Deepwater Hydrocarbon Exploration Research Articles

Petrophysical characterization of the Late-Cretaceous Logbaba Formation in the Kribi/Campo sub-basin, Cameroon: Implication on deep-water hydrocarbon exploration

Deep-water hydrocarbon exploration in the Kribi/Campo sub-basin offshore Cameroon is targeting the promising Campanian-Maastrichtian turbidite reservoirs. However, a detailed understanding of the petrophysical properties of these Upper Cretaceous reservoirs is not well documented. In this study, well logs from two boreholes W1 and W2 located in the southern part of the sub-basin provide a unique opportunity to assess the reservoir quality of the Upper Cretaceous Logbaba Formation. Four potential reservoir intervals with thickness ranging between 27 and 105.7 m were delineated in W1, compared with two intervals in W2 with thickness ranging between 72.2 and 93.6 m. Lithological analysis of these reservoir intervals indicates a heterogeneous reservoir matrix consisting of sand, limestone, and dolomite. These reservoir intervals are interpreted as turbidite sand deposits with a clay content ranging from 6.3 to 19.8%, porosity ranging from 15.5 to 21.3%, permeability ranging between 5.65 and 75.09 mD and a water saturation of 34.5–74.2%. Fluid free index, reservoir quality index, and flow zone indicator are insignificant and suggest reservoirs with poor transmissibility. These analyses reflects good petrophysical characteristics for the sandstones of Logbaba Formation. However, both wells were water-bearing with non-mobile hydrocarbon residuals and did not contain commercial quantities of hydrocarbons. There is no evidence of hydrocarbon migration in either reservoir, suggesting that the source rock and the hydrocarbon migration pathways are the main risk factors and reason for the failure of the wells. The findings from this study extend the understanding of the reservoir characteristics of the Upper Cretaceous Logbaba Formation, which will further enhance hydrocarbon prospectivity offshore Cameroon. Since these reservoirs are water-laden, they may serve as potential offshore saline aquifers for geological storage of CO2 offshore Cameroon.

Structural characteristics and deep-water hydrocarbon accumulation model of the Scotian Basin, Eastern Canada

Commercial hydrocarbon reservoirs have been discovered in shallow-water areas of the Scotian Basin, Eastern Canada. However, knowledge about the structure and hydrocarbon accumulation characteristics of the basin is still insufficient, which constrains the oil and gas exploration in deep-water areas. Based on comprehensive data of magnetic anomalies, seismic survey, and drilling, this study determines the structure characteristics of the Scotian Basin and its hydrocarbon accumulation conditions in deep waters and evaluates the deep-water hydrocarbon exploration potential. The transform faults and basement structures in the northern basin control the sedimentary framework showing thick strata in east and thin strata in west of the basin. The bowl-shaped depression formed by thermal subsidence during the transitional phase and the confined environment (micro basins) caused by salt tectonics provide favorable conditions for the development of source rocks during the depression stage (also referred to as the depression period sequence) of the basin. The progradation of large shelf-margin deltas during the drift phase and steep continental slope provide favorable conditions for the deposition of slope-floor fans on continental margins of the basin. Moreover, the source-reservoir assemblage comprising the source rocks within the depression stage and the turbidite sandstones on the continental margin in the deep waters may form large deep-water turbidite sandstone reservoirs. This study will provide a valuable reference for the deep-water hydrocarbon exploration in the Scotian Basin.

Differences of sedimentary triggers and depositional architecture of lacustrine turbidites from normal regression to forced regression: Eocene Dongying depression, Bohai Bay Basin, East China

Sedimentary processes of marine turbidite systems under sea-level changes have been the focus of deep-water sedimentology. Compared with well-studied marine basins, the products of deep-water sediment gravity flows responding to lake-level changes in closed lacustrine basins are still poorly understood. In this study, we integrate cores of 10 exploratory wells, logs of 280 development wells, 3D seismic data and geochemical elements from the Eocene Dongying Depression, Bohai Bay Basin, East China to investigate sedimentary mechanisms and depositional architecture of lacustrine turbidite systems under lake-level changes. The studied strata are divided into three parasequence sets (PSS4 ~ PSS2), corresponding to early highstand normal regression with ascending trajectories, late highstand normal regression with flat trajectories, and forced regression with descending trajectories, respectively. From early highstand normal regression to forced regression, the ratios of Fe/Mn and U/Th reveal that the humid climate shifted to the arid climate. More lithofacies clues indicate that turbidites in highstand normal regression were triggered by river floods, whereas counterparts in forced regression were related to sediment failures. There are different architectural features of turbidite systems in three regression stages. PSS4 developed a series of channel belts within which individual channel elements are aggraded vertically. PSS3 is composed of a channelized lobe formed by individual distributary channels migrating laterally. PSS2 is characterized by a suite of compensational stacking debrite tongues. Climate forcing is a crucial factor controlling depositional architecture of the turbidite systems. A relatively humid climate during highstand normal regression led to rising lake-level and frequent floods, which are conducive to the formation of hyperpycnal-fed channel-lobe systems. Nevertheless, during forced regression under an arid climate, the strong progradational clinothems were prone to failure and sediment remobilization, resulting in debrite tongue complexes. This study highlights depositional differences of lacustrine turbidites during regression stages under the control of climate. Meanwhile, it also provides a new predictive model for deep-water hydrocarbon exploration and production in lacustrine basins worldwide.

Genesis and evolution of large-scale sediment waves in submarine canyons since the Penultimate Glacial Maximum (ca. 140 ka), northern South China Sea margin

Sediment waves are common on the seafloor, but large-scale ones developed in submarine canyons are rarely reported. In this study, we document for the first time the Quaternary deep-water canyon-confined large-scale sediment waves developed on the northern South China Sea margin based on the analysis of a high-quality 3-D seismic reflection volume combined with a 2-D multichannel seismic reflection profile and three wells. Results show that the onset of these canyon-confined large-scale sediment waves can be dated back to the Penultimate Glacial Maximum (PGM)(ca.140 ka). This was the last period for the Pearl River Delta to prograde over the shelf edge. And these sediment waves have continued to develop and migrate upslope until present. The large-scale sediment waves pertaining to the PGM have a dominant down-slope asymmetrical 2-D morphology with wavelengths of 1.059–6.090 km and wave heights of 3.3–32.5 m. The present large-scale sediment waves show an up-slope asymmetrical 2-D morphology with dimensions of 0.667–5.628 km wavelength and 2.7–14.0 m wave height, which are smaller relative to those at the PGM. Grain sizes of the sediment waves at the PGM and present are interpreted to be coarse, inferred from seismic reflection data by high amplitude reflections (HARs). After a comprehensive analysis of the types of sediment-laden flows, the sediment provenances, the seafloor topography and the features of the sediment waves, these large-scale sediment waves might be interpreted as cyclic steps generated by the down-slope flowing supercritical turbidity currents and associated internal hydraulic jumps along high gradient (approximately greater than 1.28°) canyon thalwegs characterized by numerous slope breaks. The evolution of the large-scale sediment waves from partially depositional at the PGM to erosion-dominated at the present is controlled by variations of the sediment supply and the submarine slope accommodation along the canyon thalweg, which is manifested in the co-evolution of the sediment waves with the canyon. The findings of this study tell us that in addition to axial channels and mass-transport complexes, large-scale sediment waves can also develop on the canyon floor, which helps to improve our understanding of the complex canyon processes. The ‘large-scale sediment waves’ described here may be a new potential deepwater-reservoir element for the deep-water hydrocarbon exploration associated with submarine canyons.

Integrated characterization and failure mechanism for a mid-Pleistocene mass transport complex-dominant interval in the Mars Ursa Basin, northern Gulf of Mexico, USA

The economic and operational risks associated with mass transport complexes (MTCs) in deepwater hydrocarbon exploration act as a principal motivation to investigate their depositional elements using industry data. There is a lack of extensive seismic and well data coverage that limits the understanding of the processes associated with the evolution of MTCs within deepwater sedimentary basins. This study leverages a unique integrated data set to evaluate the depositional character and potential failure mechanisms of seven identified MTCs preserved in a synkinematic mid-Pleistocene MTC-dominant interval that spans the hydrocarbon-bearing Mars Ursa Basin in the northern Gulf of Mexico. Through seismic interpretation and attribute extraction methods using a 3D prestack depthmigrated seismic survey, we have determined the kinematic indicators and preserved the morphodomain geometries of the identified MTCs. The MTC-dominant interval covers an area of 631 km2, a volume of 392 km3, and a maximum thickness of 549 m in minibasin centers. The interval is penetrated by 15 boreholes that provide stratigraphic and lithologic calibration of the morphometric analyses. The lithologic composition of the MTC-rich interval is claystone/mudstone-dominant with a few interbedded, thin sandstones. The identified kinematic indicators and geometric extent of the identified MTCs are a function of the local salt tectonics extrabasinal controls. The stratigraphic framework presented in this study constrains the timing of failures to a period of high sediment deposition related to a major increase of glacial input into the Quaternary Mississippi Fan. This study offers borehole-calibrated MTC morphometrics preserved in an MTC-dominant interval whose failure is triggered by local salt inflation, but ultimately it is a consequence of loading following increased sediment supply into the basin. The results from this robust data set build upon past integrated seismic-well studies that strive to improve the understanding of MTC processes and their implications in hydrocarbon exploration across salt sedimentary basins.

Along-strike Quaternary morphological variation of the Baiyun Sag, South China Sea: The interplay between deltas, pre-existing morphology, and oceanographic processes

Continental margins usually display along-strike morphological variation, with diverse underlying controls around the world. Based on 3D seismic data from the Baiyun Sag, northern South China Sea, this work provides a new case study to understand the combined controls on along-strike morphological variation over short strike distances. The northern slope of the Baiyun sag was characterized by a gently dipping ramp at the beginning of the Quaternary, and the Quaternary along-strike morphological variation in this area is mainly displayed in the deltas, submarine canyons and contourite depositional system. The deltas were featured by lobate form and mainly distributed at the western area, with shoreline parallel and oblique to the ramp strike in the west and east, respectively. The scales of the deltas and the associated submarine canyons decreased towards the east. The eastern plastered contourite drifts have a greater areal extent than those in the west, and the former are terraced. The Quaternary slope evolution took place in three stages (stage 1–3), of which the time intervals are ca. 2.6 - ca. 1.6 Ma, ca. 1.6 - ca. 0.14 Ma and ca. 0.14–0 Ma, respectively. The slope was characterized by a gentle ramp, deltas and contourites from stage 1–3 respectively.The along-strike morphological variation of the northern slope of the Baiyun Sag was predominantly influenced by the interplays between the deltas, pre-existing morphology, and oceanographic regimes. The localization of the lobate-form deltas with respect to the pre-existing submarine canyons on the ramp exerted a great influence on the along-strike variation of these canyons within stage 2. The interplay between the delta morphology (i.e., delta position and delta-front gradients) and the oceanographic regimes (i.e. contour currents and internal waves) controlled the along-strike variation in contourite processes during the stage 3. This study provides a new insight into the combination of controls responsible for along-strike morphological variation of post-rift continental margins evolving from a ramp. The underlying depositional processes revealed by this study would be helpful for understanding the lateral variability of sequence architectures and the deep-water sands deposition, which are important basis for guiding future deep-water hydrocarbon exploration on such continental margins elsewhere.

Deep-water channels in the lower Congo basin: Evolution of the geomorphology and depositional environment during the Miocene

Abstract Deep-water channel systems are an important component of the “source to sink” system from continental slope to deep-sea basin. They are also the critical reservoir type in deep-water hydrocarbon exploration. The study of geomorphology evolution, filling processes and controlling factors of the Miocene deep-water channel in the Lower Congo Basin is conducive to deepening our understanding of basin dynamics, and to improving the prediction accuracy of deep-water reservoirs. Based on 3D seismic data, cores, thin sections, well logging data, we study the Miocene seismic stratigraphic characteristics, deep-water sedimentary units, lithofacies and channel types. Using the techniques and means of seismic geomorphology, we discuss the occurrence, development, recession and extinction processes of channel complexes and controlling factors. The Miocene was divided into seven 3rd-order sequences. Each 3rd-order sequence is subdivided into two (lower/upper) seismic stratigraphy units, with initial flooding surface (FS) as the separated boundary. The seismic characteristics of the lower/upper unit suggest the occurrence of alternating turbidite/hemipelagic sedimentary units. Seismic units such as erosional surface, filling channel, levee, lobe, MTD and background slope deposits are described. Fifteen deep-water lithofacies are identified and they are determined to be composed of clay, silt, fine-coarse sand, gravel, and conglomerate. The deep-water channels in the study area are interpreted four types: single-stage erosional channel, single-stage aggradational channel, vertical aggradational channel complexes and lateral migration channel complexes. The different types of channel are the results of interaction of flow energy and accommodation space. On this basis, we propose that tectonic uplift is the driving force for the formation of the deep-water sandy channel system, and that high frequency sea-level fluctuation in West Africa controls the development of third-order sequences and restricts the scale of the deep-water sandstone accumulation. In addition, the avulsion processes controlled by climate variations are the main factors to influence channel complex filling process.

Deepwater reservoir prediction using broadband seismic-driven impedance inversion and seismic sedimentology in the South China Sea

In recent years, many important discoveries have been made in the marine deepwater hydrocarbon exploration in the South China Sea, which indicates the huge exploration potential of this area. However, the seismic prediction of deepwater reservoirs is very challenging because of the complex sedimentation, the ghost problem, and the low exploration level with sparse wells in deepwater areas. Conventional impedance inversion methods interpolate the low frequencies from well-log data with the constraints of interpreted horizons to fill in the frequency gap between the seismic velocity and seismic data and thereby recover the absolute impedance values that may be inaccurate and cause biased inversion results if wells are sparse and geology is complex. The variable-depth streamer seismic data contain the missing low frequencies and provide a new opportunity to remove the need to estimate the low-frequency components from well-log data. Therefore, we first developed a broadband seismic-driven impedance inversion approach using the seismic velocity as initial low-frequency model based on the Bayesian framework. The synthetic data example demonstrates that our broadband impedance inversion approach is of high resolution and it can automatically balance between the inversion resolution and stability. Then, we perform seismic sedimentology stratal slices on the broadband seismic data to analyze the depositional evolution history of the deepwater reservoirs. Finally, we combine the broadband amplitude stratal slices with the impedance inversion results to comprehensively predict the distribution of deepwater reservoirs. Real data application results in the South China Sea verify the feasibility and effectiveness of our method, which can provide a guidance for the future deepwater hydrocarbon exploration in this area.

SEISMIC FACIES ANALYSIS AND STRUCTURAL INTERPRETATION OF DEEPWATER NW SABAH

The deepwaters of NW Sabah has been an interesting site for deepwater hydrocarbon exploration in Malaysia. Up to now, the exploration in this is mainly focused to the Late Miocene until the Pliocene siliciclastic sediment reservoirs distribution at the shelf edge. This paper shows a gross seismic facies mapping analysis and structural interpretation of regional deepwater NW Sabah especially at Sabah Trough. To convert depth, all seismic lines were picked and tied with selected wells. The results of the interpretation were then summarized and presented with relation to regional tectonic events. Eight seismic stratigraphic units, six seismic facies together with five sequence boundaries were recognized. Multichannel reflection 2D seismic data, gamma ray logs and biostratigraphy description from the three wells at deepwater fold-thrust belt and published tectono-stratigraphic scheme from Dangerous Grounds (Sabah Platform) in South China Sea were selected in this study. The propose of this study is to document the relevance of regional tectonic event between Dangerous Ground and Sabah Trough.

Late Miocene Red River submarine fan, northwestern South China Sea

A huge submarine fan is discovered through the research of the seismic and borehole data in the binding site of Yinggehai basin and Qiongdongnan basin in northwestern South China Sea. The fan, mainly formed during Late Miocene (Huangliu period) has an area over 10000 km2 and maximum thickness of over 2000 m. It is characterized by a wedge-shaped oblique progradation configuration on the dip profile and a hummocky bidirectional progradation configuration on the strike profile. The core and Logging data from the well YC35-1-2 located in the front side of the fan indicate that sandy gravity flow deposits are predominant in lower Huangliu Formation and change to interbeds of sand and mud in upper Huangliu Formation. The fan is interpreted as a sand/mud-rich submarine fan in combination with the bathyal geological background of Huangliu period. A preliminary analysis of provenance indicates that neither the Guiren Uplift in the west nor the Hainan Uplift in the north can serve as the major provenance for the submarine fan. The provenance is considered to be from the Red River, based on the sedimentary facies study of the Huangliu Formation in Yinggehai basin. The fan is thus named as “Red River submarine fan”. The Red River depositional system consists of the Red River submarine fan, the Red River delta, and associated submarine canyons. The discovery of the Red River submarine fan provides important information for the research of the uplift of Tibetan Plateau and the evolvement of Red River Fault Zone. Furthermore, it also points out a new direction for the deepwater hydrocarbon exploration in the northern South China Sea.

Regional structure and tectonic history of the obliquely colliding Columbus foreland basin, offshore Trinidad and Venezuela

Cenozoic eastward migration of the Caribbean plate relative to the South American plate is recorded by an 1100-km-long Venezuela-Trinidad foreland basin which is oldest in western Venezuela (65–55 Ma), of intermediate age in eastern Venezuela (34–20 Ma) and youngest beneath the shelf and slope area of eastern offshore Trinidad (submarine Columbus basin, 15.0 Ma-Recent). In this study of the regional structure, fault families, and chronology of faulting and tectonic events affecting the hydrocarbon-rich Columbus foreland basin of eastern offshore Trinidad, we have integrated approximately 775 km of deep-penetration 2D seismic lines acquired by the 2004 Broadband Ocean-Land Investigations of Venezuela and the Antilles arc Region (BOLIVAR) survey, 325 km of vintage GULFREX seismic data collected by Gulf Oil Company in 1974, and published industry well data that can be tied to some of the seismic reflection lines. Top Cretaceous depth structure maps in the Columbus basin made from integration of all available seismic and well data define for the first time the elongate subsurface geometry of the 11–15 km thick and highly asymmetrical middle Miocene-Recent depocenter of the Columbus basin. The main depocenter located 150–200 km east of Trinidad and now the object of deepwater hydrocarbon exploration is completely filled by shelf and deepwater sediments derived mainly from the Orinoco delta. The submarine Darien ridge exhibits moderate (20–140 m) seafloor relief, forms the steep (12°–24°), northern structural boundary of the Columbus basin, and is known from industry wells to be composed of 0.5–4.5 km thick, folded and thrust-imbricated, hydrocarbon-bearing section of Cretaceous and early Tertiary limestones and clastic rocks. The eastern and southern boundaries of the basin are formed by the gently (1.7°–4.5°), northward-dipping Cretaceous–Paleogene passive margin of South America that is in turn underlain by Precambrian rocks of the Guyana shield. Interpretation of seismic sections tied to wells reveals the following fault chronology: (1) middle Miocene thrusting along the Darien ridge related to highly oblique convergence between the Caribbean plate and the passive margin of northern South America; continuing thrusting and transpression in an oblique foreland basin setting through the early Pleistocene; (2) early Pliocene-recent low-angle normal faults along the top of the Cretaceous passive margin; these faults were triggered by oversteepening related to formation of the downdip, structurally and bathymetrically deeper, and more seaward Columbus basin; large transfer faults with dominantly strike-slip displacements connect gravity-driven normal faults that cluster near the modern shelf-slope break and trend in the downslope direction; to the south no normal faults are present because the top Cretaceous horizon has not been oversteepened as it is adjacent to the foreland basin; (3) early Pliocene–Recent strike-slip faults parallel the trend of the Darien ridge and accommodate present-day plate motions.

Seismic characteristics of a reef carbonate reservoir and implications for hydrocarbon exploration in deepwater of the Qiongdongnan Basin, northern South China Sea

Our analysis of approximately 40,000 km of multichannel 2-D seismic data, reef oil-field seismic data, and data from several boreholes led to the identification of two areas of reef carbonate reservoirs in deepwater areas (water depth ≥ 500 m) of the Qiongdongnan Basin (QDNB), northern South China Sea. High-resolution sequence stratigraphic analysis revealed that the transgressive and highstand system tracts of the mid-Miocene Meishan Formation in the Beijiao and Ledong–Lingshui Depressions developed reef carbonates. The seismic features of the reef carbonates in these two areas include chaotic bedding, intermittent internal reflections, chaotic or blank reflections, mounded reflections, and apparent amplitude anomalies, similar to the seismic characteristics of the LH11-1 reef reservoir in the Dongsha Uplift and Island Reef of the Salawati Basin, Indonesia, which house large oil fields. The impedance values of reefs in the Beijiao and Ledong–Lingshui Depressions are 8000–9000 g/cc × m/s. Impedance sections reveal that the impedance of the LH11-1 reef reservoir in the northern South China Sea is 8000–10000 g/cc × m/s, whereas that of pure limestone in BD23-1-1 is >10000 g/cc × m/s. The mid-Miocene paleogeography of the Beijiao Depression was dominated by offshore and neritic environments, with only part of the southern Beijiao uplift emergent at that time. The input of terrigenous sediments was relatively minor in this area, meaning that terrigenous source areas were insignificant in terms of the Beijiao Depression; reef carbonates were probably widely distributed throughout the depression, as with the Ledong–Lingshui Depression. The combined geological and geophysical data indicate that shelf margin atolls were well developed in the Beijiao Depression, as in the Ledong–Lingshui Depression where small-scale patch or pinnacle reefs developed. These reef carbonates are promising reservoirs, representing important targets for deepwater hydrocarbon exploration.

Direct seismic indicators of gas hydrates in the Walker Ridge and Green Canyon areas, deepwater Gulf of Mexico

During the past two decades, marine research has focused on gas hydrates because of their potential importance as a future energy source, as a geologic hazard in deepwater hydrocarbon exploration, and because they may impact climate change (McConnell and Kendall, 2003; Smith et al., 2005). Worldwide assessments indicate that gas hydrate reserves may surpass the total hydrocarbon reserves from all other known resources of fossil fuels. Consequently, gas hydrates are considered to be a potential energy source for the 21st century.

Significance of ODP results on deepwater hydrocarbon exploration – Eastern equatorial Atlantic region

Scientific ocean drilling has provided access to samples of potential hydrocarbon source rocks in a number of deepwater regions around the globe. The samples are often well constrained stratigraphically and normally free from organic drilling fluid contamination. The focus of this study is the results obtained on one of the Ocean Drilling Program’s (ODP) legs – Leg 159, which was located along the Equatorial portion of the West African margin, a region of considerable hydrocarbon exploration interest. Four drilling sites were included in Leg 159 along the continental margins of Côte d’Ivorie and Ghana. Drilling at these sites recovered sediments of Albian to Pleistocene age. Prior studies revealed the presence of a number of organic-rich zones capable of yielding significant quantities of hydrocarbons within both the Cretaceous and Tertiary sections. These intervals could act as hydrocarbon sources, if suitable maturity levels were obtained. Both oil and gas would be expected as their primary products. A shore-based study which focused on Site 959 and to a lesser degree Site 962 provided an opportunity to expand upon the original dataset and to further characterize the organic matter. Detailed characterization of the bitumen fractions from Site 959, provided not only information on the geochemical character of these specific sediments, but permitted them to be placed into a more regional context by comparing them to oils from the Equatorial portion of the West African margin. These data reveal a similarity, but not necessarily a genetic relationship, between the Cretaceous sediments and the majority of the Côte d’Ivoire oils. The Paleogene extracts display similar geochemical attributes as the deepwater oils from the Niger Delta. Although this study is not attempting to establish a definitive correlation, the data suggest a Tertiary source rock system for the deepwater Niger Delta, where deposition occurred under oxic to sub-oxic conditions. This contrasts with the Côte d’Ivoire where a Cretaceous source was effective and was deposited under sub-oxic to anoxic conditions. The absence of evidence for an effective deepwater Niger Delta Cretaceous source rock could be either a result of poor timing or the lack of migration pathways to the Miocene and younger reservoirs. The limited number of Tertiary-derived oils along the Côte d’Ivoire margin could be a result of the lack of sufficient overburden.

ABSTRACT: Massive Bed-Forms, Mega-Furrows, on the Continental Rise at the Base the Sigsbee Escarpment, Northwest Gulf of Mexico

Abstract Some of the largest deep-water sedimentary bed-forms ever found in the world oceans were recently discovered along the base of the Sigsbee Escarpment in the northwest Gulf of Mexico. Deep-Tow high-resolution geophysical surveys on the continental rise south of the Sigsbee Escarpment have revealed the existence of mega-furrows, ~10 m deep and ~30 m wide, spaced ~100 m apart that occupy an area on the Continental Rise 20 to 40 km wide. A single furrow within a field of furrows in the Green Knoll Diapir area can be traced over a distance of 150 km. The furrows are located at the base of the Sigsbee Escarpment from 90° to 93° West Longitude, from north of Green Knoll to the area just west of Bryant Canyon. The presence of furrows, longitudinal bed-forms, suggests that unidirectional bottom currents up to 100 cm/sec may exist at the base of the Escarpment. The furrows are inferred to be formed by helical secondary circulation. Allen (1968) produced sedimentary furrows in the lab and found a hierarchy of bed forms ranging from uniform furrows at low flow conditions to meandering furrows and flute casts at the highest flow conditions. All the conditions described by Allen are present in the area due south of Bryant Canyon on the continental rise. In terms of hazards relating to deepwater hydrocarbon exploration and production, the formation of mega-furrows demonstrates the existence of previously undocumented high-velocity currents at the base of the escarpment. End_of_Record - Last_Page 410-------

Seismic Amplitude Analysis: A Driver for Deep Water Hydrocarbon Exploration in the Eastern Niger Delta - Examples from the Zafiro Field Area, Equatorial Guinea: ABSTRACTS

Seismic Amplitude Analysis: A Driver for Deep Water Hydrocarbon Exploration in the Eastern Niger Delta - Examples from the Zafiro Field Area, Equatorial Guinea: ABSTRACTS

Deep-water hydrocarbon exploration in the Philippines

Deep-water drilling in the Philippines began in 1979 and ten wells were drilled over the next three years. The primary targets were Miocene reef limestones, which were found not only to be well developed in the geologic column but also to attain considerable size. Proven oil production from Miocene reefs in shelf waters off Northwest Palawan have encouraged explorationists to focus on the adjacent deep-water areas. The hydrocarbon potential of offshore areas deeper than 200 m was manifested by a commercial oil discovery and a noncommercial gas discovery in Lower Miocene turbidite sands and a gas discovery in Lower Miocene reefal limestone off Northwest Palawan. The Galoc oil discovery in a water depth of 1055 ft is scheduled for development beginning in late 1983 and oil production is programmed to start during the first quarter of 1985. The Galoc development/production scheme calls for an Early Production System (EPS) consisting of a floating production facility (FPF) and subsea well completions. Institutional incentives have been developed by the Philippine government to encourage deep-water exploration. The incentives include a longer exploration period, cross-recovery of exploration expenses, depreciation of tangible exploration costs over a five-year period, and up to two-thirds reimbursement on loan interest for financing development and production.