3D seismic vintage in Seg Y data format of this study area was among the data set collected from Total E&P Nigeria for review and interpretation. This seismic volume was QC/QA before It was loaded for detailed 3D seismic interpretations using the appropriate Geology and Geophysics (G&G) software, (i.e. Petrel) a ‘Schlumberger trademark’ for comprehensive seismic interpretation workflow, structural and stratigraphic interpretation. The generation of synthetic seismogram to determine the horizons or picks of interest to be interpreted on the seismic profile, fault and horizon interpretation, generation of depth converted contour maps and generation of structural model were carried out (Illo, 2015) as shown in Figure 4.18a. The 3D seismic interpretation of WABI field involved fault picking and correlation, which was done to establish the regional structural framework of the field. The seismic section is characterized by low to high amplitudes that continues and terminates at faulted zones. Two major faults and one minor fault were identified in Wabi as F1 and F2 Figure 4.18b. One of the main aims for this interpretation was to identify the stress regime existing in Wabi field based on normal, strike-slip and reverse (Anderson, 1951; Zoback, 2007) to know the appropriate model to be used for the estimation of in situ stress magnitudes and directions.
This paper presents a detailed reservoircharacterization of three wells in “Datom” Oil Field, NigerDelta using well logs data. The distributions and thicknesses of sand bodies were determined within each of the wells in the field using interactive petrophysical (IP) software. The quantitative and qualitative ana- lysis were done for the three exploration wells with the depth ranges of 8700-9200ft for Datom North well , 8900-9400ft for Datom West well, and 9000-9500ft for Datom East well. Two distinctive porous sand bodies were identified across the field (A and B), Datom North has it reservoirs as 1A (8815- 8903ft) and 1B (9100-9157ft), Datom West has its reservoir as 2A (8996-9095ft) and 2B (9263- 9321ft) and Datom East as 3A (9101-9219ft) and 3B (9357-9418ft). Petrophysical evaluation was made from a suite of wire-line logs comprising of gamma ray, resistivity, neutron and density logs of the wells. The average porosity values obtained are in the range of 0.18-0.22 with average net pay permeability values ranging from 322.70mD to 733.20mD. The water saturation obtained for each reservoir unit in combination with the resistivity index was used to prove the presence of hydrocarbon in the sand units. The hydrocarbon saturation of the reservoirs are in the range of 0.6-0.7 across the prospect zones with gas effect of the combination logs of neutron and density indicating the hydrocar- bon accumulation is predominantly gas. The average net to gross ratio across the reservoirs (0.7-0.9) is defined using an average porosity (∅) and volume of clay (𝑉 𝑐𝑙𝑎𝑦 ) cut offs values of ≥ 0.1 𝑎𝑛𝑑 ≤ 0.5 re- spectively. With a moveable hydrocarbon index (MHI=𝑆 𝑊 ⁄ 𝑆 𝑋𝑂 ) less than 0.7 across the sand units, it shows favorable hydrocarbon moveability in the reservoirs. The results clearly revealed that the gas bearing sand units have good reservoir potentials favorable for hydrocarbon production.
The study investigated 3D seismic velocities as playing a vital role in accurate depth conversion and volumetrics using the “Akos field” as a case study to be revisited for previously bypassed information as well as enhanced information on estimation of target depth and volumetrics. The petrophysical properties revealed a porosity that ranged from 20% to 30%.. Main oil accumulations lie between 6500ft subsea and 11500ft subsea at the central part of the field. Various velocity models were applied to depth conversion and volumetrics and the most suitable with respect to volumetric output, closeness to zero offset, “fit to well” and formation dependence was identified. This study proved to be useful in the creation of a reference material for marginalfield operators and operator of fields that are being revisited.
The entire Delta is composed of three major formations; Akata, Agbada and Benin Formations (Figure 3). The Benin Formation is the upper alluvial coastal plain deposit of the NigerDelta Complex. It extends from the west NigerDelta across the entire NigerDelta area and to the south beyond the present coastline. The Benin Formation deposited in a continental fluviatile environment and composed almost entirely of non-marine sandstone, consists of coarse-grained sandstones, lignite streaks and wood fragments with minor intercalation of shales. Benin Formation is of Miocene to younger age and has a variable thickness that exceeds 1,820 m.  In the subsurface, it is of Oligocene age in the north becoming progressively younger southwards but ranges from Miocene to Recent. Very little hydrocarbon accumulation
The aim of this study involves evaluating the volume of hydrocarbon within Tymot field. In order to achieve this purpose, certain objectives must be met: to evaluate petrophysical parameters such as porosity, water saturation, net and gross sand thickness, net oil and gas, and fluid contacts for hydrocarbon bearing sands; to identify and map bearing sands; and to estimate volume of hydrocarbon existing within the mapped reservoir.
These Depobelts can be thought of as transient basinal areas succeeding one another in space and time as the delta progradedSouthward. When further subsidence of the basin could no longer be accommodated the focus of sediment deposition shifts seaward forming a new depobelt (Doust and Omatsola, 1990). At the same time synsedimentary and most post-sedimentary faulting would cease within the abandoned depobelt. Therefore, Depobelts form the structural and depositional active portion of the delta at each stages of its development (Doust and Omatsola, 1990; Tuttle et al., 1999)Figure 2.Schematic diagram of the NigerDelta showing the Depobelts and the regional faults (Modified from Doust and Omotsola, (1990) and Stacher (1995).
The quest for optimum method of hydrocarbon production has been an issue which many oil and gas companies are interested in. Alvarado and Manrique (2010) have stated that the effort of industries to increase production by the use of large capital investments to enhance oil recovery sometimes prove futile. One of the major ways of resolving this issue is through hydrocarbon reservoir properties modeling. This study has been carefully and thoroughly carried out in aspects focusing mainly on reservoir modeling of “Y” field, NigerDelta using an integrated Seismic approach and well log analysis.
The natural gas transmission pipeline for a typical marginal oil and gas field in Nigerdelta has been designed. A secondary data of the field gas was obtained and empirical study was carried out to determine the nature of the gas. The gas flow rate, pressure, temperature was collated and used to design the gas pipeline.
The NigerDelta which is made up of one petroleum system; the Tertiary NigerDelta (Akata- Agbada) Petroleum System has been extensively studied with publications from authors including Short and Stauble (1967), Ekweozor and Daukoru (1984), Tuttle et al. (1999), and Nwajide (2013). Others include Doust and Omatsola (1990), Reijers et al. (1997), Evamy et al. (1978), Hack et al. (2000), Nwachukwu (1986), and Whiteman (1982). It is composed of three main lithologic units; the basal marine Akata Formation of Palaeocene-Recent age with dominantly thick dark grey shale and some sand or silt in the upper part. It is the main hydrocarbon source rock in the NigerDelta. The paralic Agbada Formation of Eocene to Pleistocene age overlies the Akata Formation and is composed of alternating sandstone, siltstone and shale, and forms the main reservoir rock in the NigerDelta petroleum system with hydrocarbons being produced from sandstone and unconsolidated sands. The Benin Formation of Oligocene age is the topmost and most shallow part of the deltaic clastic wedge overlying the Agbada Formation. It is made up of continental deposits with over 70% of sands.
Reservoircharacterization has always been a challenging domain in oil and gas industry for a long time. There are many approaches and methodologies that are applied with the aim of establishing statistically significant correlations between reservoir storage and fluid flow characteristics. Ranking of obtained correlations and their optimized clustering are used for rock typing that aims to derive representative model equations for static modelling. However, selection and validation of these methods of clustering the similarities still face hurdles due to complexities in pore- space conditions and reservoir geometry. Petrophysicists need to adequately understand these complexities in order to derive representative models for accurate predictions of petrophysical characteristics, mainly, between fluid flow (permeability) and reservoir storage (porosity) across the field.
Deposition of the overlying Agbada Formation, the major petroleum-bearing unit, began in the Eocene and continues into the Recent. The formation consists of paralic siliciclastics over 3,700meters thick and represents the actual deltaic portion of the sequence. The clastics accumulated in delta- front, delta-topset, and fluvio-deltaic environments. The Agbada Formation is overlain by the third formation, the Benin Formation, a continental latest Eocene to Recent deposit of alluvial and Upper coastal plain sands that are up to 2,000m thick (Avbovbo, 1978).
In view of this application, the availability of surface displacement data is here hypothesized according to the characteristics and the typical errors associated with InSAR measurement surveys. In one case, we assume that surface displacement measurements from a reference reservoir system are made at a single collection time, for example, at reservoir depletion; in another, two measurements collection times are considered, at reservoir depletion, when gas pressure is at its minimum, and after gas pressure has partially recovered. In each test, the ensemble of geomechanical simulations is rerun to determine if the updated ensemble of reservoir parameters provides a parameter structure that produces results in agreement with the measurements from the reference state, i.e., to verify if the ES scheme has been successful in calibrating the model to a reasonable degree. In addition, sensitivity analyses are performed to gain insights into the influence of (i) displacement measurement errors, and (ii) number of measurements.
The controls of bioturbation on reservoir porosity and permeability of onshore, Xena- 14, NigerDeltareservoir rock was conducted. Study revealed a spread of Cruziana to Skolithosichnofacies with average porosity of 23.3% and permeability of 328.8mD over all the study interval covering all the eleven (11) recognized sandstone and heterolithic lithofacies intervals. An average porosity of 23.44% and permeability of 444.6mDwas recorded for the bioturbated sandstone intervals while average values of 23.3% and 322.9mD was deduced for the unbioturbated sandstone facies excluding the heterolithic intervals. The samples generally displayedmoderate to sparse bioturbation (0-30%) andintensity of 2(BI) with the more bioturbated facies intervals displayingboosted porosity and permeability values indicating that bioturbation as much as the grain dispositionof thehigh energy onshore settings positively controls reservoir quality and consequently be applied in exploration and identification of prospective reservoirs.
Reservoircharacterization of the ALO WELL was carried out using sedimentological attributes and integrated reservoir quality of the sandbodies The porosity values show good to excellent porosity and very good permeabilities. The reservoir quality which is excellent is dependent on the facies grain sizes and sorting which are fine to medium grained and a moderately depicting a moderately high energy environment. The bioturbation structures also enhance fluid flow, hence the high vertical permeability values. The various parameters above indicate deposition in a tidally influenced environment probably a distributary channel fill.
Seven main lithufacies were identified overall the cured sequence. These facies were described based on the lithologies. Grain size, primary and biogenic structures as observed. This was done based on the classification and nomenclature scheme of Reijers et al, 1993 which follows the terminology proposed in the regional Nigerdelta study by Core laboratories in 1993.
This facies is easily recognizable in the macroscopic study of the cores with its red color. Horizontal bedding is the most important sedimentary structures observed in the study of cores. The most important phenomenon in this facies is the presence of paleo- sol horizon (Figure 3 and Figure 6) that indicates subaerial exposure for a period of time. Like other facies of the Burgan Formation, this facies is mainly composed of quartz (more than 95% of the framework). Other grains are chert and opaque minerals. Moderate sorting is seen in quartz grains, but the roundness is weak. Presence of oxi- dized plant debris is common feature of this facies in the studied thin sections. This fa- cies along with the F1 are observed in the lower parts of the Burgan Formation. This fa- cies is developed in rivers and distributary channels of the delta plain setting  .
Abstract: Although Habiganj Gas Field is one of the best gas field with good reservoir characteristics but it is least analyzed. This paper presents the critical view on four wells (HBJ -7, HBJ-8, HBJ-9, and HBJ-10) of upper gas sand using wire line log data for further development. It is found from the analyses data that a thick zone (~40 m, depth between 1410 to 1450 m) of Bokabil Formation in well no. 8 HBJ-8 shows greater porosity (>43%) and permeability (5-16 D) which may be the indicators of a big fracture zone within the reservoir that yet to be noticed. The similar phenomenon also observed in HBJ-9 with laser thickness. The consistency in porosity and permeability of different wells shows that the reservoir of Habiganj Gas Field is well-sorted. However the stratigraphical model shows that the structure of Habiganj Gas field is almost symmetrical and trending SSE, which supports the structure of Surma Basin. The multi-log 3-D model shows both lithology and stratigraphy, which also resemblance with the lithology and stratigraphy of the Surma Basin.
There is heterogeniety as a result of bioturbation and cementation. Interbedded shale/heterolithics at the upper part will therefore form a baffle to vertical flow. Conversely, the amalgamated channel contains no clay materials and shows a blocky shape in gamma ray log with a good vertical permeability than the tidal channel. Generally, the single to multi-storey channel sandstone forms the best reservoir in the Obah reservoir sand of study and cut into tidal mouth bar/shoreface sandstone types. The lobe-shaped sandstone bodies are made up of estuarine mouth bar/shoreface and tidal flat sandstones. About 20% of the entire reservoir sand is made up of this sandstone body type. They are less laterally extensive than the sheet-like sandstone but have similar properties. Their porosity ranges from 15% to 23% and permeability ranges from 50MD to 100MD. It is characterized by a moderately sorted fine grained sandstone beds which are carbonaceous.
This study focuses on the application of 3D static model using 3-D seismic and well log data for proper optimiza- tion and development of hydrocarbon potential in KN field of NigerDelta Province. 3D Seismic data were used to generate the input interpreted horizon grids and fault polygons. The horizon which cut across the six wells was used for the analysis and detailed petrophysical analysis was carried out. Structural and property modeling (net to gross, porosity, permeability, water saturation and facies) were distributed stochastically within the con- structed 3D grid using Sequential Gaussian Simulation and Sequential Indicator Simulation algorithms. The reservoir structural model show system of different oriented growth faults F1 to F6. Faults 1 and Fault 4 are the major growth faults, dipping towards south-west and are quite extensive. A rollover anticline formed as a result of deformation of the sediments deposited on the downthrown block of fault F1. The other faults (2, 3, 5 and 6) are minor fault (synthetic and antithetic). The trapping mechanism is a fault assisted anticlinal closure. Results from well log analysis and petrophysical models classified sand 9 reservoir as a moderate to good reservoir in terms of facies, with good porosity, permeability, moderate net to gross and low water saturation. The volume- tric calculation of modeled sand 9 horizon reveals that the (STOIIP) value at the Downthrown and Ramp seg- ment are 15.7 MMbbl and 3.8 MMbbl respectively. This implies that the mapped horizon indicates hydrocarbon accumulation in economic quantity. This study has also demonstrated the effectiveness of 3-D static modeling technique as a tool for better understanding of spatial distribution of discrete and continuous reservoir proper- ties, hence, has provided a framework for future prediction of reservoir performance and production behavior of sand 9 reservoir. However, more horizontal wells should be drilled to enhance optimization of the reservoir.
The Akata Formation is the under compacted, over pressured, marine prodeltamegafacies of theNiger Delta basin. It is composed mainly of marine shale with occasional turbidite sandstone andsiltstone (Short and Stauble, 1967). The thickness ranges from 600m to over 6000m and depends on the shale diapirism. It is thought to be the sources rock of the Nigerdelta complex. Abundance of planktonic foraminifera assemblage indicates deposition of the Akata shale on a shallow marine environment (Whiteman 1982).