Offshore Indonesia Research Articles

Diagenetic features recorded in sedimentary rocks within a gas chimney: A case study from the Makassar Strait, offshore Indonesia

Methane seeps, prevalent in ocean basins globally, indicate upward methane migration from the subsurface, often evident as gas chimneys in seismic reflection data. The footprint of this methane migration is often indicated by methane-derived authigenic carbonate (MDAC), a product of anaerobic oxidation of methane (AOM). Despite extensive research on MDAC from present-day seafloors and outcrops, understanding methane migration footprints from subsurface rock samples remains limited. Therefore, this study aims to investigate methane migration footprints from subsurface rock samples taken from a proven area of gas migration. This study utilized cutting samples from well XS-01 located in the Makassar Strait, offshore Indonesia. The well was drilled through a gas chimney into Oligocene carbonate reservoirs hosting a substantial methane column (102 m). Analysis of 44 cutting samples involved petrographic examination, Scanning Electron Microscope (SEM) imaging, and X-ray Diffraction (XRD) analysis to discern mineralogical content and diagenetic features signaling the presence of gas. A diagenetic texture called clotted peloidal micrite (CPM) was discovered within foraminifera fossils and around fractures based on petrographic analysis. CPM is a type of MDAC and predominantly occurs in fine-grained, siliciclastic rocks, indicating gas migration. This migration is interpreted to occur: (i) during the early burial stages originating from microbial activity since the Oligocene (biogenic gas); (ii) following matured source rock that reached its peak maturity from the Middle Eocene to the Pliocene (thermogenic gas); or (iii) interference of these two processes. The migration route persists until present day as evidenced by gas chimney and seabed pockmarks identified in seismic reflection data. This study emphasizes the importance of subsurface rock samples, such as cuttings, in uncovering gas migration footprints. Especially, where seismic data is unavailable or could not image fluid flow features. In addition, this study also provides a new perspective on diagenesis along methane migration route, complementing most of the research that is primarily focused on reservoir diagenesis.

Extensional deformation of a shale‐dominated delta: Tarakan Basin, offshore Indonesia

AbstractDeformation on shale‐rich continental margins is commonly associated with thin‐skinned extension above mobile shales. Normal faulting and shale mobilization are widespread on such margins, being associated with and controlled by progradation and gravitational failure of deltaic sedimentary wedges. However, due to uncertainties in seismically imaging mobile shales, our understanding of problems like how base mobile‐shale controls deformation, and the shape, size, and distribution of shale structures remains poorly understood. Here, we use 3D seismic reflection data from the platform region of the Tarakan Basin, offshore eastern Indonesia to investigate the temporal and spatial evolution of thin‐skinned deformation of the Neogene sedimentary section. Our detailed seismic interpretation reveals up to 74 km long, concave‐ and convex‐into‐the‐basin normal faults, dipping both basinward (eastwards) and locally landward (westwards), which detach downwards on a basal mobile shale (Early‐Middle Miocene). The base of the mobile‐shale unit dips gently (<17°) seaward, although older (Eocene‐Early Miocene), rift‐related normal faults originate local structural highs deforming the base of mobile shales. Our isochore (thickness map) analysis shows that supra‐shale normal faulting commenced in the Middle Miocene and was accompanied by the formation of hanging‐wall rollover folds and associated crestal grabens, with the subsequent along‐ and across strike migration of the deformation related to the nucleation, lateral linkage and reactivation of individual fault systems. Updip growth normal faulting was also accompanied by the downslope flow of mobile shale, accompanied by parallel and perpendicular variations of the differential loading in the delta system, and local contraction and mobile‐shale upbuilding, resulting in the growth of large, margin‐parallel shale anticlines further downdip. The growth faults and anticlines are locally overlain by up to 5 km tall mud pipes and volcanoes. We suggest that variations in the rate of sedimentary loading, mobile‐shale flow, fault growth and gravitational failure of the delta system above a seaward‐dipping, but locally rugose base mobile‐shale surface, controlled Neogene deformation in the Tarakan Basin. We also demonstrate how variations in the trend and dip of the base mobile‐shale surface influence the position, timing of formation and evolution of supra‐shale normal faults and their associated depocentres along shale‐rich, deltaic margins.

Comparison of shale depth functions in contrasting offshore basins and sealing behaviour for CH 4 and CO 2 containment systems

Mudrock compaction trends from the Rovuma Basin offshore Mozambique are compared with those of the Norwegian North Sea, the Gulf of Mexico and the Kutai Basin offshore Indonesia. The comparison reveals that burial rates and timing of rifting are the dominant causes for the differences observed. The compaction trend for the Rovuma Basin is broadly similar to the trends for the Kutai Basin and the Gulf of Mexico, but very different from those for the Norwegian North Sea data, which show higher porosity and shallower onset of overpressure than those from the other three basins. The relationships for seismic velocities as a function of depth show strong similarities between the Rovuma and Gulf of Mexico basins. These comparisons are used to make a general assessment of the capillary sealing potential of Cretaceous mudrocks in the Rovuma Basin, using a mudstone permeability-prediction function and a method for mapping permeability to threshold pressure, allowing estimation of maximum column heights for CO 2 and CH 4 , with uncertainty ranges. Predicted CO 2 column heights are slightly less than the equivalent CH 4 column heights. The observed CH 4 column height at one of the wells is significantly lower than that predicted from mudstone permeability, which is probably due to other factors such as fracturing or gas migration out of the structure. The comparison indicates generally good capillary sealing potential for the Rovuma Basin Cretaceous shales and offers a general approach for assessing CO 2 storage potential from hydrocarbon sealing datasets from multiple offshore basins. This article is part of the Energy Geoscience Series available at https://www.lyellcollection.org/cc/energy-geoscience-series

E&P Notes (March 2022)

E&P Notes (March 2022)

Architectural Diversity of Submarine Lobate Deposits

Lobate deposits in deep-water settings are diverse in their depositional architecture but this diversity is under-represented in the literature. Diverse architectures result from multiple factors including source material, basin margin physiography, transport pathway, and depositional setting. In this contribution, we emphasize the impact of differing source materials related to differing delivery mechanisms and their influence on architecture, which is an important consideration in source-to-sink studies. Three well imaged subsurface lobate deposits are described that display three markedly different morphologies. All three lobate examples, two from intraslope settings offshore Nigeria and one from a basin-floor setting offshore Indonesia, are buried by less than 150 m of muddy sediment and are imaged with high resolution 3D reflection seismic data of similar quality and resolution. Distinctively different distributary channel patterns are present in two of the examples, and no comparable distributaries are imaged in a third example. Distributary channels are emphasized because they are objectively recognized and because they often represent elements of elevated fluid content within buried lobate deposits and thus influence permeability structure. We speculate that the different distributary channel patterns documented here resulted from different processes linked to source materials: 1) a lobate deposit that is pervasively channelized by many distributaries that have branched at numerous points is interpreted to result from comparatively mud-rich, stratified, turbulent flows; 2) an absence of distributaries in a lobate deposit is interpreted to result from collapse of mud-poor, turbulent flows remobilized from littoral drift; and 3) a lobate deposit with only a few, long, straight distributaries with few branching points is interpreted to be dominated by highly viscous flows (i.e., debris flows). We propose a conceptual model that illustrates the relationship between the proportion of mud in contributing flows and the relative size and runout distance of lobate deposits. We conclude that reconciling 3D seismic morphologies with outcrop observations of channels, scours, and amalgamation zones, and simple application of hierarchical schemes, is problematic. Furthermore, when characterizing unconfined deep-water deposits in the subsurface, multiple models with significant differences in predicted permeability structure should be considered.

E&P Notes (July 2021)

E&P Notes (July 2021)

Seismic hazard analyses for North Java Offshore Indonesia using ISO 19901-2:2004

Most offshore platforms in Indonesia use API RP 2A WSD as a guideline for designing earthquake-resistance offshore structures. However, this guideline does not explicitly state the return periods and the procedures for developing the designed response spectrum for used in seismic design. The procedures are described in more detail in ISO 19901-2 which stated explicitly requirement design parameter of 1.0s oscillator period and for a 0.2s oscillator period for a 1000-years return period of the earthquake. The paper presented a development of seismic hazard maps for 1.000 years return period for North Java Offshore Indonesia. The seismic hazard maps were modeled by the USGS PSHA program based on probabilistic concepts. The seismic sources used in the analyses were based on the latest researches published by National Center for Earthquake Studies (PuSGeN) in 2017. The study reveals that, generally, North Java Offshore Indonesia can be categorized as seismic zone 1 and 2 and East Madura as seismic zone 3 in accordance to ISO 19901-2.

Lateral variability in strain along the toewall of a mass transport deposit: a case study from the Makassar Strait, offshore Indonesia

Contractional features characterize the toe domain of mass transport deposits. Their frontal geometry is typically classified as frontally confined or frontally emergent. However, it remains unclear how the style of frontal emplacement and contractional strain within a mass transport deposit vary along-strike. We use bathymetry and 3D seismic reflection data to investigate the lateral variability of frontal emplacement and strain within the toe domain of the Haya Slide in the Makassar Strait, offshore Indonesia. The slide originated from an anticline flank collapse and the toe domain is characterized by a radial fold–thrust belt that reflects southwestwards emplacement. The frontal geometry of the slide changes laterally. It is frontally confined in the south and is associated with a deep, c. 200 m b.s.f. planar basal shear surface. The frontal geometry gradually changes to frontally emergent in the west, associated with a shallow, c. 120 m b.s.f., c. 3° NE-dipping basal shear surface. Strain analysis shows c. 8–14% shortening, with the cumulative throw of the thrusts increasing along-strike westwards from c. 20–40 to c. 40–80 m. We show that even minor horizontal translation of mass transport deposits ( c. 1 km) can result in marked lateral variability in the frontal geometry and strain within the failed body, which may influence their seal potential in petroleum systems.

Maximum tolerance for water content at various stages of a natuna production

Though the Natuna field in offshore Indonesia contains natural gas resources, its CO2 content exceeds 70%. While existing technologies can handle the separation challenges, the question of CO2 transport and storage will still remain due to the lack of aquifer storage sites with sufficient sealing integrity in this part of South Asia. Substantial occurrences of natural gas hydrates have been discovered in offshore Indonesia roughly 700 miles from Natuna, making the pipeline transport economically feasible. This work aimed to assess the risk of hydrate formation during this transport as evaluated by two different approaches: traditional method based on water dew-point versus evaluation accounting for alternative routes of hydrate formation. The hydrate risk analysis was also conducted for produced natural gas at transport conditions. We have investigated the case study involving using the separated CO2 for simultaneous safe long-term storage of CO2 and release of methane for in situ hydrates located at the North Makassar Basin in offshore Indonesia. Utilization of CO2 will require additive gases to increase gas permeability and reduce the blocking of sediments by new CO2-dominated hydrate. This analysis was conducted for variable content of nitrogen and H2S. We have concluded that the water dew-point-based method appears to severely underestimate the risk of hydrate formation; the maximum water concentration it allows in gas will be larger by a factor of eighteen than the one permitted by approaches that used water adsorption on hematite (rust) as the criterion.

OIL SPILL TRAJECTORY AND FATE FORECASTING, RESPONSE AND CLEANUP OPTIONS FOR A COASTAL ENVIRONMENT: A GREEN FIELD MODEL OFFSHORE INDONESIA

The environmental impacts of an oil spill and the attendant response applied for ecological restoration would mostly depend on the conditions of the spill, nature of the area, quantity and type of oil released, meteorological and climatological factors, as well as the effectiveness of response techniques. The Indonesian government and operators have been considering best ways of shielding the environment and their reputation from spill hazards, in cognizance of the region's high sensitivity and vulnerability. This paper thus undertakes a risk assessment for the potential environmental effects of possible spillage of medium light crude pumped to the Floating Storage and Offloading (FSO) terminal installed to handle production and bulk distribution of oil produced from a green oilfield offshore Indonesia. GNOME and ADIOS were deployed to forecast the trajectory and fate of oil spilled from the FSO during loading operations to ocean-going tankers, respectively. Key environmental data obtained from ESI maps were built into the models to yield desired results. The likely trajectory of oil released from the FSO as depicted by GNOME results for nine days after the spill and the contact probabilities show that 5,200 barrels of the oil would beach on the ninth day. Response efforts must thus be effected before this occurs. The results from ADIOS were captured for both winter and summer conditions; indicating that more spilled oil would remain after a 5-day period, if it occurs during winter, than would be obtained for a spill during summer. This implies less complicated cleanup operations in summer than in winter. However, since the oil is medium light, the lighter fractions would readily evaporate out, leaving behind heavier oily residues that may form tar balls with the submarine sediments and sink to the sea bottom or arrive at the beach, as shown by GNOME. Subsequent Net Environmental Benefits Analysis suggests that dispersants would not be a good response option due to their toxicity to the ecologically sensitive ecosystem. It is thus recommended to contain imminent spills using dykes and booms within a few hours of occurrence, before further dispersion and beaching. Subsequent in-situ burning would then enable all the hydrocarbons and most other contaminants present to burn off, thus protecting the shoreline and submarine resources. The study will guide spill responders and serve as a basis for future oil spill contingency plans (OSCPs) in the field and others within the Southeast Asian hydrocarbon provinces.

Quantitative interpretations and assessments of a fractured gas hydrate reservoir using three-dimensional seismic and LWD data in Kutei basin, East Kalimantan, offshore Indonesia

Concentrated fractured gas hydrate reservoirs in fine-grained sediments have been considered to have limited potential for commercially-viable production of natural gas. They may also pose significant geohazard where they overly conventional oil and gas production targets. The genesis of such accumulations is not well known and the characterization of the reservoirs is difficult. Thus, integrate characterization using 3D seismic interpretation, well logs, and geotechnical analyses are vital. The present study is the first detailed description of a fractured gas hydrate reservoir in the Kutei basin, offshore Indonesia.In this study, vertical fluid flow features (such as mud volcanoes and chimney structures) and other indicators of gas hydrate occurrence (including Bottom Simulating Reflectors (BSRs) and high-resistivity zones) are interpreted over a region of 500 km2. Seismic amplitude anomalies provide evidence of gas migration that has reached the seafloor. An interpreted double BSR below a mud volcano is inferred to indicate thermogenic gas present in the shallow sections. Geological and geotechnical analyses show overpressure associated with gas migration across the base of gas hydrate stability zone (BGHSZ) results in the formation of hydraulic and pneumatic fracturing. Seismic and well logs data indicate that the vertical migration of ascending free gas results in large-size macro-fractures whereas free gas accumulation below less permeable hydrated sediments allows for the generation of local small micro-fractures. Consequently, the fractures play roles as conduits and reservoirs for gas hydrate accumulations.Hydrate saturation was estimated from seismic and well log data by using seismic inversion and Archie equation, respectively. Gas hydrate is inferred to uniformly occur above the base of hydrate stability zone and its average thickness is estimated to be approximately 30 m. The gas hydrate is estimated to occupy generally 5–10% by volume in micro-fracture reservoirs, with as high as 30–35% near the top of macro-fracture reservoirs.

Enhanced Sand-Control System Successfully Treats Six Zones in Offshore Indonesia Well

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24879, ’Enhanced Multizone Single-Trip Sand-Control System Successfully Treats Six Zones in Offshore Indonesia Well,’ by Leon Zhou and Indra Gunawan, ConocoPhillips, and Ricki Jannise, Casey Suire, and Tyson Eiman, Halliburton, prepared for the 2014 Offshore Technology Conference Asia, Kuala Lumpur, 25-28 March. The paper has not been peer reviewed. Although multiple-zone, downhole sand-control-tool systems have been in use since the early 1990s, these systems have been designed for jobs that require only low pump rates with low pressure differentials. Multiple-zone systems capable of high fracturing pump rates and the associated differentials only recently have been introduced to the oil field, but most of these completions have been limited to four or five treated zones. This paper presents a case history from Indonesia in which six discrete zones in an offshore deployment were treated successfully in a single trip. Field History The Bawal field is located in Block B, 1000 km north of Jakarta, in the South China Sea. The average water depth across the field is 280 ft. The Bawal field was discovered in 1979; the field is approximately 5 km long and 2 km wide. The Bawal reservoirs consist of subangular-to- rounded, well-sorted silt to extremely fine quartz sand. The initial development concept was to drill and complete two to three subsea wells and tie them back to a nearby production facility, Hangtuah, 43 km away. The first-gas-production target was 2012. The reservoirs all require sand control, varying degrees of stimulation, high-rate water packing at rates of 8 to 20 bbl/min, and fracture treatments at rates of 22 to 35 bbl/min. The operator has completed multiple fields with two dominant completion methods: openhole standalone screen (OHSAS) and cased-hole frac pack (CHFP). The OHSAS completions typically are installed in horizontal wells or very-high-angle wells. The OHSAS requires special reservoir-drill-in fluid with calcium carbonate to drill the reservoir section, run the premium screen, wash the pipe, and conduct mudcake cleanout. Typically, a CHFP is conducted with tubing- conveyed perforation and alternative- flow-path sand screen being run in one trip; then, a frac pack is pumped with viscoelastic fracturing fluid. Historically, the operator has completed subsea wells with downhole sand control using the OHSAS method for single- zone completions and singletrip frac-pack/high-rate water packs for multizone commingled production. For frac-pack completions, the completion system used previously was capable of treating only up to three zones; therefore, the treatment rate per zone became lower, and there was always an issue with slurry distribution. If more than two to three zones were required per well, a stacked frac-pack completion was implemented. Completing these wells with conventional stacked sand-control methods meant spending many rig days tripping pipe in and out of each well. The single-trip multizone methods previously used in the area typically would provide only a limited pump rate of up to 10 bbl/min per zone and pressure ratings of 6,000 psi. For the new wells, the fracture treatments would require a more-robust system that would include a pressure rating of 10,000 psi because of sandout conditions. Another challenge was that commingling these zones into one well has historically resulted in 50% less recovery compared with single-zone completions. Early water breakthrough coming in from one of the zones would cause the well to load up and die. Therefore, the operator also wanted to include installation of an intelligent-completion system that would allow zonal isolation without intervention, to optimize reserves recovery. The multizone frac-pack completion not only would have to be capable of completing up to six zones in one run but also would have to be compatible with the planned intelligent-system equipment.

Intrinsic controls on the range of volumes, morphologies, and dimensions of submarine lobes

Submarine lobe dimensions from six different systems are compared: 1) the exhumed Permian Fan 3 lobe complex of the Tanqua Karoo, South Africa; 2) the modern Amazon fan channel–mouth lobe complex, offshore Brazil; 3) a portion of the modern distal Zaïre fan, offshore Angola/Congo; 4) a Pleistocene fan of the Kutai basin, subsurface offshore Indonesia; 5) the modern Golo system, offshore east Corsica, France; and 6) a shallow subsurface lobe complex , offshore Nigeria. These six systems have significantly different source-to-sink configurations (shelf dimension and slope topography), sediment supply characteristics (available grain size range and supply rate), tectonic settings, (palaeo) latitude, and delivery systems. Despite these differences, lobe deposits share similar geometric and dimensional characteristics. Lobes are grouped into two distinct populations of geometries that can be related to basin floor topography. The first population corresponds to areally extensive but thin lobes (average width 14 km × length 35 km × thickness 12 m) that were deposited onto low relief basin floor areas. Examples of such systems include the Tanqua Karoo, the Amazon, and the Zaïre systems. The second population corresponds to areally smaller but thicker lobes (average width 5 km × length 8 km × thickness 30 m) that were deposited into settings with higher amplitude of relief, like in the Corsican trough, the Kutai basin, and offshore Nigeria. The two populations of lobe types, however, share similar volumes (a narrow range around 1 or 2 km 3), which suggests that there is a control to the total volume of sediment that individual lobes can reach before they shift to a new locus of deposition. This indicates that the extrinsic processes control the number of lobes deposited per unit time rather than their dimensions. Two alternative hypotheses are presented to explain the similarities in lobe volumes calculated from the six very different systems. The first states that the wide range of starting flow volume and grain size across all systems enters the basin floor as a narrow range due to slope ‘filtering’ via more overspill and intra-channel deposition in larger systems. The second hypothesis is a result of the gradual decrease in downstream gradient from the distributive channel base to the lobe top during lobe growth. This is not sustainable as the channel will start to aggrade, and when a steeper lateral gradient is present, an avulsion will occur to an adjacent depositional low, which will be used for flows to fill and build a new lobe. This analysis of submarine lobe volumes indicates that the basin floor topography influences lobe geometry, but the fact that lobe volumes have a narrow range indicates a strong influence of intrinsic processes.

Use of Liner Drilling Technology as a Solution to Hole Instability and Loss Intervals: A Case Study Offshore Indonesia

Summary The Banuwati field offshore southeast Sumatra, Indonesia, presents major challenges to both drilling and liner running operations because of the problematic lower Baturaja limestone formation, which is a carbonate reef structure known for severe lost-circulation conditions. The operator previously had experienced severe losses with wellbore-stability issues while drilling this formation with the inability to set the 7-in. drilling liner at the planned depth in Well A-3. The liner had to be pulled out of the hole, leading to the eventual abandonment of the existing openhole section and resulting in the sidetracking of the well. Liner-while-drilling technology was identified as the most suitable solution for setting the planned 7-in. drilling liner through the loss interval because of the following: Documented lost-circulation problems have been minimized or eliminated through the use of liner drilling technology possibly attributed to the "smear effect" (Fontenot et al. 2004) phenomenon.The liner system selected provided for high torsional capability as well as the requirement for both a mechanical and a pressure event to release the setting tool, thus minimizing the chances of premature release.A drill shoe with a displaceable polycrystalline-diamond-compact (PDC) cutting structure was used to drill the 8½-in. hole section and subsequently displaced before cementing so as to allow drill out with a conventional drill bit and bottomhole assembly (BHA). This paper will discuss the implementation of liner drilling technology in the Banuwati field project. This technology was used to drill successfully through the known lost-circulation zone with the 7-in. liner cemented in place, allowing the operator to reach the completion objectives while realizing a savings of more than USD 1 million.

新たな海洋天然ガス開発技術―ＬＮＧ‐ＦＰＳＯ―

LNG-FPSO (Floating Production Storage and Offloading Unit) is a floating system installed LNG plant on it and enables to export natural gas as LNG from offshore field to gas markets directly. This system may have significant advantages for development of deepwater, remote or small size offshore gas field for the following reasons: · Minimum Environmental Impact · Reduction in CAPEX/OPEX · Potential Reduction of Project Lead Time · Reduction in Abandonment Work & CostINPEX Corporation (INPEX) has conducted several studies on LNG-FPSO to assess the feasibility since 2001. Based on the results, INPEX conducted Pre-FEED (Front End Engineering & Design) for LNG-FPSO for the INPEX's Abadi gas field located in the deepwater remote area in Arafura Sea Offshore Indonesia from September 2007 to July 2008.This presentation outlines the concept of LNG-FPSO for the Abadi gas field and discusses the applicability of LNG-FPSO.

Three-Dimensional Seismic Architecture of Fluvial Sequences on the Low-Gradient Sunda Shelf, Offshore Indonesia

Abstract The sequence stratigraphy of fluvial–deltaic strata deposited near the center of the wide, gradually subsiding Sunda Shelf differs from standard highstand examples because low accommodation and low depositional gradients restricted the thickness of fluvial–deltaic sequences and the depth of lowstand fluvial incision. In this setting sea-level fluctuations may have had less influence on fluvial depositional patterns, and fluvial stratigraphy is more likely to be defined by changes in river discharge during gradual aggradation. The upper Muda Formation in West Natuna Basin, offshore Indonesia, is a 225-m-thick, dominantly fluvial succession that prograded onto the middle part of the Sunda shelf from Pliocene to Holocene. The succession changes upward from offshore shelf deposits, through a thin interval of deltaic deposits, a succession of fluvial deposits, and finally a thin transgressive succession directly beneath the modern sea floor. A high-resolution seismic survey (17 km by 40 km in area) of Belida Field near the middle of the Sunda shelf provides exceptional images of changing fluvial architecture within five erosionally based, fluvial sequences. Sequences, each several tens of meters thick, are characterized by low-relief basal incisions that extend laterally onto interfluves cut by a network of gullies. Although a regressive stacking pattern of successive sequences is defined to some extent by an increase in the relief of basal erosion and a decrease in average sequence thickness, it is best defined by progressive increase in the extent of gully formation onto interfluve areas (indicating longer periods of interfluve exposure). Channel size tends to decrease upward within individual sequences, recording both a decrease in the size of the largest channels and greater preservation of smaller tributary and floodplain drainage channels. The largest channels preserved directly above the better developed sequence boundaries tend to be more sinuous and to have more extensive inner-bend accretion deposits than those that cut down from horizons higher within sequences. This suggests that incised channels had more stream power to erode their banks relative to the sediment loads they carried. Although mechanisms controlling the episodic shallow incision and then aggradation of these fluvial systems are difficult to constrain from variations observed in this small study area, the consistent thickness of the Muda Formation observed in regional 2D seismic sections is evidence against significant syndepositional tectonic deformation or differential subsidence. Low regional gradients and great distance of the study area from the paleo-shelf edge (~ 1000 km) are evidence against direct sea-level influence. Larger channel sizes directly above sequence boundaries supports temporal changes in channel discharge, perhaps related to climatic changes within the drainage basin. Recognition of episodic channel incision and bypass alternating with periods of floodplain aggradation influences predictions of channel-deposit connectivity based on channel proportion.

Application of 3-D SRME and Multiple Diffraction Removal in the Makassar Straits, Indonesia

Both multiple, reflections and multiple diffractions are present in seismic data acquired in the Makassar Straits, offshore Indonesia. The application of 3-D SRME shows significant improvements over 2-D SRME results in various areas. In addition, several other processing methods were utilized to specifically attenuate any remaining multiple diffractions.

Microbial methane and ethane from gas hydrate nodules of the Makassar Strait, Indonesia

Intact, white nodules of gas hydrate were recovered in piston cores (∼0–6.4 m sediment depth) from the deep water region of the Makassar Strait, between the islands of Borneo and Sulawesi, offshore Indonesia. Consistent with structure I gas hydrate, the dominant hydrocarbon is methane (∼99.96%). The hydrate-bound methane is relatively depleted in 13C (mean δ 13C = −70.6‰; mean δD = −189.9‰). Microbial ethane, also present in the hydrate, is more highly depleted in 13C (mean = −52.6‰) than nearly all previously discovered gas hydrates, and is accompanied by trace volumes of microbial ethylene and propylene. Detrital higher-plant material is the likely sedimentary carbon source. The source of microbial methane and ethane appears to be in situ reduction of CO 2 by extremophile bacteria adapted to high pressure. The hydrate occurs several hundred meters above the base of the gas hydrate stability zone. Nodular hydrate is associated with seafloor authigenic carbonate rock and chemosynthetic clams characteristic of deep cold vent sites.

Direct Visualization and Extraction of Stratigraphic Targets in Complex Structural Settings

Abstract Advances in 3D visualization and volume detection have greatly improved our ability to find stratigraphic targets in areas of complex structure. In this paper we apply volume sculpting, seismic facies analysis and prediction of rock properties from seismic data to resolve a potential reservoir channel from a highly faulted setting in offshore Indonesia. These techniques use computational power to search for patterns in the data. These patterns may be presented to the interpreter or may be used to transform seismic and well data into estimates of rock properties. Such techniques should improve development efficiency in areas where complex structure has previously precluded the use of these techniques.

Unsupervised seismic facies classification: A review and comparison of techniques and implementation

The use of automatic seismic facies classification techniques has been steadily increasing within E&P interpretation workflows over the past 10 years. It is not yet considered a standard procedure but, with the knowledge of the advantages (and limitations) of the different seismic classification methods, its role in the interpretation process as a successful hydrocarbon prediction tool is anticipated to grow. This paper reviews and compares the unsupervised classification methods presently used in seismic facies analysis: K-means clustering, principal component analysis (PCA), projection pursuit, and neural networks (vector quantization and Kohonen self-organizing maps). The term “unsupervised” covers all classification techniques relying only on input data and not biased by the desired output. These methods are described, compared, and illustrated by case studies taken from deep offshore Louisiana, west and south Texas, onshore California, and offshore Indonesia. Seismic data volumes are huge and consist of highly redundant data. It is now established that their analysis can be greatly optimized by applying efficient data reduction algorithms that preserve essential features of the seismic character. The objective of the facies classification process is to describe enough variability of the seismic data to reveal details of the underlying geologic features. The classification process should do this while preserving a synthesis for the seismic signal changes. In addition to comparing the classification methods, this paper presents relevant information pertaining to data input, data analysis, and data output. Seismic data, from the statistical point of view, have characteristics like continuity, redundancy, and noise that affect the behavior of the seismic classification techniques. At first glance, these classification techniques may appear similar. However, their ability to efficiently describe changes in seismic character and their interpretability can vary significantly. These different techniques are compared in this paper for their suitability to describe seismic data in a meaningful manner directly …