Pliocene Sands Research Articles

The evolution of groundwater in the Tyrrell catchment, south-central Murray Basin, Victoria, Australia

The Tyrell catchment lies on the western margin of the Riverine Province in the south-central Murray Basin, one of Australia’s most important groundwater resources. Groundwater from the shallow, unconfined Pliocene Sands aquifer and the underlying Renmark Group aquifer is saline (total dissolved solids up to 150,000 mg/L) and is Na-Cl-Mg type. There is no systematic change in salinity along hydraulic gradients implying that the aquifers are hydraulically connected and mixing during vertical flow is important. Stable isotopes (18O+2H) and Cl/Br ratios indicate that groundwater is entirely of meteoric origin and salts in this system have largely been derived by evapotranspiration of rainfall with only minor halite dissolution, rock weathering (mainly feldspar dissolution), and ion exchange between Na and Mg on clays. Similarity in chemistry of all groundwater in the catchment implies relative consistency in processes over time, independent of any climatic variation. Groundwater in both the Pliocene Sands and Renmark Group aquifers yield ages of up to 25 ka. The Tyrrell Catchment is arid to semi-arid and has low topography. This has resulted in relatively low recharge rates and hydraulic gradients that have resulted in long groundwater residence times.

THE EAST COAST BASIN OF NEW ZEALAND, AN EMERGING PETROLEUM PROVINCE

More than 300 oil and gas seeps are known in the onshore East Coast Basin of North Island, New Zealand. Spectacular geological structures have been explored by more than 40 wells, only three of which have been offshore. Results are tantalising, with 70% of wells yielding oil or gas shows. Westech’s two gas discoveries onshore at Kauhauroa and Tuhara in northern Hawkes Bay remain un-developed at present.Strong gas shows were encountered in both open-file wells drilled offshore and elevated gas readings were recorded in the recent Tawatawa–1 well, but reservoir quality was poor.Nevertheless, good reservoir facies are abundant in the East Coast Basin. A wide range of Miocene and Pliocene sands and limestones, with porosities of 20% and above are known from outcrop and wells. But, modern, good quality seismic data are essential to allow sequence stratigraphic interpretation and a reasonable likelihood of predicting the distribution of reservoir facies. As part of its program to stimulate exploration in New Zealand, the NZ government is commissioning a new 4,000 km, highquality 2D seismic data set with the intention of making it freely available to interested exploration companies by mid-2005.The very thick sedimentary succession, the presence of direct hydrocarbon indicators on seismic data, the strong gas shows in wells drilled offshore and the reasonable expectation of oil generation and expulsion into numerous large structures with good reservoir facies combine to make the offshore East Coast Basin an attractive exploration venue.

A geophysicist's view of the Nansen Discovery, Gulf of Mexico

Editor's note: This paper is reprinted with permission from the September 2003 issue of Sea Technology magazine.www.sea-technology.com The Nansen Field was discovered in May 1999 by Kerr-McGee Corporation and Ocean Energy, on East Breaks Block 602, deepwater Gulf of Mexico. The field is located about 150 miles to the south of Houston, in 3700 ft of water and it is part of the Greater Nansen-Boomvang Field which includes West, North, and East Boomvang as well as Nansen and Navajo Fields with total reserves up to 320 million barrels of oil equivalent (MMBOE). The Nansen Field is the largest of the five, with reserves up to 180 MMBOE (Figure 1). It was fast-tracked and the first production commenced on 28 January 2002, with the world's first truss spar. Daily production of the field is expected to ramp up to a peak of about 40 000 barrels of oil and 80 million cubic feet of gas. Figure 1. The Greater Nansen-Boomvang Field with time structure map of the Nansen Field. The Nansen prospect is located on a series of downthrown three-way closures against faults. These closures are on the west flank of a Pliocene-Pleistocene depositional center (mini-basin). The mini-basin is bordered to the west along a north-south trending salt-cored ridge. Most of the faults are trending NNE-SSW, down to the east with significant displacement; some of them reach more than 1000 ft dip-slip, and therefore facilitate large vertical separations down into the mini-basin. The prognosis targets are Pliocene sands situated on the three-way closures with amplitude support. These Pliocene sand reservoirs are tied to the pay intervals in wells Redding and Bate 1 and Kerr-McGee 1 in the North Boomvang Field located in East Breaks Block 643. To ensure exploration success, the importance of thorough fundamental geologic work and detailed seismic mapping can …

Mio–Pliocene to Pleistocene paleotopographic evolution of Brittany (France) from a sequence stratigraphic analysis: relative influence of tectonics and climate

The Mio–Pliocene in Western Europe is a period of major climatic and tectonic change with important topographic consequences. The aim of this paper is to reconstruct these topographic changes (based on sedimentological analysis and sequence stratigraphy) for the Armorican Massif (western France) and to discuss their significance. The Mio–Pliocene sands of the Armorican Massif (Red Sands) are mainly preserved in paleovalleys and are characterized by extensive fluvial sheetflood deposits with low-preservation and by-pass facies. This sedimentological study shows that the Red Sands correspond to three main sedimentary environments: fluvial (alluvial fan, low-sinuosity rivers and braided rivers), estuarine and some rare open marine deposits (marine bioclastic sands: “faluns” of French authors). Two orders of sequences have been correlated across Brittany with one or two minor A/ S cycles comprised within the retrogradational trend of a major cycle. The unconformity at the base of the lower cycle is more marked than the unconformity observed at the top, which corresponds to a re-incision of the paleovalley network. A comparison of the results of the sequence stratigraphy analysis with eustatic variations and tectonic events during the Mio–Pliocene allows (1) to discuss their influence on the evolution of the Armorican Massif and (2) to compare the stratigraphic record with other west-European basins. The unconformity observed at the base of the first minor cycle may be attributed to Serravallian–Tortonian tectonic activity and/or eustatic fall, and the unconformity of the second minor cycle may be attributed to Late Tortonian–Early Messinian tectonic activity. The earlier unconformity is coeval with the development of a “smooth” paleovalley network compared to the jagged present-day relief. A single episode of Mio–Pliocene deformation recorded in Brittany may be dated as Zanclean, thus explaining the lack of the maximum flooding surface except in isolated areas. From this study, five paleogeographic maps were drawn up also indicating paleocurrent directions: three maps for the lower cycle (Tortonian retrogradational trend, Late Tortonian to Early Messinian maximum flooding surface and Messinian progradational trend) and two for the upper cycle (Pliocene retrogradational trend and Piacenzian maximum flooding surface). These maps show (1) the variations of paleocurrent directions during the Mio–Pliocene, (2) the extent of estuarine environments during the maximum flooding intervals and (3) a paleodrainage watershed oriented NNW–SSE following the regional Quessoy/Nort-sur-Erdre Fault during the retrogradational trend of the upper cycle and possibly during the progradational trend of the lower cycle. The present-day morphology of the Armorican Massif is characterized by (1) incised valleys and jagged topography, in contrast with the “smooth” morphology described for Mio–Pliocene times and (2) a main East–West drainage watershed, located to the north, separating rivers flowing towards the English Channel from rivers flowing towards the Atlantic Ocean. The Mio–Pliocene/Pleistocene paleotopographic changes seem to be controlled by climatic effects. These can be related to the change in runoff associated with warmer and wetter conditions during the Mio–Pliocene, which control the river discharge and lead to the development of extensive fluvial sheetflood deposits. Tectonic or eustatic factors exert a second-order control.

A first estimate of ground water ages for the deep aquifer of the Kathmandu Basin, Nepal, using the radioisotope chlorine-36.

The Kathmandu Basin in Nepal contains up to 550 m of Pliocene-Quaternary fluvio-lacustrine sediments which have formed a dual aquifer system. The unconfined sand and gravel aquifer is separated by a clay aquitard, up to 200 m thick, from the deeper, confined aquifer, comprised of Pliocene sand and gravel beds, intercalated with clay, peat, and lignite. The confined aquifer currently provides an important water supply to the central urban area but there are increasing concerns about its sustainability due to overexploitation. A limited number of determinations of the radioisotope 36Cl have been made on bore waters in the basin, allowing us to postulate on the age of ground water in the deeper, confined aquifer. Ground water evolution scenarios based on radioisotope decay, gradual dissolution of formational salts as the ground waters move downgradient, and flow velocity estimations produce comparable ground water ages for the deep waters, ranging from 200,000 to 400,000 years. From these ages, we deduce a mean ground water flow velocity of only 45 mm/year from recharge in the northeast to the main extraction region 15 km to the southwest. We thus estimate current recharge at about 5 to 15 mm/year, contributing 40,000 to 1.2 million m3/year to the ground water system. Current ground water extraction is estimated to be 20 times this amount. The low specific discharge confirms that the resource is being mined, and, based on current projections, reserves will be used up within 100 years.

ABSTRACT: Petroleum Geology of the Peng Lai 19-3 Oil Complex, Bohai Bay, People's Republic of China

The Peng Lai 19-3 (PL 19-3) Oil Field, in the south-central Bohai Bay, People's Republic of China, was discovered in May 1999 with the drilling of the PL 19-3-1 well by Phillips China, Inc., a subsidiary of ConocoPhillips. The PL 19-3-1 intersected a 425-m gross hydrocarbon interval in Miocene–Pliocene sands at a depth of approximately 1000 m. The PL 19-3-2 appraisal well, located 1.6 km south-southwest of the discovery well, intersected a gross hydrocarbon interval of 525 m in the same reservoir interval. Subsequent drilling of an additional five appraisal wells has proved that a large oil accumulation exists. The oil quality ranges from 13 to 23 API, with low pour-point temperatures and low wax content. Gas-to-oil ratios are relatively low and range from 100 to 300 scf/stbo. The oil field is on the northeast extension of a large basinal high and is interpreted as a north-south–trending wrench anticline associated with a major north-south strike-slip fault system (Tan Lu fault). En-echelon northeast-southwest–trending normal faults are intersected by north-south–trending wrench faults that divide and compartmentalize the anticline. Reservoirs are a stacked sequence (600–700 m) of unconsolidated to semiconsolidated postrift fluvial-lacustrine sands of good to excellent quality in the lower portions of the Miocene–Pliocene lower Minghuazhen Formation and the Miocene Guantao Formation. Top seal consists of intraformational mudstones in the lower Minghuazhen. Source rocks are organic-rich lacustrine mudstones in the synrift Oligocene Dongying and Eocene Shahejie Formations located in adjacent subbasins. A significant portion of the oil field is masked seismically by the presence of shallow gas which covers approximately 30% (14 km2, or 3460 ac) of the crestal area of the structure. A four-component, on-bottom cable seismic survey was initiated in the spring of 2000 to enhance the seismic imaging of this portion of the anticline.

Offshore Atlas Project: Methodology and Results

The Offshore Atlas Project (OAP) grouped 4,325 Miocene and older and 5,622 Pliocene and Pleistocene productive sands in the Gulf of Mexico into 91 chronostratigraphic hydrocarbon plays to aid the oil and gas industry with regional hydrocarbon exploration and field development. OAP has produced a two-volume atlas series entitled Atlas of Northern Gulf of Mexico Gas and Oil Reservoirs. Volume 1 comprises Miocene and older reservoirs, while volume 2 comprises Pliocene and Pleistocene reservoirs. Chronozones (Reed et al., 1987) were used to define geologic ages in the Gulf of Mexico. A chronozone is a time-stratigraphic unit defined by a particular benthic foraminifera biostratigraphic zone. The 26 chronozones identified by Reed et al. (1987) were further grouped into 14 Cenozoic and 2 Mesozoic chronozones for OAP. A composite type log (CTL), which shows the chronostratigraphic relationship of all productive sands in a field, was constructed for each of the 876 proved federal fields in the Gulf of Mexico. Depositional facies (retrogradational, aggradational, progradational, and submarine fan)were next identified on each CTL. The four facies were identified primarily according to characteristic SP-curve shapes, paleoecozones, and sand content. The chronozones and depositional facies identified on each CTL were then correlated among fields across the Gulf of Mexico. All productive sands correlated to the same chronozone and depositional facies were then identified as a unique play. Both federal and state fields in the Gulf of Mexico contain original proved reserves (sum of cumulative production and remaining proved reserves) estimated at 12.481 Bbbl of oil and condensate and 156.466 Tcf of gas (40.322 Bboe [sum of liquids and energy equivalent gas]). Of this, 9.943 Bbbl of oil and condensate and 122.263 Tcf of gas (31.698 Bboe) have been produced. Miocene plays contain the most total original proved reserves with 41.9 %, followed by Pleistocene plays (36.2 %), Pliocene plays (18.6 %), Mesozoic plays (2.9 %), and Oligocene plays (0.4 %). Miocene plays have produced the largest amount of total hydrocarbons, as well, at 43.5 % followed by Pleistocene plays (36.5 %), Pliocene plays (19.1 %), Oligocene plays (0.5 %), and Mesozoic plays (0.4 %). Just over two-thirds of the Gulf of Mexico's total original proved reserves are contained in progradational facies (67.4 %),with the remainder comprising submarine-fan facies (18.5 %), aggradational facies (9.9 %), retrogradationalfacies (2.4 %), combination facies (1.7 %), and caprock and reef reservoirs (0.1 %). Total cumulative production from the different facies closely mimics the distribution of original proved reserves. Of the 91 plays, the lower Pleistocene progradational play (LPL P.1) contains the most original proved gas reserves (10.5 %) and has produced the most gas (11.4 %). However, the upper upper Miocene eastern progradational play (UM3 P.1B) contains the most original proved oil and condensate reserves (18.9 %) and has produced the most oil and condensate (21.4%). Several technical studies resulting from OAP have been published. Hunt and Burgess (1995) described the distribution of OAP plays deposited by the ancestral Mississippi River delta system in the north-central Gulf of Mexico over the past 24 million years. The lower Miocene plays are restricted to the westernmost portion of the Louisiana shelf. In the late middle Miocene, the depocenter migrated east of the present-day Mississippi River delta. During the late upper Miocene, the depocenter began migrating back to the west and prograded basinward, and it continued to do so throughout the Pliocene and Pleistocene. Lore and Batchelder (1995) discussed how OAP plays can be used to find exploration targets and assess undiscovered resources. As an exploration tool, OAP play maps can be used to identify conceptual submarine-fan plays downdip of established shallow water producing facies, and to identify wells where a known producing facies or chronozone has not yet been reached. As an assessment tool, the extensive data sets associated with each OAP play can be used to infer statistically the size of undiscovered resources in a play to determine if exploration in that play is economically justifiable. Lore et al. (1995) estimated the amount of undiscovered conventionally recoverable resources in the Gulf of Mexico, basing their assessment on previous work performed for OAP. Mean level estimates show that, by far, submarine-fan plays have the greatest potential for additional oil and gas in the Gulf of Mexico, with 75.1 % and 70.4 % of the total oil and gas resources, respectively. Mean level estimates for the 13 OAP Miocene, Pliocene, and Pleistocene chronozones show that upper Pleistocene plays have the most oil resource potential (24.3 %), while lower Pleistocene plays have the most gas resource potential (20.6 %).

Abstract: West Delta Block 107 Field: Hidden under a Mudflow

ABSTRACT West Delta Block 107 Field, located eight miles seaward of the Southwest pass of the Mississippi River of 235 ft of water, contains approximately 18 million barrels of oil (MMBO) and 70 billion cubic ft of gas (BCFG) (recoverable) in 19 Pliocene sands. Hydrocarbons are trapped in a three-way structural closure down thrown to a large down-to-the-southwest growth fault. Water Oil & Gas Corporation discovered the field in 1993 with its OCS-G 8736 no. 1 well, located within a large active mudflow lobe that has caused major difficulties in seismic and drilling exploration over the years. Due to effects of the mudflow, pre-1983 2-D seismic data did not adequately define the amplitude response or the structure of the prospect. Only after 1988 3-D seismic data were reprocessed with refraction statics corrections by Shell Offshore, Inc. in 1993 was it possible to interpret structure and amplitude correctly enough to discover the field. 1996 3-D survey has further improved data quality and has refined our understanding of the field. The field has been developed by seven wells. Five of those wells were drilled from a conventional platform site (West Delta 106 A platform) outside of the mudflow and two miles west of the field. The two other wells (including the discovery well) are active subsea completions. Field production rate since February 1995 has averaged 7200 barrels of oil and 17 million cubic feet of gas daily. The Block 107 Field was nearly found in 1968 by a Humble well and in 1983 by a McMoran well, each of which missed the main accumulation by less than 200 feet horizontally. End_of_Record - Last_Page 569-------

Neotectonic and seismic activity in the Armorican and Cornubian Massifs: Regional stress field with glacio-isostatic influence?

In Brittany and SW England, evidence for low magnitude Quaternary seismicity can be found in sand pit exposures and beach sections. Deformation is especially well seen in alluvial and estuarine complexes resting on Late Pliocene sands or thick saprolite. The deformations are shallow, dominantly hydroplastic (high water-table) and led to overconsolidated sands, silts or clays. They reveal normal loading at micro (millimetric) and macro (decametric) scales as controlled by the local rheological properties of the sediments, by strikeslip faults associated with positive flower structures, folding, and intraformational water expulsion or hill slope sliding with reverse microfaulting. All the sites where these features occur, are in the vicinity of presumed active faults or steep slopes in highly fractured Proterozoic basement rocks indicating a possible shear zone. In most cases, these features are not associated with synsedimentary deformation, as strong superficial red soils are generally reworked by them. All these features are reworked by microfaulting after overconsolidation. Additional periglacial phenomena are superimposed on them and are often confused with them. Deformation occurred after the development of Holstenian peats (isotopic stage 11,400 ka BP) at Crozon (Brittany), after 317 ka BP (beginning of isotopic stage 9) in the Vilaine estuary, and in most other sites before the last rubified pedogenesis in the Middle Pleistocene (presumed isotopic stage 9). These dates correspond to the same episode that gave rise to the last main reactivation of the fossil cliff around 300 ka BP and to local uplift. One or several seismic clusters have taken place, probably due to delayed crustal rebound after a major glacial event (stage 10) and to rapid loading resulting from younger ice sheet growth (stage 8). Similar events occurred in late stage 7 and late stage 5. These events might have locally amplified the crustal deformation of the old Brittany and Cornubian Hercynian massifs resulting from a regional stress field especially from 400 ka to 200 ka BP. Stratigraphical, geodynamical and paleoclimatological implications are discussed.

Detection of gas migration from a deep source by the use of exploration 3D seismic data

Periods of sustained gas seepage since Mid Miocene time is indicated in exploration 3D seismic data from the area of the Sleipner fields in the North Sea. Buried mounds, suspected to be mud volcanoes, may have been generated in association with gas migration in Mid Miocene time. Minor faults and fractures are present at the same horizon, and the mud volcanoes seem to be distributed along some of these. Seismic chimneys indicate migration of gas from below this level through the faults and fractures and up to the seabed. Shallow gas accumulations in Late Pliocene sands above the mud volcanoes may be a result of the gas migration. Possible buried craters, overlying seismic chimneys, may have been generated in a period of sustained gas seepage followed by a less active period during which the craters have been buried. A large depression at the seabed, overlying seismic chimneys, indicates a recent period of sustained gas seepage. The gas is believed to have migrated from the Sleipner gas reservoirs.

Reservoir geochemistry of South Pass 61 Field, Gulf of Mexico: compositional heterogeneities reflecting filling history and biodegradation

Cluster analysis of GC data for gasoline and mid-range hydrocarbon ratios from fifty-one South Pass 61 Field oils reveals geochemically similar oil clusters corresponding to geographically coherent groups. Insight into the groupings is obtained from examination of indicators of geochemical processes, e.g., anaerobic biodegradation, aerobic biodegradation and extensive remigration of light ends. Six duplicate samples collected in 1986 and 1992 as well as replicate runs on a single sample showed excellent analytical reproducibility. Subtle but consistent differences in both gasoline and oil-range hydrocarbon maturity indicators are observed between the east, west, and far west flanks of the field, suggesting filling of different segments of the reservoir from different kitchens at slightly different stages of thermal maturity or with slightly different chemical character. The west flank of the salt dome was charged with slightly more thermally mature petroleum than the east flank. The stratigraphically oldest and deepest sand on the far west flank has received the most mature petroleum. Different fluid contacts and GORs are observed in different sands and different fault blocks. The stacked pay geometry of the field and widespread faulting have led to considerable remigration of gas and condensate as observed in other fields in the Gulf of Mexico (Thompson, 1987). Biodegradation varies in severity with depth and reservoir zone, but is frequently overprinted by remigration of light end hydrocarbons. Anaerobic biodegradation by sulfate-reducing bacteria is probably the cause of light to moderate alteration in intermediate depth Pliocene sands which are hydraulically connected to the salt dome (with dissolution of anhydrite from the salt dome providing the sulfate). Widespread late pyrite formation in reservoir sandstones is inferred to represent the ultimate sink for reduced sulfur from sulfate reduction during oil biodegradation. Co-produced water compositions suggest no oxygenated freshwater infusion.

Late Pliocene sand ridges at the western margin of the Barents Sea—do they monitor Late Pliocene glaciations?

Seismic data combined with core analysis of the northwesternmost exploration well on the Norwegian continental margin, well 7316/5-1, has been used to map and discuss the genesis of three well-defined sand ridges. The sand ridges have a NE-SW to N-S orientation and are of Late Pliocene age. The dimensions of the ridges are: height 40 m, length 2–4 km and width 0.5–1 km. In relation to the glaciation models of the Barents Sea, the position of well 7316/5-1, and especially information from a core that penetrated one of the sand ridges, provide important information. The ridges are not, in themselves, diagnostic for grounded glaciers at the margin of the Barents Sea shelf during the Late Pliocene, although the presence of pebbles in a cored section of the ridges may represent ice-dropped material. Whether the possible influx of glaciogenic material is related to local or regional glaciations on the Barents Shelf remains to be evaluated.

Sequence Stratigraphic Setting of Turbidite-Related Petroleum Fields, Green Canyon and Ewing Bank Lease Areas, Northern Gulf of Mexico: ABSTRACT

The Green Canyon (GC) and Ewing Bank (EW) OCS lease areas have 17 discoveries/fields, primarily from bathyal turbidite systems. Salt has played a significant role in the formation of the intraslope basins that the turbidite systems were deposited in, by influencing the flows of turbidities throughout the basin, in the subsequent trap formation, and, in some cases, as a seal. Nearly every field/discovery is associated with a seismic amplitude anomaly. Fields generally have multiple pay zones, with up to 22 in GC 184 (Jolliet). To date, eight of the fields are producing: EB 826, EB 873 (Lobster), GC 6 (Kodiak), GC 18, GC 53/54 (Marquette), GC 65/110 (Bullwinkle), GC 184 (Jolliet), and GC 205 (Vancouver). Other fields expected to be developed are GC 72/116 (Popeye), GC 254 (Allegheny), GC 200/244 (Olivella), GC and GC 166 (Bison). Other discoveries that were produced and then abandoned include GC 19, and GC29. Producing reservoir facies are highly variable across the area. Turbidite reservoir geometries in Pliocene sands (>1.6 Ma) consist of sheets and amalgamated sheet sands. Pleistocene sands are characterized primarily from channel-levee systems and related deposits. These sands tend to more compartmentalized with separate oil/water or gas/water contacts. Most reservoir sands occurmore » within 100 ft overlying a sequence boundary, indicating the eustatic control on the timing of reservoir sand deposition.« less

New Stratigraphic Technologies in Exploration/Exploitation: ABSTRACT

Abstract With the demand for increased accuracy and precision in the interpretation of seismic sections for the prediction of reservoirs and traps, traditional paleontologic and new non-paleontologic stratigraphic data have assumed a greater role in exploration/exploitation. Strata bounded by sequence boundaries can be dated precisely by the graphic correlation technique. For example, Arabian Cretaceous reservoirs pinch out by facies change and diagenesis into coeval strata. But Pliocene sands in the Gulf Coast are truncated by regional unconformities accentuated by salt dome movement. In this Plio-Pleistocene section high precision chronostratigraphy is achieved by the integration of paleontological and geochemical data. Detailed biostratigraphic analysis of many sections of Mississippian carbonates along the eastern side of the Transcontinental Arch allows for the recognition of four unconformity-bounded units (biothems of Lane and others, 1994). These biothems have been traced from Illinois to New Mexico and are not easily detected in the subsurface by using seismic or electric log technology because of the rather uniform carbonate lithologies composing the entire Mississippian in the region. Mississippian hydrocarbon production in western Kansas can be shown to be associated with these intra-Mississippian carbonate-on-carbonate unconformities that are easily detected biostratigraphically.

A latest Cretaceous hotspot and the southeasterly tilt of Britain

The southeasterly regional dip of England and Wales is usually ascribed to Miocene movements. Loss of up to 2 km of cover from northern England, shown by apatite fission track analysis, has been related to uplift and erosion induced by a mantle hotspot, but its effects were far more widespread than considered hitherto. Outcrop patterns throughout much of England, Wales and eastern Ireland can be related to a hotspot beneath the Irish Sea. Uplift occurred within the late Maastrichtian and erosion continued into the late Palaeogene. After post-Oligocene down-faulting of the Irish sea, the modern drainage was initiated on the eroded surface. Unconformities provide the best means of dating orogenic movements; in some localities the time interval between the youngest rocks preserved beneath the unconformity and the oldest preserved above may be small enough to enable the dating of fold movements to be determined with some precision. Thus in southeastern Britain the major E-W structures of the Hampshire Basin, the Weald and the London Basin can be dated as Miocene, as rocks of Oligocene age are involved in the folding in the Hampshire Basin and Pliocene sands rest in erosional pockets of the Chalk of SE England. Because fold movements tend to affect large areas of the crust at discrete intervals of time, the southeasterly tilt of Britain, evident from the fact that a NW-SE transect from Anglesey to London crosses outcrops of rocks getting progressively younger from the Precambrian of Anglesey to the Tertiary of the London Basin, has

Tectonic causes of landslides

AbstractThe relationship between mass movements and tectonic lineaments is investigated in the Pliocene sand and clay terrains of Montepulciano (central Italy). Satellite images and aerial photographs show six families of lineament in southern Tuscany, all of which are present in the Montepulciano area. The orientation, location and density of these are related to corresponding attributes of morphological phenomena such as retrogressive slumps, drainage density and slope angle. Rose diagrams, stereographic plots and statistical analysis all reveal a close correspondence between slumping mass movements and the directions and spatial concentrations of fracture traces. Although slopes and valley trends respond more closely to Apennine (NW‐trending) and anti‐Apennine (NE‐trending) lineaments, the longitudinal axes of landslides are strongly orientated NNW to N, the direction of one of the most significant lineament groups in western central Italy and the local study area.

Stress field changes in the Rhone Valley from the Miocene to the present

Study of the deformation of Neogene and Quaternary deposits in the Rhône Valley shows that the end-Miocene E-W greatest principal compression ( σ 1) that deformed the Western Alps did not continue into the Quaternary, at least between Vienne and Montélimar. The Middle to Upper Miocene molasse on the east side of the Rhône Valley was affected by E-W compression at the end of the Miocene, causing reverse faulting and N-S folding (St. Lattier and Varacieux anticlines). In contrast, the Pliocene sands and clays of the Rhône Valley are unaffected by folding and show only small normal faults with a maximum throw of l m trending between N-S and NW-SE. These were caused by E-W to NE-SW extension, which is incompatible with the E-W compression that characterises the latest-Miocene Alpine phase. These structures are the surface expression of extension that was probably induced locally by the overall compressive regime that exists to the present day in this part of Western Europe [the “transcurrent extensional regime” of Philip (1983), USTL thesis, Montpellier]. This stress field results from the collision of the African and European plates that began in the Tertiary. West of the frontal Pennine thrust, the present-day direction of compression, which is deduced from calculated focal mechanisms and from in-situ stress measurements, varies between N-S and NW-SE. In the Grenoble region and the northern Massif Central, the focal mechanisms indicate transcurrent movement, with σ 1 horizontal and oriented between N-S and NW-SE, and with σ 2 vertical. In the southwestern Massif Central and the Vendée, however, they indicate an extensional tectonic regime, with σ 1 vertical and σ 2 horizontal and oriented NW-SE, σ 3 trends NE-SW. This orientation is similar to that which would have caused the small Pliocene normal faulting observed in the Rhône Valley between Vienne and Montélimar. In this part of the Rhône Valley, west of the frontal Pennine thrust, the E-W stress resulting from the collision of Apulia (Italy) with the West European plate has not been in evidence since the Pliocene. The E-W compression has been replaced by N-S to NW-SE compression resulting directly from the collision between the African and European plates transmitted through the Straits of Gibraltar and the Iberian microplate in the west and the Corsica-Sardina block in the east. The piercing effect of the Apulian block is no longer dominant in the Rhône Valley.

Development of a Mature Giant Offshore Oil Field

Summary The Teak field, a mature oil field offshore southeast Trinidad, has produced266 million bbl oil since 1972. Production is from Pliocene sandstonereservoirs in a Pliocene sandstone reservoirs in a complexly faulted anticline. This paper summarizes the history and geology of Teak field, describes itsoil-producing reservoirs, and discusses the mature-field development strategyused since 1988, including case histories of two 1989 developmentprospects. Introduction The Teak field, the fourth largest oil field in Trinidad, is located 25miles off the south-east coast of the island in 190 ft of water (Fig. 1). Discovered by Amoco Production Co. in 1969, Teak has produced 266 million bblof oil and 1.1 trillion scf of gas from 1972 through 1990. Teak is a mature oilfield with significant depletion after its first 19 years of production. Despite a steep natural decline rate of 25%/yr, the field has respondedfavorably to renewed development drilling since 1989. A steady downward trendin production rate reversed, and the field achieved its highest rate in almost5 years in July 1990. A primary factor in the reversal of the decline rate wasa deliberate multidisciplinary team approach to reservoir development. Geology Structural Setting. The Teak field is located in a regionalcompressional-wrench terrain about 40 miles south of the current Caribbean and South American plate boundary along the El Pilar fault (Fig. 1). The fieldproduces hydrocarbons from Pliocene sandstones from 4,000 to 14,000 ft belowsea level. Hydrocarbons are trapped in a steep anticlinal structure along aneast/west-trending compressional ridge bisected by a large fault (Fig. 2). Thisfault dips east-northeast at 35 to 45 degrees, with vertical offset of 2,000 to3,000 ft, splitting the field into two separate hydrocarbon accumulations: oiltrapped to the west on the upthrown side of the fault and gas trapped to theeast on the downthrown side of the fault. In addition to normal offset, Fault Fexhibits left-lateral wrenching, indicated by displacement of the downthrownstructural crest about 1 mile north of the upthrown crest. This paper focusesprimarily on the upthrown oil reservoirs, which are arranged as stackedthree-way closures behind the major sealing Fault F and are between 4,000 and12,000 ft subsea (ss) (Fig. 3), informally called the Teak A-C-E field. The Teak structure is characterized by fairly steep bed dips that average 10degrees and steepen locally to more than 30 degrees. Bed dips are locallyvariable in both direction and magnitude. The structural geometry iscomplicated by myriad cross-cutting normal faults that segment the field intonumerous compartments. The oil accumulation up-thrown to Fault F is separatedinto two major fault blocks by Fault F (800 to 1,500 ft vertical offset) andseveral minor fault blocks. About 90% of the Teak field oil produced to datehas been trapped upthrown to both Faults F and F2, although deeper reservoirshave been (discovered and produced between these faults. Stratigraphy and Petrology. Teak oil reservoirs span an 8,700-ft-thickstratigraphic section in the Pliocene that contains approximately 60 % sand and 40% shale. Teak sands are typically very fine-grained (from 0.06 to 0.12 mm ingrain size) and extremely well-sorted, and average more than 90% quartz withlittle or no visible cement. Porosities average 27 to 33%. Teak shales Porosities average 27 to 33%. Teak shales exhibit a variable resistivity andgamma ray log response, unlike clean shales typical of the U.S. Gulf of Mexico. Shale lithologies vary from argillaceous shales to arenaceous mudstones, andtextures vary from soft to well-indurated and phyllitic. Oil-producing sandsexhibit no appreciable stratigraphic thickness variation across theoil-productive area. The Pliocene producing section is 10 to 20% thicker on thedownthrown side of Fault F, but individual sands maintain an excellentcorrelation across the field. The environment of deposition for the Pliocenesands is probably a broad, shallow Pliocene sands is probably a broad, shallowmarine shelf proximal to the Orinoco delta, where strong, steady coastalcurrents provided a uniform energy regime. Oil Reservoirs Reservoir and Fluid Parameters. High-quality crude oil, 27 to 33 degrees API, has been produced from 17 different sandstone reservoirs (Fig. 3 and Table1). Individual sands vary from 10 to 440 ft in thickness. Sand porosities rangefrom 18 to 33%, decreasing slightly with depth. Initial water saturationsaverage 25%, with residual oil saturation of 20%. Hydrocarbon columns rangefrom 170 to 900 ft of oil with thin gas caps. April 1991 P. 392

Detailed Layer Studies in the East Wilmington Oil Field

Recent detailed studies have been made of the Pliocene and upper Miocene sequences in the East Wilmington oil field. Roughly 1,200 vertical ft of section (Ranger Zone) were evaluated in fault blocks VI and VII. The sequence was broken into 40 to 50 correlatable units (sub-subzones) based on electric logs. Twelve horizons (subzones) were used to guide the correlation work and aid in the construction of true stratigraphic logs. The TST logs were used to make many north-south and east-west cross sections. This provided good loop control for correlations. Over eight hundred wells were evaluated in this way. Structure maps, isochore maps, and percent sand maps were constructed. The primary purpose of this work was to determine the net pay for the Ranger zone. This work has found excellent secondary applications including definition of flow units, clarification of stratigraphic sequencing, and depositional history. The depositional history involved the sedimentation and transport of lobed deposits and sheet or draped deposits. The Upper Miocene sands are intercalated with shales and siltstone. These thin turbidites are reasonably wide spread and show some lenticularity but not the lobate lenticularity that is common in the Pliocene sands. The Pliocene section is dominated by large lobatemore » fans. These lenticular depositional units show much about sediment transport. The lobes lie laterally between each other with each successive lob filling the low area adjacent to or between the earlier lobes. Balancing of the deposited sand results. Knowledge of the lobed nature of the sands and specific localized characteristics helps in the design of injection programs that will greatly improve the sweep efficiencies.« less

Fault-Zone Seals in Offshore Trinidad Oil Fields

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