bluuebunny/crossref_metadata_2025_split huggingface dataset:
Petroleum system, migration and charge history in the Neo- and Meso-Proterozoic series of the Taoudenni Basin, Adrar: Insights from fluid inclusions
Authors: Girard Jean-Pierre , Eichenseer Herbert , Kabbej Amir , Idris Kamil Mohamed 
Published: May 2016

Abstract
Exploring ancient Paleozoic–Proterozoic cratonic basins is a very challenging undertaking because it is often difficult to achieve a good understanding of complex burial/thermal histories and old petroleum systems. As part of an ongoing exploration campaign, two frontier exploration wells were recently drilled in the northwestern part of the Taoudenni basin in Mauritania, targeting Proterozoic clastic and carbonate petroleum plays located at present-day depths between 2.4 and 3.0 km. Both wells were investigated by use of the so-called FIS (Fluid Inclusion Stratigraphy) technique in order to document the performance of a Proterozoic petroleum system in the Adrar sector of the basin. The results permitted to document the existence of 1) petroleum paleo-accumulation and -migration in the Neo-Proterozoic Lower Assabet sandstones and Meso-Proterozoic Atar dolostones, 2) an efficient seal to oil, above the Lower Assabet sandstones, 3) multiple charges of oil of variable maturity in the eastern well (shallower paleo-burial) subsequently lost by leakage, 4) secondary cracking of a primary oil charge, and possibly gas dismigration, in the western well (deeper paleo-burial). This work demonstrates the existence and the functioning of an oil-prone Proterozoic petroleum system, and provides very valuable guidance for future exploration in this area of the Taoudenni basin. It also opens up potentialities to be investigated for Proterozoic gas/oil shale plays.

1. Objectives and context
Frontier onshore exploration is presently being conducted in the northwestern part of the Taoudenni basin, Mauritania, with the objective of investigating very old (450–1500Ma) Paleozoic-Proterozoic plays. This is a very challenging undertaking because this very old cratonic sedimentary basin remains largely under-explored today. Two wells were drilled in the early seventies (1973–1974, Ouasa-1 & Abolag-1) and three in the recent years (2009–2013) in the northwestern part of the basin, but no economical discovery was made so far.
The present study focuses on two of the most recent exploration wells. They are located in the Adrar region, east of the city of Atar (Fig. 1), and are referred to as well A (western well) and B (eastern well).
The Adrar prospective area is characterized by a Proterozoic-Paleozoic sedimentary succession and a Proterozoic petroleum system (Fig. 1). The Meso-Proterozoic series is composed of the predominantly clastics sediments of the Char Group at the bottom overlain by the thick succession of dolomitic carbonates of the Atar Group. The Neo-Proterozoic series is composed of, from bottom to top, the thick Assabet sandstones, the Jebliat glacial deposits and the thick Teniagouri shales. The Paleozoic rocks are essentially clastics of Cambrian (Nouatil sandstones) to Devonian (Tenemouj sandstones) age.
Techniques to Understand Reservoirs Associated with Deepwater Sedimentological Processes, from Basin to Field Scale - A Case Study
Authors: Acevedo Andres , Madhoo Hamechan A , Khramtsov Artem , Noomee Lakkanaporn , Tetzlaff Daniel Matias 
Published: May 2016

Abstract
Over the last decade, there have been several discoveries of significant oil accumulations in deepwater reservoirs. With advances in research and the availability of high-resolution seismic data, their variability and complexity have been well documented. For hydrocarbon exploitation purposes, however, the industry lacks an integrated approach to interpret these reservoirs, using multiple domains, and efficiently consume the available data. This paper describes a series of innovative interrelated techniques, plus observations to help improve the understanding of these reservoir types at three scales:Basin scale: Stratigraphic forward modeling is a useful method to simulate regional geological processes. Using this technique a paleo-basin floor surface reconstructed from seismic can be used to set a series of simulations. By varying several parameters, such as water level and water/sediments coefficients, within a reasonable range of values and comparing results to observed data, plausible models are created. These, considered jointly, provide an integrated understanding of the uncertainty of the occurrence of observed features and sediment properties.Sequence scale: Sinuosity and stacking configurations are critical factors that control local channel-fill patterns. By using seismic sections along channels, coupled with seismic reconstruction, complex paleo-sequence geometries can be resolved. In our case a low-sinuosity channel was identified and a backstepping-fill pattern defined.Reservoir scale: The quantification of net-to-gross is critical in hydrocarbon exploitation. By using training grids and multipoint statistical methods a comprehensive facies model can be built. Training grids, based on fill patterns and channel geometry, are combined with probability properties to condition the overall stochastic distribution of facies. Additionally, uncertainties associated with this process are captured in an uncertainty workflow.
Integrating these three techniques leads to a better understanding of reservoir-critical factors. The above approach is proven by using a seismic dataset from Campos Basin, Brazil, which contains well-documented reservoirs originally deposited in a deepwater setting.

Introduction
Deepwater clastic sediments form important hydrocarbon reservoirs globally, for example the Atlantic margins of West Africa and Brazil (Weimer et al., 2000), and over the last decade there have been several significant discoveries in these provinces. However, with increasing insight into these deepwater reservoirs as a result of high-resolution seismic data and borehole imaging techniques, more complexities are being revealed than previously anticipated. Furthermore, with higher data volumes there is a growing need to integrate, both across data types and geoscience domains.
Using 4D Seismic Surveys and History Matching to Estimate Critical and Maximum Gas Saturation
Authors: Obidegwu Dennis Chinedu , Chassagne Romain Louis , Macbeth Colin 
Published: May 2016

Abstract
An approach is explored for estimating critical and maximum gas saturation using 4D seismic data from multiple surveys shot during gas exsolution and dissolution in a producing hydrocarbon reservoir. To guide this process, hydrocarbon gas properties and behaviour are studied, and their relation to the fluid-flow physics is understood using numerical simulation and seismic modelling. This understanding is then used to interpret observed seismic data, which has surveys repeated every 12 to 24 months, from a turbidite field in the United Kingdom Continental Shelf (UKCS). Furthermore, the field reservoir simulation model is then history matched to the production data and the gas saturation effects observed on the 4D seismic data. The 4D seismic response is a function of pressure changes, fluid (oil/water/gas) changes and noise. The effects of the gas mechanism are extracted from the seismic data based on its unique relationship to the seismic amplitudes. It is found that these changes can be represented by a binary model (presence or absence of gas) which enables the use of a logical objective function to compute the misfit between the observed data and simulated data, and thus guide the parameterisation process of the history matching exercise. This approach circumvents full physics modelling in a joint history matching workflow that includes conditioning to both production data and multiple time lapse seismic data. It is concluded that for seismic surveys repeated at intervals of six months or more, the gas saturation distribution during either liberation or dissolution exists at two fixed saturations defined by the critical and the maximum gas saturation. From analysing only the 4D seismic data, we find a low critical gas saturation and a maximum gas saturation that is relatively unconstrained. The history matching exercise also gives us similar low values for the critical gas saturation, and highlights the importance of the vertical permeability in getting an extensively corroborated model. This paper explores a direct link between 4D seismic and the fluid flow parameters, a link between the gas saturation distribution and seismic response, as well as a quantitative analysis using multiple 4D seismic surveys for history matching.
FLNG: Technological Breakthrough and Innovative Application of Existing Technologies
Authors: van der Velde Harry , Boekhorst Alexander 
Published: May 2016

Abstract
Shell, with a history in LNG spanning 50 years, has become the world's largest international oil company by equity LNG production with ownership in many liquefaction projects currently in operation or under construction. We believe that floating liquefied natural gas (FLNG) will write the next chapter in the history of the industry. Our FLNG journey started in the 1990s with early stage project development followed by further design work. FLNG technology allows for the production, liquefaction, storage and transfer of LNG at sea, as well as the ability to process and export liquefied petroleum gas (LPG) and condensate. This opens up new business opportunities for countries looking to develop their gas resources and bring more natural gas to market.
Shell's FLNG uses a range of proven technologies in innovative combinations. Examples include the internal turret – selected for its suitability to tie-back complex subsea systems and harsh meteocean conditions, a double wall substructure hosting the product storage tanks, processing equipment such as the absorption columns and main cryogenic heat exchangers that have been modified to allow them to operate efficiently under marine conditions and a system of specially designed cryogenic loading arms. The safety of the FLNG facility has been paramount during its design. The layout of the facility for example has been developed using rigorous process safety standards and evaluation through Quantative Risk Assessments. The layout includes open 20 meter safety gaps across the full width of the barge between the main processing modules and escape routes at both starboard and port side, as well as through the central alley.
Shell's final investment decision (FID) for Prelude in May 2011 was the world's first FID for a FLNG project. Shell is the operator of Prelude FLNG in a joint venture with INPEX (17.5%), KOGAS (10%) and OPIC (5%). The facility is built by a consortium of Technip and Samsung Heavy Industries (SHI), with the Goeje yard in South Korea being a key construction location.
Looking forward, Shell's FLNG philosophy is pursuing standardisation so that subsequent developments can become quicker and more cost effective. Shell has also developed a FLNG solution for leaner gas fields. The so called 'FLNG Lean' can be applied on fields with lean compositions and by optimizing liquid handling and storage facilities, FLNG Lean is able to achieve higher LNG production capacities.
Is Your Trap Filled to Spill?
Authors: Peacock Douglas 
Published: May 2016

Abstract
Gross rock volume is typically the biggest uncertainty in volumetric estimation, especially early in field life. Assumptions about fluid contacts are often the biggest component of volumetric uncertainty. This paper will examine how a better understanding of hydrocarbon trap and seal capacity allows more accurate volumetric estimates and improved risk assessment.
Recent advances in several areas such as basin modelling, hydrocarbon charge, seal capacity and fault seal analysis have allowed a more comprehensive understanding of hydrocarbon traps. Hydrocarbon charge studies indicate that the proportions of generated hydrocarbons that are trapped in conventional reservoirs, the trapping efficiency, are very low, in the order of a few percent. Many times more hydrocarbons are generated than traps have the capacity to store.
Analysis of individual fields suggests that many traps are filled to capacity rather than to structural spill points. Fill capacity may be limited due to lack of top seal or fault seal. Fields that are not filled to structural spill are often limited by trap capacity rather than by insufficient charge. Hydrocarbon phase in a trap is affected not only by source rock type and maturity, but also by seal capacity.
With exploration wells often targeted at or near the crest of structural highs, over-optimistic assumptions about fluid contacts, in particular an assumption of fill-to-spill is a major cause of misunderstanding volumetric uncertainty.
These observations and results have implications throughout the life cycle of a field, from risk assessment of prospects to estimation of volume ranges during exploration, appraisal and development.
Look-backs and post-mortems are also useful to assess whether previous assumptions about hydrocarbon charge, seal capacity and fill mechanisms have been accurate or if they need revision. Analogues and lessons learned from existing fields and discoveries can also provide valuable insight into future predictions. Assessing volumetric uncertainty in terms of trap and seal capacity rather than relative to structural spill points allows better quantification of volumetric uncertainty.

Hydrocarbon Generation and Trapping Efficiency
Previous studies of hydrocarbon trapping efficiency have suggested that a relatively small proportion of generated hydrocarbons are conventionally trapped. Large proportions of the hydrocarbons generated are retained in the source rock without migrating, and remain as targets for unconventional reservoir development. Of the hydrocarbons that are expelled from source rocks, most are lost to the surface or are retained in carrier beds. The proportion of hydrocarbons captured in conventional traps is estimated to range from a few percent to around ten percent. Figure 1 highlights the large proportion of hydrocarbons retained in the source rock, but also shows the relatively small amount of conventionally trapped hydrocarbons. Expelled hydrocarbon volumes are typically many times greater than trapped hydrocarbon volumes.
A Broadband Seismic Acquisition and Processing Solution to Improve Imaging in a Complex Shallow Water Environment, Malaysia
Authors: Spedding Andrew , Gehman Carter , Nyein Glenn , Sazykin Artem , Vasilyev Pavel , Wurfel Monica 
Published: May 2016

Abstract
There have been several recent advances in the last few years in marine broadband acquisition and processing technologies and shallow gas imaging. They have enabled new life to be breathed into old datasets through reprocessing and from completely new seismic surveys to be acquired in place of legacy conventional datasets that can lead to a step change in data quality and subsequently reservoir understanding. This paper will look at these new technologies and give an example of a shallow water dataset with complex near surface shallow gas bodies where a combination of new acquisition, processing and reprocessing techniques have been able to provide significant uplift over pre-existing legacy conventional datasets targeting thin bed pay zones. Careful consideration of the geophysical challenges and implementing targeted solutions has been a key to producing a successful output. A complimentary paper discusses in more detail the interpretational benefits of the new acquired broadband data versus the legacy conventional data.

Introduction
Until recent years marine seismic datasets have had to contend with the source and receiver ghost notch effect in the output frequency spectrum whereby the outgoing upward travelling source side sea-surface reflection and the returning receiver side sea-surface reflection constructively and destructively interfere with the directly down going source reflections and up going receiver side reflections to give band limited datasets. Geophysicists have had to design their surveys to enhance a given part of the bandwidth at the detriment to another part e.g. tow shallow to enhance higher frequencies or tow deep to enhance low frequencies. With the advent of broadband acquisition techniques (Hill et al., 2006; Carlson et al., 2007; Soubaras and Dowle, 2010) this no longer has to be the case and the recorded ghosts can be addressed in acqusition based solutions to give frequency rich broadband datasets that can almost reduce the wavelet to a near spike. As a by-product streamers can be towed deeper to reduce the effects of noise from sea state generated noise to provide datasets with higher signal to noise and aiding better lower frequency penetration deeper into the section. The result is rich bandwidth shallow data and better imaged deeper sections.
Asia-Pacific’s First Isometrically Sampled Subsurface Image: Innovative Technology to Deliver on Complex Field Development
Authors: Fitzpatrick Jeremy , Iwachow Dana , Bayly Martin Paul , Roth Jurgen 
Published: May 2016

Abstract

Introduction
This case study describes the motivation and execution of a large 3D surface seismic survey recently conducted over 4,000km2 in the Carnarvon Basin offshore Australia. This survey was the first use of an innovative towed streamer technology in Australasia that enables the collection of broadband, un-aliased isometrically sampled wavefields.
Woodside Energy Ltd (Woodside) operates the North West Shelf gas producing assets that are located on the Rankin Platform, Parker Terrace, Kendrew Trough and also oil fields of the Madeline Trend. Certain areas in the vintage 3D surveys are characterized by poor seismic data quality producing uncertainty in reservoir management and potential prospectivity. In 2012 the North West Shelf (NWS) Project participants held a technical workshop to determine a strategy to maximize the productive life of this acreage and to extend the production from the Karratha gas plant. A key outcome of the workshop was the need for new 3D seismic data of a quality suitable for appraisal, development and exploration activities over the next decade. This resulted in the decision in late 2013 to acquire the "Fortuna 3D" (Fortuna) seismic survey, covering over 4,000km2 (Figure 1). The resulting seismic image is intended to enable the NWS joint venture to explore and develop this core asset with greater confidence.
Fortuna is the first survey in Australia to use a new multi-sensor towed streamer technology. This streamer includes both finely spaced hydrophones and accelerometers embedded in the cable. These streamers digitally measure not only the scalar pressure wave with finely spaced hydrophones as in conventional systems, but also use accelerometers to measure the directional particle acceleration of the seismic wave in both the vertical (Az) and cross-cable (Ay) directions. These additional measurements when carefully combined provide a broadband frequency signal that allows the reconstruction of the seismic wavefield with fine spatial sampling to improve both noise attenuation and subsequently the subsurface image. This "three component" streamer technology was augmented with other innovations including multilevel seismic sources, integrated real time navigation and streamer steering along with massive computing resources to facilitate data conditioning and initial signal processing on the vessel.
As shown in the map in Figure 1, the Fortuna survey presented several operational challenges including concurrent oilfield operations, working around infrastructure and other vessels, plus environmental challenges associated with strong tides and unpredictable currents. These issues required careful forecasting and planning due to the dynamic nature of this operational environment.
Reservoir Characterization through Bayesian Joint Inversion of Seismic and EM Attributes
Authors: Miotti Fabio Marco , Ceci Federico , Guerra Ivan , Lovatini Andrea 
Published: May 2016

Abstract
The main objective of the reservoir characterization is to provide reservoir property maps to reservoir engineers for the field appraisal. Since that porosity and water saturation affect both seismic and EM attributes, their estimation can reduce the uncertainty of the interpretation and consequently the costly drilling of un-productive reservoirs. This study explains the petrophysical joint inversion (PJI) of seismic and EM attributes to estimate the petrophysical model in terms of porosity and water saturation. Rock physics models are involved as forward models to form a proper link between data input (seismic and EM attributes) and the petrophysical parameters, (porosity and water saturation). According to the formal Bayesian theory, the uncertainty affecting the input data (AI and resistivity models) and the model parameters (porosity and water saturation) is captured by, respectively, data and model covariance matrix. It is assumed Gaussian probability density functions for model parameters and input data. PJI is applied where both seismic attributes and resistivity models show consistent anomalies as evidence of a potential reservoir. PJI objective is to jointly estimate porosity and water saturation from AI (seismic inversion derived), and resistivity (CSEM inversion derived), by using rock physics modeling within Bayesian framework. The result is represented by the porosity and water saturation distribution within the potential reservoir. PJI realizes a multi-physic inversion able to exploit the complimentary information available in the single physic domains, which are seismic and EM. The methodology is applied to a real hydrocarbon exploration scenario to evaluate its contribution to the interpretation phase. 3D volumes of estimated porosity and saturation show how the joint inversion of acoustic impedance and electrical resistivity provide a quantitative description of the reservoir properties and with it a measure of uncertainty, which is consistent with the petrophysical model and observations.

Introduction
Reservoir characterization objectives are to estimate the petrophysical properties of the prospective hydrocarbon traps and to reduce the uncertainty of the interpretation. In this framework, we present a workflow for petrophysical joint inversion of seismic and EM attributes to estimate the petrophysical model in terms of porosity and water saturation. This study realizes the joint inversion within the probabilistic structure provided by the Bayesian theory. 3D volumes of estimated porosity and saturation, show how the joint inversion of acoustic impedance and electrical resistivity can provide a quantitative description of the reservoir properties and with it a measure of uncertainty, which is consistent with the petrophysical model and observations.