Marine Claystones Research Articles

Syn-depositional oil seeps in the Late Albian Paddy Member of the Peace River Formation (Early Cretaceous), north-central Alberta

Abstract Controversy exists regarding the timing of emplacement of oil in the giant Athabasca and Peace River oil sands. Bitumen-cemented sandstones are present in the late Albian Paddy Member of the Peace River Formation; some cemented sandstones formed burrowed firmgrounds and reworked intraclasts, showing that oil was reaching surface by about 101–102 Ma. Estuarine and shallow-marine sandstones of the Paddy Member are exposed on the Peace and Heart rivers in the vicinity of the town of Peace River. Bitumen-cemented sandstone occurs in four stratigraphic settings: 1) An in-situ cement forms locally bedding-transgressive, sheet-like masses in cross-bedded estuarine sandstone; 2) A bitumen-cemented and heavily burrowed layer, 30–60 cm thick, lies immediately beneath a marine transgressive surface and shows that oil infiltrated downward into, and cemented, the upper surface of a shoreface sandbody. The firm sand was subsequently exhumed by transgressive erosion, fractured and burrowed by arthropods; 3) Rounded pebble- to cobble-sized clasts of bitumen-cemented sand lie on the floor of a tidal channel, and the channel floor surface is also stained and burrowed. This case suggests floating oil infiltrated the channel floor at low tide, subsequently hardening prior to erosion and burrowing; 4) Rounded cobble-to boulder-size clasts of bitumen-cemented sandstone, up to 1 m wide and 0.5 m thick, lie on a regional marine ravinement surface cut on the uppermost Paddy shoreface sandstone. The sand was permeated with oil, top-down, then oxidized to form a tough bitumen cement. The bituminous sand was subsequently scoured by waves during marine transgression to form a boulder lag that is enclosed in transgressive marine claystone. All four of these examples show that oil was reaching the Earth’s surface during Paddy time where it infiltrated porous sands to a depth of several decimetres, subsequently degrading and oxidizing to form a tough ‘asphalt pavement’ that attracted a burrowing firmground fauna and was eroded into cohesive intraclasts weighing many tens of kilograms. Pyrolysis proved the bitumen cement to be degraded oil, but it was not possible to identify the source-rock using gas chromatography-mass spectrometry. The Paddy ‘asphalt pavements’ are comparable to cements that form in beach sediments in the wake of catastrophic spills from tanker groundings. A direct analogue is provided by Eocene estuarine sediments in Dorset, U.K. There, bitumen-cemented estuarine sands also formed firmgrounds and intraclasts on channel-floor and marine transgressive surfaces.

Triassic (Anisian and Rhaetian) palaeomagnetic poles from the Germanic Basin (Winterswijk, the Netherlands)

In this paper, we provide two new Triassic palaeomagnetic poles from Winterswijk, the Netherlands, in the stable interior of the Eurasian plate. They were respectively collected from the Anisian (~ 247–242 Ma) red marly limestones of the sedimentary transition of the Buntsandstein Formation to the dark grey limestones of the basal Muschelkalk Formation, and from the Rhaetian (~ 208–201 Ma) shallow marine claystones that unconformably overlie the Muschelkalk Formation. The magnetization is carried by hematite or magnetite in the Anisian limestones, and iron sulfides and magnetite in the Rhaetian sedimentary rocks, revealing for both a large normal polarity overprint with a recent (geocentric axial dipole field) direction at the present latitude of the locality. Alternating field and thermal demagnetization occasionally reveal a stable magnetization decaying towards the origin, interpreted as the Characteristic Remanent Magnetization. Where we find a pervasive (normal polarity) overprint, we can often still determine well-defined great-circle solutions. Our interpreted palaeomagnetic poles include the great-circle solutions. The Anisian magnetic pole has declination D ± ∆Dx = 210.8 ± 3.0°, inclination I ± ∆Ix = − 26.7 ± 4.9°, with a latitude, longitude of 45.0°, 142.0° respectively, K = 43.9, A95 = 2.9°, N = 56. The Rhaetian magnetic pole has declination D ± ∆Dx = 32.0 ± 8.7°, inclination I ± ∆Ix = 50.9 ± 8.1°, with a latitude, longitude of 60.6°, 123.9° respectively, K = 19.3, A95 = 7.4°, N = 21. The poles plot close to the predicted location of global apparent polar wander paths (GAPWaPs) in Eurasian coordinates and are feasible for future apparent polar wander path construction. They confirm that the intracontinental, shallow-marine Germanic Basin, in which the Muschelkalk Formation was deposited, existed at a palaeolatitude of 14.1° [11.3, 17.1] N, in a palaeo-environment reminding of the Persian Gulf today. In Rhaetian times, palaeolatitudes of 31.6° [24.8, 39.8] N were reached, on its way to the modern latitude of 52°N.

Source rocks of the German Central Graben

Abstract Jurassic to Lower Cretaceous formations are the most important source rocks for hydrocarbons in the southern Central Graben area. Within the Dutch Central Graben, the Lower Jurassic Posidonia Shale Formation is the most prolific source for hydrocarbons, while the Upper Jurassic to Lowermost Cretaceous Bo Member of the Farsund Formation plays this role in the Danish Central Graben. Oil and gas discoveries in the Norwegian, Dutch and Danish part of the Central Graben proved a prolific petroleum system. Despite limited success of hydrocarbon exploration in the German part of the Central Graben, various indications suggest migration of gas out of active thermogenic source rocks that are closely related to potential shallow gas accumulations. These indications include the restricted location of the bright spots above the Jurassic graben system, the occurrence of gas chimneys underneath these accumulations and geochemical data from offshore The Netherlands, which support contribution of thermogenic gas. The purpose of this study is to assess the potential for generating thermogenic hydrocarbons from Upper Triassic to Lower Cretaceous formations. For this reason, prominent source rocks of the Southern North Sea, i.e. the Posidonia Shale Formation and the Upper Jurassic to Lower Cretaceous “Hot Shales” (namely Clay Deep Member offshore The Netherlands and Bo Member offshore Denmark), were mapped in detail. These and other potential formations from the Late Triassic to the Early Cretaceous are integrated into an existing petroleum system model of the Northern German North Sea, which was modified for the new requirements. The results showed that the main source rocks of the southern Central Graben, the Posidonia Shale Formation, and the Upper Jurassic – Lower Cretaceous “Hot Shales” are insignificant as sources for commercial hydrocarbon accumulations within the German Central Graben area. That is either due to marginal occurrence or to low maturity. However, Lower to Upper Jurassic formations such as marine claystones of the Aalburg Formation and the lower parts of the Kimmeridge Clay Formation, as well as coaly intervals of the Central Graben Subgroup, are likely to have generated, and still generate, hydrocarbons.

Influence of Oil Sands Composition on Bitumen Quality During Non‐Aqueous Bitumen Extraction from the Athabasca Deposit

ABSTRACTThe aim of the present work is to identify the most important species affecting a non‐aqueous bitumen extraction process and bitumen quality. This investigation was carried out on four petrologic end member samples from Syncrude's North Mine collected in 2012 (NM12), i.e., marine claystone (MC), marine sand (MS), estuarine claystone (EC), and estuarine sand (ES). Each end member was separately mixed with cyclohexane at a ratio of 40:60 (cyclohexane:end member), and the bitumen‐cyclohexane solutions were collected at different settling times (1–30 min). These solutions were analyzed to determine the amount, particle size distribution, and mineralogical composition of suspended fine solids (SFS), water content, as well as the bitumen content using a focused beam reflectance measurement (FBRM) particle size analyzer, Karl Fischer (KF) titration, x‐ray diffraction (XRD), quantitative XRD (QXRD), and elemental analysis. The SFS was composed of mainly illite and kaolinite after cyclohexane extraction from MC, MS, EC, and ES. Although mixed layer expandable clay minerals (i.e., illite‐smectite and kaolinite‐smectite) were identified in the original clay, end members (EC and MC), illite‐smectite, and kaolinite‐smectite were not observed in the SFS of the bitumen‐cyclohexane solutions obtained from the four petrologic end members. The SFS content and bitumen quality of the bitumen product were affected slightly but significantly by the end member composition and settling time, respectively. Illite and kaolinite were identified as the main minerals in the SFS of the bitumen products after relatively long settling times.

Predicting Effective Diffusion Coefficients in Mudrocks Using a Fractal Model and Small‐Angle Neutron Scattering Measurements

AbstractThe determination of effective diffusion coefficients of gases or solutes in the water‐saturated pore space of mudrocks is time consuming and technically challenging. Yet reliable values of effective diffusion coefficients are important to predict migration of hydrocarbon gases in unconventional reservoirs, dissipation of (explosive) gases through clay barriers in radioactive waste repositories, mineral alteration of seals to geological CO2 storage reservoirs, and contaminant migration through aquitards. In this study, small‐angle and very small angle neutron scattering techniques have been utilized to determine a range of transport properties in mudrocks, including porosity, pore size distributions, and surface and volume fractal dimensions of pores and grains, from which diffusive transport parameters can be estimated. Using a fractal model derived from Archie's law, we calculate effective diffusion coefficients from these parameters and compare them to laboratory‐derived effective diffusion coefficients for CO2, H2, CH4, and HTO on either the same or related mudrock samples. The samples include Opalinus Shale from the underground laboratory in Mont Terri, Switzerland, Boom Clay from a core drilled in Mol, Belgium, and a marine claystone cored in Utah, USA. The predicted values were compared to laboratory diffusion measurements. The measured and modeled diffusion coefficients show good agreement, differing generally by less than factor 5. Neutron or X‐ray scattering analysis is therefore proposed as a novel method for fast, accurate estimation of effective diffusion coefficients in mudrocks, together with simultaneous measurement of multiple transport parameters including porosity, pore size distributions, and surface areas, important for (reactive) transport modeling.

Sedimentology and depositional environments of the Ordovician Umm Sahm Sandstone Formation in southern Jordan

The Ordovician Umm Sahm Sandstone Formation of Jordan comprises approximately 200-m-thick succession of fluvial quartzarenites with subordinate claystone and siltstone lithologies of shallow marine conditions. The Umm Sahm Formation is characterized by its dark brown color, frequent jointing, and steep scarps. The Umm Sahm Formation is bounded by the marine claystones of Hiswah Formation at the top and the fluvial sandstones of the Disi Formation at the bottom. The Umm Sahm Formation is composed of two main facies: fluvial facies and tidal facies. The fluvial facies constitutes about 93% of the total thickness. The lower few meters of the succession passes upward from the Disi Sandstone Formation into similar massive white sandstone facies exhibiting similar white color, fine- to coarse-grained sandstone, with round-shaped pebbles. Trough and planar cross-bedding show a northwest unidirectional palaeocurrent trend. Light brown colored quartzarenites similar to those of the Cambrian Umm Ishrin Sandstone Formation are most common in the upper part of the succession. The tidal facies occupies three intervals in the middle part of the succession. It is composed of laminated and thin-bedded sandstones, siltstones, and claystones. They are rippled and varicolored with abundant trace fossils (Cruziana, Harlania, ruzophycus). The presence of hummocky cross stratification indicates the earliest short-lived tempestite conditions during the Paleozoic erathem of Jordan. The first appearance of Graptolites in the Ordovician rocks of Jordan was recorded during this study in the tidal facies of the Umm Sahm Formation. The vertical arrangement of both fluvial and tidal facies indicates three successive short-lived transgressions and regressions. These marine incursions indicate the successive shoreline advances of the Tethys Ocean, which was located northward, and inundated the southern braid plain. The three short-lived transgressive events took place, and the Tethys marine margin was displaced southward, giving rise to deposition of tidal facies in an open coast tidal flat. Following the transgressive events, renewed progradation and strandline retreat took place, fed by large amounts of siliciclastics derived from the continent and transported by braided streams across the intertidal zone.

Tunisian gypsums: Characteristics and use in cement

Gypsum materials of hundred meters thickness and interbedded with marine claystones and limestones from different paleogeographic sectors in the Tunisian territory are studied to assess their suitability for cement production. For this reason, thirty representative samples are analysed by chemical, physical and geotechnical tests. The obtained results for the studied gypsum materials are compared to Tunisian and European norms and with the local cements, currently marketed and which obey international norms. Indeed, for all samples hydraulic modulus HM, silica modulus SM and alumina modulus AM vary from (2.37–2.44), (2.48–2.68) and (1.45–2.5), respectively; whereas the required values for these modulus are (1.5–2.5), (2–3) and (1.5–2.5). The same behavior is observed for mineralogical analyses of C3S, C2S, C3A and C4AF and compressive strength at different ages.Briefly, Tunisia contains important reserves of gypsum scattered and spread over the Tunisian territory and can be used for cement production.

EVOLUTION AND TAXONOMIC STUDY OF THE CRETACEOUS PLANKTIC FORAMINIFERAL GENUS HELVETOGLOBOTRUNCANA REISS, 1957

The evolution and taxonomy of the planktic foraminifer genus Helvetoglobotruncana Reiss, 1957, are investigated to improve stability in the concepts of the biomarker species Hv. praehelvetica and Hv. helvetica , which have been used to correlate uppermost Cenomanian–middle Turonian (Upper Cretaceous) marine sediments worldwide. The study focuses on exquisitely preserved specimens obtained from Turonian marine claystones drilled on the coastal margin of Tanzania, and these are compared with specimens reported from a number of Cenomanian/Turonian boundary sequences worldwide. Absence of discernable shell recrystallization in the Tanzanian specimens provides an unprecedented opportunity for detailed observations of the external wall texture and wall microstructures, allowing for a more concise characterization of similarities and differences between the two species. Abundance counts of Turonian planktic foraminifer assemblages from one Tanzania borehole reveals that Hv. helvetica occurs in trace abundance early in its range and reaches maximum abundance of 35–45% of the total assemblage shortly before the simultaneous and abrupt extinction of both helvetoglobotruncanid species. The ratio between Hv. helvetica and Hv. praehelvetica increases gradually up-section, with a 1:1 ratio reached nearly halfway above the lowest occurrence level of Hv. helvetica and 9:1 dominance by Hv. helvetica near the top of its range. The helvetoglobotruncanid and mixed whiteinellid species yield δ 13 C and δ 18 O values that are nearly identical and slightly more enriched in δ 18 O than co-occurring Globoheterohelix paraglobulosa, and they are slightly more enriched in d 13 C and more depleted in δ 18 O than co-occurring species of Dicarinella and Praeglobotruncana. These isotopic results indicate that helvetoglobotruncanids lived at relatively shallow depths in the mixed layer. Using an age model developed for the Rock Canyon Anticline Cenomanian/Turonian Global Stratotype Section and Point (GSSP) sequence near Pueblo, Colorado, the age of the first occurrence of Hv. helvetica is calculated as 93.52 Ma. The extinction of Hv. helvetica has not been properly calibrated, but it must be younger than 92.77 Ma, which is the age of its occurrence at the top of the Rock Canyon Anticline GSSP section.

Formal ratification of the GSSP for the base of the Calabrian Stage (second stage of the Pleistocene Series, Quaternary System)

The Calabrian Stage is now formally defined by the Global Boundary Stratotype Section and Point (GSSP) at Vrica, Calabria, Italy. This GSSP had previously defined the base of the Pleistocene Series. The Calabrian becomes the second stage of the Pleistocene Series and Quaternary System, following the Gelasian. The GSSP occurs at the base of the marine claystone conformably overlying sapropelic bed 'e' within Segment B in the Vrica section. This lithological level represents the primary marker for the recognition of the boundary, and is assigned an astronomical age of 1.80 Ma on the basis of sapropel calibration. It coincides with the transition from Marine Isotope Stage 65 to 64, and the underlying sapropel bed 'e' is assigned to the Mediterranean Precession-Related Sapropel layer 176. Secondary markers include calcareous plankton bioevents of widely distributed taxa. The boundary falls between the highest occurrence of Discoaster brouweri (below) and the lowest common occurrence of left-coiling Neogloboquadrina pachyderma (above), and below the lowest occurrences of medium-sized Gephyrocapsa (including G. oceanica) and Globigerinoides tenellus. The top of the Olduvai Subchron is identified c. 8 m above the GSSP. Ratification of the Calabrian Stage effectively completes the Lower Pleistocene Subseries.

Stratigraphy and Tectonics of the Sengkang Basin, South Sulawesi

DOI: 10.17014/ijog.v5i1.89Sulawesi was formed during the Oligocene - Miocene collision between the Eurasian Plate and micro-continental fragments detached from the Indian-Australian Plate. The Sengkang Basin situated on the South Sulawesi Province, was formed by a major north northwest - south southeast trending fault system of the Walanae Fault Zone, which was followed by the formation of Late Neogene foreland basin and syn-orogenic deposition. The fault system separated the eastern and western parts of South Sulawesi and influenced the deposition during the Late Miocene to Quaternary. The lower part of the deposition unit consists of small carbonate reefs of the Tacipi Member occupying the East Sengkang Basin, where this shallow marine facies is intercalated within or overlies marine claystones representing the base of the Walanae Formation. The middle sequence is interpreted as a delta foreset consisting of the Samaoling and Beru Members. During the deposition of these two members, the northern part of the Sengkang Basin gradually changed from a tidal and deltaic to fluvial environments. Furthermore, the upper sequence of this sedimentary unit is dominated by fluvial deposits.

Morphological analysis and erosion rate evaluation in badlands of Radicofani area (Southern Tuscany — Italy)

Abstract Since 1988, geomorphologic research based on field surveys and photo-geological analysis, has been conducted in southern Tuscany (Italy), in areas characterised by very rapid morphological evolution. In the area outcrop Pliocene marine claystones uplifted during the Quaternary up to 750 m above sea level, now undergoing intense erosion processes, leading to considerable badlands formation. Morphodynamic analysis, conduced by direct and indirect measurements in a sample area, were taken in order to quantify the erosion rate in badland areas. The “Torrente Piantrafolla” sample area was chosen as representative of the study area; it was most recently monitored during the period Nov. 2000–Feb. 2004. At this time, morphographic and morphometric analyses carried out in selected measurement stations located on slopes, identified gravity as the main morphogenetic process responsible for slope shaping. The calanchi badland areas are characterised by constant and rapid shrinking of their edges resulting from landslides which occur in autumn and winter as a consequence of intense rainstorms. Selected measurement stations indicate an erosion rate value range from 5 to 7.5 cm/y. The comparison between 1976 and 1994 digital elevation models (DEM), obtained from photogrammetric restitution, indicated a mean erosion rate of about 5 cm/y in a nineteen year period. This value, considerably higher than the values measured in other Italian basins, indicate a very rapid evolution of the slopes, due mainly to small earth flows inside calanchi badlands.

BAYU/UNDAN GAS-CONDENSATE DISCOVERY: WESTERN TIMOR GAP ZONE OF COOPERATION, AREA A.

The Bayu/Undan Gas-Condensate Field straddles the boundary between the ZOCA 91-12 and ZOCA 91-13 PSC areas, within the Timor Gap Zone of Cooperation Area A (ZOCA). The field is located approximately 450 km north­west of Darwin, NT, and 350 km east-southeast of Kupang, Timor. The closure is the culmination of the Flamingo High, a major structural element within the northern Bonaparte Basin. This structure has been viewed as having significant hydrocarbon potential since Flamingo-1 recovered gas from Berriasian sandstones in 1971.The discovery well, Bayu-1, was drilled by the ZOCA 91-13 contract operator, Phillips Petroleum Company ZOC, in early 1995. Bayu-1 intersected a gross 155m gas-condensate column within Middle Jurassic sandstones at a depth of 2,954.5 mSS. The ZOCA 91-12 joint venture then drilled Undan-1,10 km northwest of Bayu-1, on a separate culmination within the closure defined by the Bayu-1 gas-water contact. Undan-1 and subsequent wells have confirmed the existence of one large gas-conden­sate field, with a most likely areal extent of over 160 km2.The sandstone reservoir consists of late Oxfordian to Callovian shallow marine, deltaic to shoreface, coarsen­ing upward parasequences, overlying Callovian to Bajocian marginal marine to coastal plain sediments. The trap is an east-west oriented horst block bounded by en-echelon normal faults to the north and south, with dip closure to the east and west. Seal is provided by Tithonian to Barremian marine claystones. A likely hydrocarbon source is contained within the Barremian to Callovian interval, some of which are mature for condensate and wet gas expulsion in the southern Sahul Syncline and Malita Graben.

EdmontoniaSp., The First Record of an Ankylosaur from Alaska

(1995). Edmontonia Sp., The First Record of an Ankylosaur from Alaska. Journal of Vertebrate Paleontology: Vol. 15, No. 1, pp. 195-200.

Toarcian source rock potential in the North Celtic Sea Basin, offshore Ireland

Abstract Conditions favourable to the development and preservation of rich oil-prone source rocks are demonstrated for the uppermost Lower Jurassic stage, the Toarcian, in the Irish Sector of the North Celtic Sea Basin (and adjacent South Celtic Sea Basin), located offshore to the south of Ireland. An integrated approach, involving geological and geochemical data and techniques, has permitted the quantification of source rock potential. Wireline log responses in conjunction with existing geochemical analyses have defined net thickness, quality and richness for potential source beds. Up to 450 ft of very good to rich source rocks, capable of generating liquid hydrocarbons, are calculated for marine claystones of Early and Middle-Late Toarcian age. The thickest and best quality source rocks are predicted to occur in Toarcian depocentres, mostly situated along the axis of the North Celtic Sea Basin. One-dimensional burial history modelling suggests that substantial quantities of hydrocarbons were expelled from basinal areas towards the end of the Cretaceous.

TECTONIC SETTING, STRATIGRAPHY AND HYDROCARBON POTENTIAL OF THE BEDOUT SUB-BASIN, NORTH WEST SHELF

The tectonic and depositional histories of the Bedout Sub-basin are closely related to more widely explored areas of the southern North West Shelf, i.e. the Barrow and Dampier Sub-basins. The Mesozoic Bedout Sub-basin onlaps and overlies the Palaeozoic offshore Canning Basin sequence. Four distinct tectonic regimes characterised the Triassic, Early to Late Jurassic, Late Jurassic to Late Cretaceous, and Tertiary to present:During the Triassic, the Bedout Sub-basin was part of a broad intracratonic downwarp that also encompassed the Barrow, Dampier and Beagle Sub-basins. A thick sequence of Locker Shale and Upper and Lower Keraudren Formations (Mungaroo Formation equivalent) was deposited.During the Jurassic rifting phase, the Bedout Sub-basin was a subsiding rim basin, landward of the uplifted rift margin. Sedimentation was dominated by a thick sequence of fluviodeltaic to marginal marine deposits.In the post-break-up phase from the Callovian to latest Cretaceous, a transgressive regime resulted in deep open marine conditions with widespread claystone and minor carbonate deposition over the southern North West Shelf.Through the Tertiary to the present, shallow shelf conditions prevailed and sedimentation was dominated by a thick prograding carbonate wedge.Hydrocarbon source is provided by a thick sequence of Triassic Locker Shale and Lower Keraudren Formation. The Locker Shale is presently mature for hydrocarbon generation over most of the Bedout Sub-basin and has the potential to generate both oil and gas. The Lower Keraudren Formation is a mature source mainly for gas/condensate in deeper sections of the sub-basin. Jurassic marine claystones, which represent a prolific source in the Barrow and Dampier Sub-basins, are not present in the Bedout Sub-basin.Reservoir rocks exist in the Triassic and Jurassic sections. However, gentle Jurassic rim basin tectonic activity has resulted in minor faulting compared to the adjacent rift. This has limited migration pathways from Triassic source to Jurassic reservoirs. The primary reservoir objectives are sandstones of the Triassic Upper and Lower Keraudren Formations.Although large structural traps are uncommon, there is considerable potential to host large hydrocarbon accumulations in stratigraphic traps. A giant prospect involving the onlap of the Triassic sequence has been identified in the eastern Bedout Sub-basin. Pursuit of this play should accelerate exploration in this sparsely drilled area.

Case Study of Two Horizontal Wells for Improved Oil Recovery in New Zealand

Summary Two horizontal wells were drilled in the McKee reservoir to improve oilrecovery by repressing the coning problem experienced in conventional wells. Steps taken to facilitate an optimum completion in the geologically complexreservoir included petrophysical logging to identify fractured zones, cementingthe liner to provide isolation, and selective perforating. Disappointing earlygas breakthrough resulted in lower-than-expected oil recoveries. Introduction Today the application and drilling of horizontal wells is common. Because ofreduced costs and risks associated with horizontal drilling, hundreds of thesewells have been drilled successfully all over the world. The main benefits ofhorizontal wells, increased productivity and improved sweep efficiency, havebeen realized in many oil fields. Petrocorp Exploration Ltd. investigated thepossibility of drilling horizontal wells in the northern area of the McKeefield, which is characterized by a large gas cap overlying a thin oil column. Conventional wells in this area are plagued by high-GOR production and low oilrecovery. production and low oil recovery. This paper discusses the reservoirengineering aspects of the two horizontal wells drilled in the McKee field:justification and expectation,drilling and completion method, andperformance and production results. performance and production results. Field History The McKee field is located onshore Taranaki, New Zealand, some 20 miles eastof New Plymouth. The field is wholly owned and operated by Petrocorp. The fieldwas discovered in Sept. 1979 by the exploration Well McKee-1, and commercialproduction began in Oct. 1981. During 1980–89, the McKee field was developedwith 21 conventional wells from 11 surface locations producing to a centralproduction station. Before production started on the first horizontal well(Jan. 1990), the McKee field produced 10,600 BOPD and 9.0 MMscf/D gas, with a 5% water cut. Individual wells produced at rates from 200 to 1,450 BOPD. Allwells are completed in a single zone with sets of perforations spaced withblank sections to allow possible selective perforations spaced with blanksections to allow possible selective plugging of zones at later dates. pluggingof zones at later dates. In all wells, 2 7/8 -in. tubing has been used withsidepocket mandrels installed in case gas lift valves are needed later forartificial lift. All wells are still producing under natural flow. McKee Field Description The McKee field has two separate gas caps and a common water/oil contact(WOC). The gas/oil contact (GOC) is lower in the northern part of the fieldthan in the south. This results in an oil column part of the field than in thesouth. This results in an oil column in the north that is only 190 ft thick, whereas in the south and central areas, the oil column is 761 ft thick. Thedifferent GOC's arise from a saddle. The WOC was established at 7,100 ft truevertical depth subsea (TVDSS). The oil initially in place is estimated to havebeen some 106 MMSTB, and the gas initially in place is estimated at 183 Bscf. The accumulation occurs in the sandstone McKee formation around 6,562 ft belowsea level in one of several overthrust structures found in the Upper Eocene/Oligocene marginal marine sediments of eastern onshore Taranaki. Itbelongs to the Kapuni group and represents the last of a series of coastaltransgressions. The reservoir is sealed by the overlying marine claystone ofthe Turi formation and by the overthrust fault that juxtaposes the reservoirwith the Miocene marine claystone of the Mohakatino and Mahoenui formations. The McKee sand is, on average, some 230 ft thick. Although it has a homogeneousappearance superficially, it is heterogeneous on a larger scale. Thisheterogeneity results from the presence of subtle variations in grain size, thin calcareous-cemented beds, small-scale healed faults and fractures, andindistinct sedimentary structures. Reservoir quality suffers from significantdegradation of primary reservoir properties resulting from diageneticprocesses. processes. In the northern half of the field, the sand isinterbedded with a band of shales and thin coal beds that gradually thickentoward the north. This feature, known as the Intra McKee shale. divides the McKee formation into Sands A and B. Sand B averages 39 ft thick and is, onaverage, of poorer quality than Sand A. Most effective permeabilities to oilmeasured from well tests range from 15 to 20 md.

DEPOSITIONAL HISTORY AND FACIES ANALYSIS OF THE UPPER JURASSIC SEDIMENTS IN THE EASTERN BARROW SUB-BASIN

Callovian to Tithonian syn-rift sediments in the eastern Barrow Sub-basin can be subdivided into five depositional sequences, each separated by regionally correlatable unconformities. Sequence boundary development can be closely related to periods of major changes in basin configuration associated with the sequential breakup of eastern Gondwanaland. Synchronism of major faulting with sequence boundary development during the early and late Callovian, mid Kimmeridgian, and mid Tithonian times supports tectonism being a dominant control on the development of Type 1 unconformities in the eastern Barrow Sub-basin.Upper Jurassic depositional sequences in the eastern Barrow Sub-basin, whether of tectonic or eustatic origin, consist primarily of lowstand systems tracts comprised, wholly or in part, of detached basin floor fan complexes, channelised and canyon-fed fan systems, slump deposits, outer shelf to slope deposits, and deep marine claystones. Inner shelf to shoreface sediments of the transgressive and highstand systems tracts are absent due to episodic, post-depositional uplift and erosion along the Peedamullah Shelf and Flinders Fault System during the Late Jurassic. The periods of uplift and erosion provided much of the sediment redeposited in basinal areas during lowstand times.Depositional models based on regional sequence stratigraphic studies can be integrated with local seismic stratigraphy to provide a mechanism for estimating likely reservoir quality, once controls on sedimentation (namely tectonics, eustasy, and sediment supply) are understood. This is demonstrated by the recognition of at least seven sandstone facies within the Upper Jurassic sedimentary section. Each sandstone has particular characteristics which can be related to the depositional setting. Reservoir quality is best developed in dominantly medium grained, moderate to well sorted sandstones, deposited as detached, basin floor submarine fan sands or interbedded turbidites. In contrast, reservoir quality is poorly developed in the remaining sand-prone facies deposited as slope fans, slumps, or distal turbidites.

Petroleum source-rock potentials of the cretaceous transgressive-regressive sedimentary sequences of the Cauvery Basin

The present work is an attempt to contribute to knowledge on the petroleum source-rock potentials of the marine claystones and shales of basins associated with passive continental margins where the source-rock developments are known to have been associated with the anoxic events in the Mesozoic era. Data on three key exploratory wells from three major depressions Ariyallur-Pondicherry, Thanjavur and Nagapattinam of the Cauvery Basin are described and discussed. The average total organic carbon contents of the transgressive Pre-Albian-Cinomanian and Coniacian/Santonian claystones/shales range from 1.44 and 1.16%, respectively. The transgressive/regressive Campanian/Maastrichtian claystones contain average total organic carbon varying from 0.62 to 1.19%. The kerogens in all the studied stratigraphic sequences are classified as type-III with Rock-Eval hydrogen indices varying from 30 to 275. The nearness of land masses to the depositional basin and the mainly clastic sedimentation resulted in accumulation and preservation of dominantly type-III kerogens. The Pre-Albian to Cinomanian sequences of peak transgressive zone deposited in deep marine environments have kerogens with a relatively greater proportion of type-II components with likely greater contribution of planktonic organic matters. The global anoxic event associated with the Albian-Cinomanian marine transgression, like in many other parts of the world, has pervaded the Cauvery Basin and favoured development of good source-rocks with type-III kerogens. The Coniacian-Campanian-Maastrichtian transgressive/regressive phase is identified to be relatively of lesser significance for development of good quality source-rocks.

Petroleum Source Rock Potential of Mesozoic Condensed Section Deposits in Southwestern Alabama

Because condensed section deposits in carbonates and siliclastics are generally fine-grained lithologies often containing relatively high concentrations of organic matter, these sediments have the potential to be petroleum source rocks if buried under conditions favorable for hydrocarbon generation. In the Mesozoic deposits of southwestern Alabama, only the Upper Jurassic Smackover carbonate mudstones of the condensed section of the LZAGC-4.1 cycle have realized their potential as hydrocarbon source rocks. These carbonate mudstones contain organic carbon concentrations of algal and amorphous kerogen of up to 1.7% and have thermal alteration indices of 2- to 3+. The Upper Cretaceous Tuscaloosa marine claystones of the condensed section of the UZAGC-2.5 cycle are rich (up to 2.9%) in herbaceous and amorphous organic matter but have not been subjected to burial conditions favorable for hydrocarbon generation. The Jurassic Pine Hill/Norphlet black shales of the condensed section of the LZAGC-3.1 cycle and the Upper Jurassic Haynesville carbonate mudstones of the condensed section of the LZAGC-4.2 cycle are low (0.1%) in organic carbon. Although condensed sections within depositional sequences should have the highest source rock potential, specific environmental, preservational, and/or burial history conditions within a particular basin will dictate whether or not the potential is realized as evidencedmore » by the condensed sections of the Mesozoic depositional sequences in southwestern Alabama. Therefore, petroleum geologists can use sequence stratigraphy to identify potential source rocks; however, only through geochemical analyses can the quality of these potential source rocks be determined.« less

Petroleum geology of the Niger Delta

Abstract The Niger Delta is one of the World’s largest Tertiary delta systems and an extremely prolific hydrocarbon province. It is situated on the West African continental margin at the apex of the Gulf of Guinea, which formed the site of a triple junction during continental break-up in the Cretaceous. Throughout its history, the delta has been fed by the Niger, Benue and Cross rivers, which between them drain more than 10 6 km 2 of continental lowland savannah. Its present morphology is that of a wave-dominated delta, with a smoothly seaward-convex coastline traversed by distributary channels. From apex to coast the subaerial portion stretches more than 300 km, covering an area of 75 000 km 2 . Below the Gulf of Guinea, two enormous lobes protrude a further 250 km into deeper waters. The delta sequence comprises an upward-coarsening regressive association of Tertiary clastics up to 12 km thick. It is informally divided into three gross lithofacies: (i) marine claystones and shales of unknown thickness, at the base; (ii) alternations of sandstones, silstones and claystones, in which the sand percentage increases upwards; (iii) alluvial sands, at the top. Delta structure and stratigraphy are intimately related, the development of each being dependant on the interplay between sediment supply and subsidence rates. The dominant subsurface structures are syn- and post- sedimentary listric normal faults which affect the main delta sequence. They die out upwards into the alluvial sands and sole out at depth near the top of the marine claystones. Major growth-fault trends cross the delta from northwest to southeast, dividing it into a number of structural and stratigraphic belts, called depobelts, which become younger towards the south. The deltaic sequence in each of these depobelts is distinct in age, so that they actually represent successive phases in the delta’s history. Hydrocarbons have been located in all of the depobelts of the Niger Delta, in good quality sandstone reservoirs belonging to the main deltaic sequence (the ‘paralic sequence’ of common usage). Most of the larger accumulations occur in roll-over anticlines in the hanging-walls of growth faults, where they may be trapped in either dip or fault closures. In the 30 or 50 years since the first discoveries were made, approximately 4 × 10 9 m 3 of oil and an unestablished, but very substantial quantity of associated and unassociated gas have been discovered. Most fields are small, ranging up to 50 × 10 6 m 3 , though several larger fields contain recoverable reserves in excess of 80 × 10 6 m 3 . The hydrocarbons are found in multiple pay sands with relatively short columns, and adjacent fault blocks usually have independent accumulations.