Characterization and geostatistical modeling of reservoirs in ‘Falad’ field, Niger Delta, Nigeria

This research aims at characterizing and modeling delineated reservoirs in ‘Falad’ Field, Niger Delta, Nigeria, to mitigate the challenge caused by the heterogeneous nature of the reservoirs. Seismic and well log data were integrated, and geostatistics was applied to describe the reservoir properties of the interwell spaces within the study area. Four reservoirs, namely RES 1, RES 2, RES 3 and RES 4, were delineated and correlated across four wells. The reservoir properties {lithology, net to gross, porosity, permeability, water saturation} of all the delineated reservoirs mapped were determined, and two reservoirs with the best quality were picked for further analysis (surface generation and modeling) after ranking the reservoirs based on their quality. Structural interpretation of the field was carried, nine faults were mapped (F1—F9), and the fault polygon was generated. The structural model showed the area is structurally controlled with two of the major faults mapped (F1 and F3) oriented in the SW–NE direction while the other one (F4) is oriented in the NW–SE direction. A 3D grid was constructed using the surfaces of the delineated reservoirs and the reservoir properties were distributed stochastically using simple krigging method with sequential Gaussian simulation, sequential indicator simulation and Gaussian random function simulation algorithms. Geostatistical modeling used in this study has been able to give subsurface information in the areas deficient of well data as the estimated reservoir properties gotten from existing wells have been spatially distributed in the study area and will thus aid future field development while also they are used in identifying new prospect by combining property models with structural maps of the area.

Depositional Model for Turbidite Lobes in Complex Slope Settings Along Transform Margins: The Motta San Giovanni Formation (Miocene—Calabria, Italy)

Intraslope lobes, or perched lobes, are attracting scientific interest because they represent a key archive between the shelf and the deep basin plain when looking at a complete source-to-sink depositional system across a continental margin and can form significant offshore hydrocarbon plays. In this study, we focus on a detailed characterization of intraslope lobes of the Motta San Giovanni Formation (Miocene, Calabria), which were deposited in confined conditions during the Miocene along a transform margin. We determine the typical facies associations and stratigraphic architecture of these intraslope lobes using a 3D digital outcrop model resulting from a combined Uncrewed Aerial Vehicle (UAV) and walking acquisition, together with sedimentological logging and geological mapping. We propose recognition criteria for the identification of intraslope lobes, including facies and geometries, integrated within a depositional model. A comparison with other well-known intraslope and confined lobes, as well as basin floor lobes, is finally discussed, to highlight the peculiarities of intraslope lobes deposited along transform margins. The diagnostic depositional model for these types of intraslope lobes includes four main stages of evolution: 1) Stage 1—isolated detached lobe precursor in response to a flushed hydraulic jump, 2) Stage 2—prograding and aggrading lobe elements associated with a relatively stable and submerged hydraulic jump in the Channel-Lobe Transition Zone (CLTZ), 3) Stage 3—major bypass associated with lateral accretion and local aggradation interpreted as a renewal of a normal hydraulic jump in the CTLZ, and 4) Stage 4—erosion and bypass then abandonment. The development of intraslope lobes along active transform margins is allowed by tectonically induced slope segmentation and local confinement. In such a context, flow stripping and overspill processes occurred. Resulting lobes appear to be particularly small and relatively thin sandy deposits. They could be considered end-member in a lobe classification based on the Net-to-Gross content (high) and taking into account their thickness/width ratio (intermediate between 10:1 and 100:1 lines).

Coarse-grained meandering distributive fluvial system of the basal Cedar Mountain Formation, U.S.A.

ABSTRACT The analysis of downstream changes in ancient fluvial systems can better inform depositional models for foreland-basin systems. Herein we analyze the basal deposits of the Early Cretaceous Cedar Mountain Formation of Utah to better understand the variety of fluvial deposits present and to develop a depositional model for the Sevier foreland basin. We also evaluate the long-held interpretation of a braided origin for these deposits and document numerous examples of point-bar deposition in highly sinuous meandering rivers by analysis of large (20 to 60 km2) plan-view exposures. These plan-view exposures allow comparisons between planform and cross-sectional geometries. The study utilizes outcrop data, virtual outcrop models, and satellite imagery to develop a facies model and analyze the architecture of channel bodies in the Buckhorn Conglomerate and Poison Strip Sandstone of the Cedar Mountain Formation. We document downstream (west to east) decreases in lateral channel migration, sinuosity, channel amalgamation, grain size, and percent of fluvial channel facies (conglomerate and sandstone). Fluvial channel deposits occur arranged into larger stratal bodies: multistory–multilateral channel bodies that are dominantly composed of clast-supported conglomerate in the west to a mix of multistory, multilateral, and isolated channel bodies composed of matrix-supported conglomerate in the east. The median width of highly sinuous point bars is similar across the field area (344 m to 477 m), but the inclusion of narrower (median = 174 m), low-sinuosity bar elements in the east indicates an overall reduction in lateral channel migration and sinuosity downstream. Net-to-gross values range from 100% in much of the western outcrops to as low as 38% in the east. Paleocurrent analysis reveals a transverse (west to east) paleoflow for the study interval that merges with axial (south–north) paleoflow near the Utah–Colorado state line. We estimate 104 m3/s-scale discharge and 106 kilometer-scale drainage area for axial rivers based on paleohydraulic analysis which represents a significant part of the Early Cretaceous continental-scale drainage. The observed downstream trends in lateral channel migration, sinuosity, channel amalgamation, grain size, and net-to-gross for the basal Cedar Mountain Formation are consistent with expected trends for sinuous single-thread distributive fluvial systems and are similar to observed trends in the Jurassic Morrison Formation. Medial (Buckhorn Conglomerate) to distal (Poison Strip Sandstone) zones are preserved and span the forebulge to backbulge depozones of a foreland-basin system. Postulated deposits of the proximal distributive fluvial system have been removed during erosion of the foredeep depozone. The easternmost Poison Strip Sandstone and coeval Burro Canyon Formation represent deposits of an axial system at which western-sourced distributive fluvial systems end. Distributive fluvial systems dominate modern foreland basins, and this study suggests that they may constitute a significant proportion of ancient successions.

Remote Bed Boundary Detection Tool Data Interpretation Without Special Geosteering Support to Drill Horizontal Wells

Today, one of the most modern and successful geosteering methods in terms of net to gross value (NTG) is a proactive geosteering. The purpose of this article is to share the experience of using Remote Boundary Detection Tools to solve various geological problems and describe the ways of using the data from it. The method provides the ability to detect the approaching boundary (usually reservoir top) with resistivity contrast before entering it with the bit or BHA sensors. It allows to adjust well trajectory proactively and, therefore, increase Net to gross ratio. The article shows the ways to implement global experience in horizontal wells drilling and proposes ways to reduce the cost of well construction without elimination of High-Tech equipment in BHA. The article explains the methods of interpreting the output data from the tool that can determine the approach to one or several boundaries with resistivity contrast.

Redistribution and Income-Tax Reform

One of the most significant determinants of the level of redistribution or the capacity to change inequality within a tax-benefit system is the structure of the taxation system. In this chapter, we add income taxation and social-insurance contributions to the analysis of social transfers in the previous chapter. The chapter describes the theoretical structure of personal income taxes and introduces the concept of joint taxation. The chapter also addresses a methodological issue common to many microsimulation models and the creation of their base datasets, namely the inversion of data from net to gross. From a validation point of view, concepts associated with using external validation sources are introduced. From a measurement point of view, measures that aim to quantify the degree of progressivity and redistribution in tax systems are described. A redistributive analysis of a theoretical tax system, and the implications of a joint taxation system, is then undertaken.

The Characterization of Stratigraphic Play in Middle Baong Sand for Hydrocarbon Prospecting in Offshore North Sumatera Basin

Pertamina EP is operating a small block in Offshore North Sumatera Basin where a couple of the fields are producing gas and condensate from the Belumai Carbonate. However, the wells production is depleting and several delineation wells are unable to find additional reserves, it is important to find a new play within the block. Few discoveries in the Middle Baong Sand (MBS) reservoir suggested a promising stratigraphic play to be explored, but it requires more detailed characterization of the reservoir extent. The Malacca strait-sourced MBS consists of several deposited sand packages during a mega sequence. The term MBS might represent a deltaic environment from a transgressive system tract of some marine shore bar or a basin floor fan. Each system has a distinct character (thickness, net to gross ratio, distribution) that must be evaluated before proposing an exploration well. The depositional environment and reservoir distribution are interpreted and modeled using regional 2D seismic and high-quality 3D seismic. Paleo-bathymetric interpretation from well samples shows a good correlation with the palinspastic reconstruction. The result shows that the Pertamia EP working area is located in the shore bar depositional environment. Seismic attributes are used to delineate reservoir distribution within the working block and well logs are used to constrain prospective sand bodies and water zones identification. Furthermore, source rock maturation and migration path and hydrocarbon occurrence from the discovery wells have been evaluated for hydrocarbon prospecting and risking. This study suggests a promising lead for hydrocarbon exploration in the study area and opens up a new opportunity for an underexplored play.

Recognition and characterization of small-scale sand injectites in seismic data: Implications for reservoir development

Small-scale (< 20 m), non-resolvable sand injectites can constitute a large part of the net-to-gross volume and affect fluid flow in the reservoir. However, they may also cause challenges for well placement and reservoir development because they are too small to be reliably constrained by reflection seismic data. It is therefore important to better understand how small-scale injectites influence seismic images and may be recognized and characterized above reservoirs. The Grane Field (North Sea) hosts numerous small-scale sand injectites above the main reservoir unit, causing challenges for well placement, volume estimates and seismic interpretation. Here, we investigate how such small-scale sand injectites influence seismic images and may be characterized by (1) using well-, 3D seismic- and outcrop data to investigate geometries of small-scale sand injectites (0-15 m) and creating conceptual models of injectite geometries, (2) performing seismic convolution modelling to investigate how these would be imaged in seismic data, and (3) compare these synthetic seismic images to actual 3D seismic from the well-investigate Grane Field.Our results show that despite injectites being below seismic resolution, small-scale sand injectites can be detected in seismic data. They are more likely to be detected with high thickness (> 5 m), steep dip (> 30°), densely spaced sand injectites, and homogeneous background stratigraphy. Furthermore, as fraction of sand injectites increases the top reservoir amplitude will decrease. Moreover, comparison of the synthetic seismic images with real seismic data from the Grane Field indicates that the low-amplitude anomalies and irregularities observed above the reservoir may be a result of the overlying sand injectites. Additionally, the comparison strongly suggests that the Grane Field hosts sand injectites that are thicker and located further away from the top reservoir than what is indicated by well observations. These results may be used to improve well planning and develop reservoirs with overlying sand injectites.Supplementary material: A PDF file containing all the seismic modelling results allowing the reader to flip back and forth between the different models is available at https://www.doi.org/10.6084/m9.figshare.14333102 . Well logs from well 25/11-18 T2 are available at https://factpages.npd.no/pbl/wellbore_documents/2358_25_1_18_COMPLETION_REPORT_AND_LOG.pdf

Targeting and Developing the Remaining Pay in an Ageing Field: the Ovhor Field Experience

Understanding the complexity in the distribution of hydrocarbon in a simple structure with flow baffles and connectivity issues is critical in targeting and developing the remaining pay in a mature asset. Subtle facies changes (heterogeneity) can have drastic impact on reservoir fluids movement, and this can be crucial to identifying sweet spots in mature fields. This study evaluated selected reservoirs in Ovhor Field, Niger Delta, Nigeria with the objective of optimising production from the field by targeting undeveloped oil reserves or bypassed pay and gaining an improved understanding of the selected reservoirs to increase the company's reserves limits. The task at the Ovhor field, is complicated by poor stratigraphic seismic resolution over the field. 3-D geological (Sedimentology and stratigraphy) interpretation, Quantitative interpretation results and proper understanding of production data have been used in recognizing flow baffles and undeveloped compartments in the field. The full field 3-D model was constructed in such a way as to capture heterogeneities and the various compartments in the field. This was crucial to aid the simulation of fluid flow in the field for proper history matching, future production, prediction and design of well trajectories to adequately target undeveloped oil in the field. Reservoir property models (Porosity, Permeability and Net-To-Gross) were constructed by biasing log interpreted properties to a defined environment of deposition model whose interpretation captured the heterogeneities expected in the studied reservoirs. At least, two scenarios were modelled for the studied reservoirs to capture the range of uncertainties. This integrated approach led to the identification of bypassed oil in some areas of the selected reservoirs and an improved understanding of the studied reservoirs. Dynamic simulation and production forecast on the 4 reservoirs gave an undeveloped reserve of about 3.82 MMstb from two (2) identified oil restoration activities. These activities included side-tracking and re-perforation of existing wells. New wells have been drilled to test the results of our studies and the results confirmed our findings.

Reservoir characterization and volumetric estimation of reservoir fluids using simulation and analytical methods: a case study of the coastal swamp depobelt, Niger Delta Basin, Nigeria

Suites of wireline well logs and three-dimensional (3D) seismic data were integrated to characterise the reservoir and estimate the hydrocarbon in Otigwe field, coastal swamp depositional belt, Niger Delta. The 3D seismic data were used to generate seismic sections through which fourteen faults and two horizons of interest were mapped across four wells. Depth structural map generated from the mapped faults and horizons of interest shows that the trapping mechanism within the field is fault-supported anticlinal structural trap. The four available wells were correlated using lithostratigraphic correlation to establish two reservoir continuities (Reservoir A and B). The estimated reservoir fluid volume at surface condition using reservoir simulation and modelling software is 59 MMstb for reservoir A and 25.70 MMstb for reservoir B. On the other hand, the estimated reservoir fluid volume at surface condition using analytical method is 52.58 MMstb for reservoir A and 18.85 MMstb for reservoir B. Using reservoir simulation and modelling software, the average net-to-gross ratio and shale volume for reservoir A range from 0.86 to 0.89 and 0.11 to 0.14, respectively, while for reservoir B the range is between 0.69 to 0.82 and 0.18 to 0.31, respectively. On the flipside using the analytical method, the average net-to-gross ratio and shale volume for reservoir A is 0.78 and 0.22, respectively. The results from the volumetric estimation of reservoir fluids showed close values using both methods and reservoir A is more prolific compare to B.