) offshore of the mouth of the Mississippi River and west to the Louisiana–Texas border, which first occurred in 1993, has reduced habitat carrying capacity for juvenile red snapper in this region by up to 25%, averaging 19%. This environmental change may limit the level to which overfished Gulf red snapper stocks can be rebuilt to historical levels.

The application of reflection tomography and interval velocity analysis to achieve accurate depth conversion of subtle structures: a case study

Reflection tomography and interval velocity analysis (IVA) is applied to a 2D seismic line in the Surat Basin - an area where the primary goal is achieving reliable depth conversion of low relief structures, in the presence of near surface velocity anomalies and subtle lateral velocity gradients.The technique, using commercially available velocity analysis and Pre-Stack-Depth-Migration (PSDM) software, represents a potential solution to problems which have challenged previous workers. We demonstrate reflection tomography can resolve shallow velocity anomalies by using as input the moveout errors of deeper horizons from an initial pass of PSDM. Significantly, reflection energy from the near-surface layer is not required to resolve its velocity. When the shallow velocity model is determined, the interval velocity analysis of subsequent layers becomes stable and a more refined velocity model may be constructed. Several iterations of PSDM and reflection tomography are generally required before running a final pass of PSDM. The example seismic line contains three wells which are used to judge the quality of the final depth migration.The results demonstrate that it is possible to extract accurate lateral velocity information inherent in high fold CMP gathers from land data containing shallow velocity anomalies or residual static errors. A lateral velocity gradient causing an apparent pull up of 26 metres between Wells B and C is successfully resolved. The example demonstrates the predicted formation tops of Well C would have been accurate to around +/- 5m if reflection tomography and interval velocity analysis had been applied in place of a regional velocity function derived from nearby well data.

Abstract: Geologic and Computer Modeling of Upper Jurassic Smackover Reef and Carbonate Shoal Lithofacies, Eastern Gulf Coastal Plain

ABSTRACT Reefs and carbonate shoals have long been known from the Upper Jurassic Smackover Formation in the Gulf Coastal Plain; however, these carbonate lithofacies have unique acoustic properties that make them difficult to define using 3-D seismic reflection technology. In the eastern Gulf Coastal Plain, microbial reef and shoal buildups occur on pre-Jurassic paleotopographic basement features on a carbonate ramp margin. Development of these buildups is a result of the interplay among paleotopography, sea-level changes, and carbonate productivity. Geological and computer modeling indicates that Smackover reef and shoal development is restricted to the flanks of high (emergent) relief structures, while reef and shoal development occurred on the crest and flanks of low-relief structures (submergent). For these submergent features, modeling indicates that carbonate productivity during reef growth was significantly greater than during shoal development. In addition to the initial paleorelief, the rate of sea-level rise, the level of carbonate productivity, and duration of reef growth appear to be critical factors in determining thickness and distribution of the reef lithofacies. Subsidence and compaction are minor factors. Shoal development is greatly influenced by reef distribution, sea-level changes, level of carbonate productivity, and duration of shoal deposition. Subsidence, compaction and sediment redistribution are also factors. Modeling of parameters affecting reef and shoal development associated with pre-Jurassic paleohighs in combination with 3-D seismic reflection studies increases the chances of drilling a successful exploration well.

Migration velocity analysis: Accounting for the effects of lateral velocity variations

The most common migration velocity analysis algorithms, iterative profile migration, focusing analysis, and stack power analysis are based on restrictive subsurface assumptions that may cause the methods to break down in the presence of lateral velocity variations. Typically, the subsurface is assumed to have either a constant velocity, or at most, a depth variable velocity. Recent innovations include the use of traveltime inversion philosophy to invert migration measurements of the curvature as a function of offset exhibited by an event following migration. Traveltime inversion makes few assumptions regarding the subsurface, but is a rather unstable process. Thus, an important question is, “Under what conditions do the traditional methods break down and make the use of traveltime inversion methods mandatory?” Marrying the common migration analysis with tomography results in a set of equations that, while useful for generating updates from migration measurements, are too complex for answering the above question. However, by restricting the subsurface to low relief structures and assuming small angle wave propagation, these updating equations can be approximated by forms that are identical to the traditional updating equations, except for a factor that is dependent upon the magnitude, position, and spatial wavelength of potential lateral velocity variations. These simpler equations indicate that even relatively long wavelength anomalies can cause updates to point in the wrong direction and iterative procedures to diverge, and under certain conditions, cause the accuracy of these updates to decrease dramatically.

Successful Integration of 3-D Seismic and Multidisciplinary Approaches in Exploring the Zechstein 2 Carbonates in Northeast Netherlands

Nederlandse Aardolie Maatschappij has been actively involved in the exploration of the Zechstein 2 carbonate play for over 40 yr. This exploration effort, concentrated mainly in the Drenthe and Schoonebeek area of northeast Netherlands, has resulted in the discovery of 20 gas fields with cumulative reserves of more than 40 x 10[sup 9] m[sup 3] of gas. The wealth of subsurface data collected in the exploration and development of these fields has lead to the establishment of detailed depositional and diagenetic models of the Zechstein 2 carbonates. More recently, extensive three-dimensional seismic coverage, the integration of lateral prediction techniques, and detailed fracture studies in cores have provided powerful predicting tools in the comprehension and exploitation of the play. Successful integration of the various disciplines now allows exploration of subtle low-relief structures in the mature Zechstein hydrocarbon province and helps target directional exploration and development wells.

Eromanga Basin seismic stratigraphy and tectonic modelling – keys to exploration success in ATP 299P

Within the Eromanga Basin, stratigraphic variations in the Jurassic Birkhead Formation are recognizable on seismic sections as lateral character changes. Understanding these character changes and developing representative depositional and structural models results in lower risk and hence more favourable economics when exploring for Birkhead Formation oil.Authority to Prospect (ATP) 299P is located in the Eromanga Basin, on the southeastern flank of the Cooper Basin. It is 120 km northwest of the Jackson Oil Field. Over 1.5 million barrels of oil have been produced from the permit, of which 500,000 barrels have been produced from the Birkhead Formation, highlighting it as an important exploration target.By late July 1989 Cranstoun-1, a Birkhead Formation oil well, had produced more than the mapped proved and probable reserves and was still producing 203 barrels of clean oil per day. To investigate this anomaly the existing seismic data was reprocessed with additional 80 m uphole control and a seismic stratigraphic interpretation was carried out. The mapped data identified a Devonian wrench system overlain by a large low relief structure known as the Greater Cranstoun Structure (GCS). Endeavour-1 was drilled on this structure 3 km north of Cranstoun-1 and was completed as a Birkhead oil producer. Post drill analysis revealed that the interpreted top intra-Birkhead seal seismic marker crossed a geologically correlated boundary — from the top Birkhead ('A' sand) seal at the Endeavour wells switching down to the top 'B' sand seal at the Cranstoun wells. A further three wells were drilled based on the mapping of this seismic marker resulting in limited success. Detailed 2D seismic modelling, using the sonic logs from the five wells on the GCS as input, indicated that an increase in the frequency bandwidth of the seismic data was needed to resolve those geologically correlated boundaries within the Birkhead Formation which have an acoustic impedance contrast.Future seismic acquisition and processing should use good statics together with optimum recording parameters (defined from the 2D modelling results) to produce the required seismic resolution for accurate stratigraphic interpretation and mapping.Quantitative understanding of the limitations and possible resolution of seismic data is crucial to accurate seismic stratigraphy, which, combined with a valid tectonic model are keys to exploration success in the Birkhead Formation in ATP 299P and throughout the Eromanga Basin.

Paleotopographic Control on Smackover Reservoir Evolution: Southwest Alabama

A number of Smackover fields in southwest Alabama occur over pre-Mesozoic paleotopographic highs that, in addition to providing a trapping mechanism, had considerable influence on Smackover deposition, diagenesis, and reservoir development. The overall influence of paleotopography is largely a function of relief on the pre-Smackover surface. Paleorelief ranges from less than 100 ft in association with low relief structures to over 500 feet with higher relief features. Lower relief structures (Appleton field) are characterized by thinning of both the Smackover and overlying Buckner Anhydrite sections. High energy depositional facies are localized across the crest of these structures and pass into lower energy facies off structure. Porosity enhancing diagenesis is most apparent across the crests of the structures, but had little effect on the Smackover in off structure wells. An appropriate exploration strategy would be to drill the crest of the structure. High relief structures (Vocation field) are characterized by thinning and, in some cases, pinchout of the Smackover section. Generally, nonporous deeper subtidal wackestones and packstones pass into porous, high energy grainstones and algal boundstones in a halo that surrounds the paleohigh. Porosity enhancing diagenesis is apparent across the entire structure, but extensive evaporite cementation plugs most porosity in crestalmore » areas. Because the updip Smackover is tight, successful exploration involves identification of the porosity halo that rims the structure.« less

Evolution of Stocks and Massifs from Burial of Salt Sheets, Continental Slope, Northern Gulf of Mexico

Salt structures in a 4000-km{sup 2} region of the continental slope, the northeast Green Canyon area, include stocks, massifs, remnant structures, and an allochthonous sheet. Salt-withdrawal basins include typical semicircular basins and an extensive linear trough that is largely salt-free. Counterregional growth faults truncate the landward margin of salt sheets that extend 30-50 km to the Sigsbee Escarpment. The withdrawal basins, stocks, and massifs occur within a large graben between an east-northeast-trending landward zone of shelf-margin growth faults and a parallel trend of counterregional growth faults located 48-64 km basinward. The graben formed by extension and subsidence as burial of the updip portion of a thick salt sheet produced massifs and stocks by downbuilding. Differential loading segmented the updip margin of the salt sheet into stocks and massifs separated by salt-withdrawal basins. Initially, low-relief structures evolved by trap-door growth as half-graben basins buried the salt sheet. Remnant-salt structures and a turtle-structure anticline overlay a salt-weld disconformity in sediments formerly separated by a salt sheet. Age of sediments below the weld is inferred to be be late Miocene to early Pliocene (4.6-5.3 Ma); age of sediments above the weld is late Pliocene (2.8-3.5 Ma). The missing interval of time (1-2.5 Ma)more » is the duration between emplacement of the salt sheet and burial of the sheet. Sheet extrusion began in the late Miocene to early Pliocene, and sheet burial began in the late Pliocene in the area of the submarine trough to early Pleistocene in the area of the massifs.« less

Depths and interval velocities from seismic reflection data for low relief structures : Sherwood, J W C; Chen, K C; Wood, M Proc 18th Offshore Technology Conference, Houston, 5–8 May 1986V2, P103–110. Publ Richardson, Texas: OTC, 1986

Depths and interval velocities from seismic reflection data for low relief structures : Sherwood, J W C; Chen, K C; Wood, M Proc 18th Offshore Technology Conference, Houston, 5–8 May 1986V2, P103–110. Publ Richardson, Texas: OTC, 1986

Facies Control of Reservoir Quality in Grayburg Formation, Dune Field, Crane County, Texas: ABSTRACT

The lower Guadalupian Grayburg carbonates of Dune field were deposited along the edge of the Central Basin platform on the west side of the Midland basin. Dune field lies on the northeast side of a low-relief structure that dips gently into the basin. In the Mobil University Unit 15/16 of Dune field, the Grayburg reservoir section has been divided vertically into three parts based on carbonate facies recognized in whole cores. Predictable average porosities ({phi}) and geometric mean permeabilities (k) associated with these facies vary widely between four orders of magnitude. Fusulinid wackestone ({phi} = 7%, k = 0.2 md), the most widely distributed facies studied, composes the lower unit in all cores. The middle unit is represented by sponge-algal framestone ({phi} = 8%, k = 0.15 md) in the western third and crinoid packstone/grainstone ({phi} = 11%, k = 1.2 md) in the eastern two-thirds of the area studied. The upper unit contains an upward-shoaling succession from bottom to top of fusulinid wackestone, pellet grainstone ({phi} = 9%, k = 0.5 md), ooid grainstone ({phi} = 5%, k = 0.05 md), and pisolite grainstone ({phi} = 4%, k = 0.02 md). This sequence is interpreted to represent a progradationalmore » sequence from shallow-water subtidal to arid tidal-flat environments. Siltstone beds occur throughout the upper unit but are more numerous and thicker toward the top. Moldic, vuggy, interparticle, and intercrystalline porosities occur in the Grayburg dolomites. Although diagenesis of the San Andres/Grayburg carbonates (including massive dolomitization, and anhydrite and gypsum replacement and cementation) is extensive, the primary depositional fabrics still exert some control over the distribution, type, and amount of porosity and permeability. Permeability is highest (geometric mean = 0.5-1.2 md) where interparticle porosity is developed in the grainstones and packstones.« less

The application of high resolution seismic processing to low relief structures – Harriet oil accumulation*

The Harriet structure is located within the offshore permit WA-192-P on the north-west shelf of Western Australia, near Barrow Island. The structure is a low-relief feature controlled by late faulting. An oil-bearing sand of Lower Cretaceous age forms the reservoir which has excellent porosity and permeability. The reservoir has a low seismic acoustic impedance contrast with the overlying deep marine shales. This low acoustic impedance contrast, combined with penetration problems due to near surface carbonates, results in a generally weak reflector at the top of the reservoir sands at a two-way time of approximately 1.5 s. Four recent vintages of seismic surveys using different recording parameters have been shot over the structure with a resultant grid spacing of 250 m. After the Harriet No. 1 discovery well, all the data over the structure were reprocessed using ‘state-of-the-art’ processing techniques to improve the resolution of the reflecting event at the top of the reservoir sand. The reprocessing was also carried out to minimize mis-ties between the various vintages of seismic data, and to improve the match between the surface seismic data and the vertical seismic profile at the wells. The above three aims were achieved by replacing standard pre-stack predictive deconvolution by deterministic deconvolution, i.e. instrument phase compensation and spectral equalization and by statistical wavelet extraction and shaping to ‘zero phase’. Also a pre-stack FK filter was applied to suppress noise on the data. Additionally, the application of spectral equalization to the suppression of low frequency short period multiples is demonstrated.

Sealing and Nonsealing Faults in Louisiana Gulf Coast Salt Basin

Fault-controlled accumulations in the hydropressured Tertiary section were studied in 10 Louisiana Gulf Coast salt basin fields located on low-relief structures. Investigations were limited to traps associated with faults which restrict vertical migration of hydrocarbons; that is, where an accumulation is in contact with the fault. The fault-lithology-accumulation relations observed are (1) fault sealing, with hydrocarbon-bearing sandstone in lateral juxtaposition with shale; (2) fault nonsealing to lateral migration, with parts of the same sandstone body juxtaposed within the hydrocarbon column; (3) fault nonsealing to lateral migration, with sandstone bodies of different ages juxtaposed within the hydrocarbon column; and (4) fault sealing, with sandstone bodies of diffe ent ages juxtaposed within the hydrocarbon column. In some places, these four relations are present at different levels along the same fault. In the examples studied, only faults nonsealing to lateral migration were observed where parts of the same sandstone body are juxtaposed across a fault. With sandstone bodies of different ages juxtaposed, some faults are sealing and others are nonsealing to lateral migration, but sealing faults are the most common. The fault seal apparently results from the presence of boundary fault-zone material emplaced along the fault by mechanical or chemical processes related directly or indirectly to faulting.

Sealing and Nonsealing Faults in Gulf Coast Salt Basin: ABSTRACT

This study was undertaken to investigate (1) the different End_Page 529------------------------------ situations of fault entrapment of hydrocarbons in Tertiary sediments of the Gulf Coast salt basin, and (2) the role of juxtaposed sediments in a sandstone-shale sequence in creating sealing and nonsealing faults. Fault-controlled accumulations in the hydropressured Tertiary section were studied in 10 Gulf Coast fields located on low relief structures. Investigations were limited to traps associated with faults which restrict vertical migration of hydrocarbons, that is, where an accumulation is in contact with the fault. The relations observed among fault, lithology, and accumulation are (1) fault sealing, with hydrocarbon-bearing sandstone in lateral juxtaposition with shale; (2) fault nonsealing to lateral migration, with parts of the same sandstone body juxtaposed within the hydrocarbon column; (3) fault nonsealing to lateral migration, with sandstone bodies of different ages juxtaposed within the hydrocarbon column; and (4) fault sealing, with sandstone bodies of different ages juxtaposed w thin the hydrocarbon column. In some places these four relations are present at different levels along the same fault. In the examples studied, faults nonsealing to lateral migration were observed only where parts of the same sandstone body are juxtaposed across a fault. With sandstone bodies of different ages juxtaposed, some faults are sealing and others are nonsealing to lateral migration, but sealing faults are the most common. The fault seal apparently results from the presence of boundary fault-zone material emplaced along the fault by mechanical or chemical processes related directly or indirectly to faulting. End_of_Article - Last_Page 530------------

Deposition, Facies Patterns, and Hydrocarbon Potential of Bangor Limestone (Mississippian), Northern Black Warrior Basin, Alabama and Mississippi: ABSTRACT

Abstract The Bangor Limestone was deposited as a carbonate shelf, ramp and basin sequence on the northeast flank of the Warrior Basin. Progradation to the southwest was episodic and resulted in several cyclic units which grade upward from deeper water muddy facies into grainy shoal facies. Shoal facies regression eventually expanded the shelf more than 14 miles basinward. The Bangor can be divided into three members which are mappable throughout the shelf and ramp. Each member contains a shelf-blanketing, grain-support facies rich in crinoids, bryozoans and oolites. Widely scattered patches of porous reservoir-quality lime occur in this shallow water suite; however, there are no indications of broad porosity pockets which might serve as large stratigraphic traps on the shelf. Known gas accumulations on the Bangor shelf, i.e., Whitehouse and Nauvoo Fields, appear to be low-relief closures having small reserves. Future discoveries are anticipated to be analogous to these. Small potential reserves and probable inability to seismically detect the low-relief structures make the shelf an unattractive objective. The Bangor ramp may offer better hydrocarbon potential. One speculative ramp model is presented which suggests the possibility of bryozoancrinoidal mounding. Suggested mound-trap closure could reach 100 to 150 feet. If such mounds were densely spaced or areally large, hydrocarbon reserves could be attractive.