Checkshot Data Research Articles

Lithology and fluid prediction from simultaneous seismic inversion over Sandfish field, Niger Delta, Nigeria

Seismic inversion has been widely practiced in the oil and gas industry because it generates broad bandwidth of impedance data which maximizes vertical resolution and minimizes tuning effects. The lack of accurate prediction of lithology and fluid content of subtle features identified in seismic data acquired over the Sandfish field, Niger Delta, Nigeria necessitated the use of seismic inversion. In this paper, simultaneous seismic inversion is adopted to integrate seismic and well data for quantitative interpretation and uncertainty assessment of the subsurface reservoirs in the Sandfish field. Three Sandfish (Sfn) wells with the required petrophysical logs, check-shot data, high quality 3D seismic data of five angle stacks (6–12°, 12–18°, 18–26°, 26–32°, and 32–42°) were used for the analysis. A feasibility study including cross-plots of petrophysical and elastic properties from well data was first carried out to establish rock property relationships in the interval of interest. Biot-Gassmann fluid substitution analysis was also used to reveal sensitivity of rock properties to pore-fill type. Low frequency (0–2 Hz) models were generated from interpolation of high-cut-filtered P-sonic, S-sonic, and density logs guided by interpreted seismic horizons. The low frequency models were used to broaden the spectrum to estimate elastic volumes. The five partial angle stacks were simultaneously inverted using Jason’s Rock-Trace® inversion software which iterated trial inversions until the model sufficiently matched the seismic data. The inverted P-impedance (ZP), Simpedance (ZS), and density (ρ) were used to derive Poisson’s ratio (σ), volume of sand (Vsand), lambda-rho (λρ), and mu-rho (µρ). The cross-plot of λρ with µρ from well data looks similar to that from inverted results. Sands and shales are discriminated on the basis of sands having low values of µρ. Hydrocarbon-bearing sands are differentiated from water-bearing sands and shales on the basis of having lowest values of λρ. The Biot-Gassmann fluid substitution analysis at reservoir N-01 reveals typical class III amplitude variation with angle (AVA) responses for low-impedance hydrocarbon sands. The lithology and fluid prediction maps extracted from Vsand and σ at the N-01 seismic horizon show variation in lithology and fluid types for the entire volume. The inversion products reveal heterogeneities in the reservoirs away from well control validated by a blind well test. Hence, the study shows that rock-property model from a simultaneous inversion is an effective predictive tool for lithology and fluid types which in turn can guide well placement and predict reservoir development in the field of study.

ANALISA POTENSI MINYAK DAN GAS BUMI DENGAN ATRIBUT SEISMIK PADA BATUAN KARBONAT LAPANGAN *ZEFARA* CEKUNGAN SUMATRA SELATAN

ABSTRACT*Zefara* Field formation Baturaja on South Sumatra Basin is a reservoir carbonate and prospective gas. Data used in this research were 3D seismik data, well logs, and geological information. According to geological report known that hidrocarbon traps in research area were limestone lithological layer as stratigraphical trap and faulted anticline as structural trap. The study restricted in effort to make a hydrocarbon accumulation and a potential carbonate reservoir area maps with seismic attribute. All of the data used in this study are 3D seismic data set, well-log data and check-shot data. The result of the analysis are compared to the result derived from log data calculation as a control analysis. Hydrocarbon prospect area generated from seismic attribute and are divided into three compartments. The seismic attribute analysis using RMS amplitude method and instantaneous frequency is very effective to determine hydrocarbon accumulation in *Zefara* field, because low amplitude from Baturaja reservoir. Low amplitude hints low AI, determined high porosity and high hydrocarbon contact (HC). Keyword: Baturaja Formation, RMS amplitude seismic attribute, instantaneous frequency seismic attribute

Geometry, kinematics and dynamic characteristics of a compound transfer zone: the Dongying anticline, Bohai Bay Basin, eastern China

AbstractThe Dongying anticline is an E-W striking complex fault-bounded block unit which located in the central Dongying Depression, Bohai Bay Basin. The anticline covers an area of approximately 12 km2. The overlying succession, which is mainly composed of Tertiary strata, is cut by normal faults with opposing dips. In terms of the general structure, the study area is located in a compound transfer zone with major bounding faults to the west (Ying 1 fault) and east (Ying -8 and -31 faults). Using three-dimensional seismic data, wireline log and checkshot data, the geometries and kinematics of faults in the transfer zone were studied, and fault displacements were calculated. The results show that when activity on the Ying 1 fault diminished, displacement was transferred to the Ying -8, Ying -31 and secondary faults so that total displacement increased. Dynamic analysis shows that the stress fields in the transfer zone were complex: the northern portion was a left-lateral extensional shear zone, and the southern portion was a right-lateral extensional shear zone. A model of potential hydrocarbon traps in the Dongying transfer zone was constructed based on the above data combined with the observed reservoir rock distribution and the sealing characteristics of the faults. The hydrocarbons were mainly expulsed from Minfeng Sag during deposition periods of Neogene Guantao and Minghuazhen Formations, and migrated along major faults from source kitchens to reservoirs. The secondary faults acted as barriers, resulting in the formation of fault-bound compartments. The high points of the anticline and well-sealed traps near secondary faults are potential targets. This paper provides a reservoir formation model of the low-order transfer zone and can be applied to the hydrocarbon exploration in transfer zones, especially the complex fault block oilfields in eastern China.

3-D predrill overpressure prediction using prestack depth-migrated seismic velocity in a field of southwestern Malay Basin

Quantitative predrill pore pressure prediction is very important for reducing the drilling hazards. In many Tertiary basins, generation of overpressure is mainly by compaction disequilibrium due to high deposition rate and low permeability in shale. In the Malay Basin, high geothermal gradient (i.e., 40–60 °C/km) and high heat flow also play an important role in generating overpressure at shallow depth. This study describes the utilization of 3-D prestack depth-migrated seismic interval velocity for predrill pore pressure prediction in a field of southwestern Malay Basin. The quality of 3-D prestack depth-migrated seismic interval velocity was enhanced by calibration with check-shot data. Modified Gardner’s equation was used to generate the 3-D density cube from the interval velocity. The Eaton and Bowers methods were used to compute and predict pore pressure values from the seismic velocity. The Eaton method with standard exponent for seismic velocity gave good prediction in the shallower zone where overpressure is caused by undercompaction mechanism, whereas underpredicted the high pore pressure at the greater depth where fluid expansion is the cause of overpressure. However, the overpressures were predicted quite well by applying correction on the Eaton method for fluid expansion mechanism.

Reservoir Modeling of Carbonate on Fika Field: The Challenge to Capture the Complexity of Rock and Oil Types

DOI: 10.17014/ijog.v1i2.181The carbonate on Fika Field has a special character, because it grew above a basement high with the thickness and internal character variation. To develop the field, a proper geological model which can be used in reservoir simulation was needed. This model has to represent the complexity of the rock type and the variety of oil types among the clusters. Creating this model was challenging due to the heterogeneity of the Baturaja Formation (BRF): Early Miocene reef, carbonate platform, and breccia conglomerate grew up above the basement with a variety of thickness and quality distributions. The reservoir thickness varies between 23 - 600 ft and 3D seismic frequency ranges from 1 - 80 Hz with 25 Hz dominant frequency. Structurally, the Fika Field has a high basement slope, which has an impact on the flow unit layering slope. Based on production data, each area shows different characteristics and performance: some areas have high water cut and low cumulative production. Oil properties from several clusters also vary in wax content. The wax content can potentially build up a deposit inside tubing and flow-line, resulted in a possible disturbance to the operation. Five well cores were analyzed, including thin section and XRD. Seven check-shot data and 3D seismic Pre-Stack Time Migration (PSTM) were available with limited seismic resolution. A seismic analysis was done after well seismic tie was completed. This analysis included paleogeography, depth structure map, and distribution of reservoir and basement. Core and log data generated facies carbonate distribution and rock typing, defining properties for log analysis and permeability prediction for each zone. An Sw prediction for each well was created by J-function analysis. This elaborates capillary pressure from core data, so it is very similar to the real conditions. Different stages of the initial model were done i.e. scale-up properties, data analysis, variogram modeling, and then the properties were distributed using the geostatistic method. Finally, after G&G collaborated with petrophysicists and reservoir engineers to complete their integrated analysis, a geological model was finally created. After that, material balance was needed to confirm reserve calculations. The result of OOIP (Original Oil in Place) and OGIP (Original Gas in Place) were confirmed, because it was similar to the production data and reservoir pressure. The model was then ready to be used in reservoir simulation.

Erratum: Corrigendum: Lusi mud eruption triggered by geometric focusing of seismic waves

Nature Geoscience 6, 642–646 (2013); published online 21 July 2013; corrected after print 28 August 2014. In our 2013 article1, we adopted a published velocity profile2 described as check-shot data, which we used as an input constraint for our numerical simulations. We were subsequently alerted to artefacts in that velocity profile, so below we present revised simulation results, based on additional data.

Seismic While Drilling (SWD) with a Rotary Percussive Sounding System (RPSS)

Seismic while drilling (SWD) with a rotary percussive drill used as the seismic source is presented. In addition to saving time by collecting seismic data while drilling, SWD also has the advantage of collecting a high data density with no additional effort and has a signal with a broad frequency spectrum. The only disadvantage is its signal-to-noise ratio is lower than many other seismic sources, although the signal-to-noise ratio is quite sufficient. The discussed methodology includes the triggering system and the stacking approach used to improve the signal-to-noise ratio. An example of SWD data is presented and compared to traditional down-hole (check-shot) data. Other examples of SWD are presented to demonstrate some of the data acquisition possibilities.

The Use of Seismic Attributes to Enhance Structural Interpretation of Z-Field, Onshore Niger Delta

An integrated approach to the study of the structural patterns and seismic attributes was carried out on the Z-field using a 3D seismic data covering approximately 56 Km2 of western belt of the Niger Delta, checkshot data for well to seismic tie and log information for six wells from the field. This study aimed at investigating the available prospects, the responses of the basic seismic attributes to structural and stratigraphic elements within the study area. In all, six hydrocarbon bearing levels were delineated from well logs and correlated across the field. These horizons were analysed and petrophysical parameters estimated. An integration of well and seismic data was done by applying a time-depth relationship to identify where the hydrocarbon bearing sands from well posts on the seismic lines. These studies revealed two major regional growth faults (F1 and F5) dipping in the NE-SW directions and crestal faults (F4) dipping in the northern direction. The north dipping crestal fault F4 is responsible for holding the hydrocarbon in the proven closure A. The northernmost regional growth fault F1 is responsible for trapping the hydrocarbon in the prospect closure B in the north eastern part of the field. The closure C prospect is a four way dip closure to the spill point but becomes fault assisted on regional growth faults F1 and F5 at deeper levels. The trapping mechanism identified from our interpretation indicates that the field is characterized mostly by fault assisted closures and a few four way closures. The fault zones are identified by distinct displacement of walls and amplitude distortions towards the fault zones identified on the seismic sections and the extracted amplitude maps. At the south-western part of the field, using only seismic Stratigraphic approach, a part of fault F5 was too subtle to be identified, and this may lead to missing out on the potentials of the identified closure C prospect. Thus, where conventional seismic interpretation has failed, seismic attribute analysis complements.

Building tilted transversely isotropic depth models using localized anisotropic tomography with well information

Tilted transverse isotropy (TTI) is increasingly recognized as a more geologically plausible description of anisotropy in sedimentary formations than vertical transverse isotropy (VTI). Although model-building approaches for VTI media are well understood, similar approaches for TTI media are in their infancy, even when the symmetry-axis direction is assumed known. We describe a tomographic approach that builds localized anisotropic models by jointly inverting surface-seismic and well data. We present a synthetic data example of anisotropic tomography applied to a layered TTI model with a symmetry-axis tilt of 45 degrees. We demonstrate three scenarios for constraining the solution. In the first scenario, velocity along the symmetry axis is known and tomography inverts for Thomsen’s [Formula: see text] and [Formula: see text] parame-ters. In the second scenario, tomography inverts for [Formula: see text], [Formula: see text], and velocity, using surface-seismic data and vertical check-shot traveltimes. In contrast to the VTI case, both these inversions are nonunique. To combat nonuniqueness, in the third scenario, we supplement check-shot and seismic data with the [Formula: see text] profile from an offset well. This allows recovery of the correct profiles for velocity along the symmetry axis and [Formula: see text]. We conclude that TTI is more ambiguous than VTI for model building. Additional well data or rock-physics assumptions may be required to constrain the tomography and arrive at geologically plausible TTI models. Furthermore, we demonstrate that VTI models with atypical Thomsen parameters can also fit the same joint seismic and check-shot data set. In this case, although imaging with VTI models can focus the TTI data and match vertical event depths, it leads to substantial lateral mispositioning of the reflections.

Reducing Uncertainty With Seismic Measurements While Drilling

This paper discusses both seismic checkshot data inversion and seismic waveform look-ahead imaging while drilling. We investigate the estimation under real-time data uncertainties of interval velocity profiles calculated from checkshot measurements acquired while drilling. It is found that real-time checkshots may suffer from downhole time-picking errors in addition to an unpredictable clock drift uncertainty. We developed a method to account for these uncertainties and to provide drillers with reliable formation interval velocity models in real time, regardless of whether the direct arrival times are detected by an automated downhole process or picked by an interpreter uphole once the seismograms have been transmitted to the surface through mud-pulse telemetry. By quantifying the posterior uncertainties in the interpreted velocity measurements, we then demonstrate: 1) the value of making the seismic waveforms recorded in downhole memory available in real time at the surface and 2) the benefit of quantifying and accounting for the standard deviations, which describe the downhole time-picking errors, in the case when the real-time seismograms are not available. This is exemplified with the application of the proposed methodology to measurements collected in deep water in the Gulf of Mexico, with inverted real-time velocity models that are consistent and comparable to the ones obtained from travel times picked after the drilling is complete. Finally, a case study is shown combining real-time checkshot inversion and downhole-to-surface transmitted seismic waveforms to look ahead while drilling for an optimal well steering in high-probability hydrocarbon sands.

Variation of vertical stress in the Carnarvon Basin, NW Shelf, Australia

Variations in vertical stress magnitudes can be attributed to lateral facies variations, diagenesis, localized uplift and disequilibrium compaction overpressure. Vertical stress magnitudes have been calculated using density and checkshot data from 47 wells in the Carnarvon Basin, on the NW Shelf of Australia. The vertical stress ranges from 20.2 MPa km − 1 to 23.8 MPa km − 1 below seabed; demonstrating a significant variation across the basin. The largest vertical stress magnitudes were calculated for the Dampier Sub-Basin, the eastern Barrow Sub-Basin and on the Peedamullah Shelf. The smallest vertical stress magnitudes were calculated in the Kangaroo Syncline, the western Barrow Sub-Basin and offshore across the Exmouth Plateau. High rock densities, thus, high vertical stress magnitudes, can be due to uplifted rock that is over-compacted relative to its current depth. In the Carnarvon Basin, areas of elevated vertical stress magnitudes correspond to areas of identified uplift. Uplift at the Bambra Anticline has previously been estimated to be approximately 900 m. Calculations within the Bambra-4 well demonstrate that a 900 m increase in burial depth of a regionally consistent lithostratigraphic unit (the Muderong Shale) equates to a 0.22 g cm − 3 increase in rock density. Thus, the difference between uplifted, over-compacted rock and normally-compacted rock (no uplift) is equivalent to a difference in the vertical stress magnitude of 2.1 MPa km − 1 at the Bambra Anticline. This value, totalling the difference between over-compacted (uplifted) and normally-compacted sedimentary rock (2.1 MPa km − 1 ), accounts for some part of the 3.6 MPa km − 1 variation in vertical stress magnitude observed across the Carnarvon Basin. Therefore, recent tectonic uplift has had a significant impact on the present-day magnitude of the vertical stress and is interpreted to be responsible for the majority of observed variation of vertical stress in the Carnarvon Basin.

Time-depth and velocity trend analysis of the Wasagu field

It is known in the North Sea basin that depths to major reflectors as determined from surface seismic data are often larger than the well depths. From this study of data sets from Wasagu field in the Niger Delta, it has been found that this statement might not hold in an area where rapid lateral variations in the subsurface (varying structural relief) cause big difference in bed velocities or where anisotropy is severe. From a combination of seismic data and checkshot data sets, which lie three wells, a relationship between seismic velocity and checkshot average velocity in Wasagu field, was derived. This relationship is the conversion factor that enables us to predict average velocity values from seismic velocity values. Using this factor, seismic times of a well have been converted to well depths. From well information alone, second degree polynomial fit has been used to convert seismic times of this virgin area to depth and from statistical analysis, it was discovered that the standard deviation of depth results got by causing the polynomial fit was 105.1ft and that obtained by using the conversion factor was 42.61ft. Nigerian Journal of Physics Vol. 16(2) 2004: 66-75

Constraining stress magnitudes using petroleum exploration data in the Cooper–Eromanga Basins, Australia

The magnitude of the in situ stresses in the Cooper–Eromanga Basins have been determined using an extensive petroleum exploration database from over 40 years of drilling. The magnitude of the vertical stress ( S v) was calculated based on density and velocity checkshot data in 24 wells. Upper and lower bound values of the vertical stress magnitude are approximated by S v = (14.39 × Z) 1.12 and S v = (11.67 × Z) 1.15 functions respectively (where Z is depth in km and S v is in MPa). Leak-off test data from the two basins constrain the lower bound estimate for the minimum horizontal stress ( S hmin) magnitude to 15.5 MPa/km. Closure pressures from a large number of minifrac tests indicate considerable scatter in the minimum horizontal stress magnitude, with values approaching the magnitude of the vertical stress in some areas. The magnitude of the maximum horizontal stress ( S Hmax) was constrained by the frictional limits to stress beyond which faulting occurs and by the presence of drilling-induced tensile fractures in some wells. The maximum horizontal stress magnitude can only be loosely constrained regionally using frictional limits, due to the variability of both the minimum horizontal stress and vertical stress estimates. However, the maximum horizontal stress and thus the full stress tensor can be better constrained at individual well locations, as demonstrated in Bulyeroo-1 and Dullingari North-8, where the necessary data (i.e. image logs, minifrac tests and density logs) are available. The stress magnitudes determined indicate a predominantly strike-slip fault stress regime ( S Hmax > S v > S hmin) at a depth of between 1 and 3 km in the Cooper–Eromanga Basins. However, some areas of the basin are transitional between strike-slip and reverse fault stress regimes ( S Hmax > S v ≈ S hmin). Large differential stresses in the Cooper–Eromanga Basins indicate a high upper crustal strength for the region, consistent with other intraplate regions. We propose that the in situ stress field in the Cooper–Eromanga Basins is a direct result of the complex interaction of tectonic stresses from the convergent plate boundaries surrounding the Indo-Australian plate that are transmitted into the center of the plate through a high-strength upper crust.

Wavelet extractor: A Bayesian well-tie and wavelet extraction program

We introduce a new open-source toolkit for the well-tie or wavelet extraction problem of estimating seismic wavelets from seismic data, time-to-depth information, and well-log suites. The wavelet extraction model is formulated as a Bayesian inverse problem, and the software will simultaneously estimate wavelet coefficients, other parameters associated with uncertainty in the time-to-depth mapping, positioning errors in the seismic imaging, and useful amplitude-variation-with-offset (AVO) related parameters in multi-stack extractions. It is capable of multi-well, multi-stack extractions, and uses continuous seismic data-cube interpolation to cope with the problem of arbitrary well paths. Velocity constraints in the form of checkshot data, interpreted markers, and sonic logs are integrated in a natural way. The Bayesian formulation allows computation of full posterior uncertainties of the model parameters, and the important problem of the uncertain wavelet span is addressed uses a multi-model posterior developed from Bayesian model selection theory. The wavelet extraction tool is distributed as part of the Delivery seismic inversion toolkit. A simple log and seismic viewing tool is included in the distribution. The code is written in Java, and thus platform independent, but the Seismic Unix (SU) data model makes the inversion particularly suited to Unix/Linux environments. It is a natural companion piece of software to Delivery, having the capacity to produce maximum likelihood wavelet and noise estimates, but will also be of significant utility to practitioners wanting to produce wavelet estimates for other inversion codes or purposes. The generation of full parameter uncertainties is a crucial function for workers wishing to investigate questions of wavelet stability before proceeding to more advanced inversion studies.

Horizon velocity analysis for depth conversion – A case study

This case study compares three methods of deriving velocity information from seismic data for the purposes of depth conversion. Horizon stacking velocity analysis (HSVA) and Interval velocity analysis (IVA) have been used to derive average and interval velocity data over the Yolla structure in the Bass Basin, approximately 120km north of Tasmania. The resultant velocity maps are compared with those derived from (more commonly used) vertical function stacking velocities generated during processing. As HSVA and IVA are both horizon-based approaches to velocity picking, lateral velocity trends can be more readily identified and interpreted to be consistent with the geological structure, than regular stacking velocities. A velocity gradient between the 2 wells in the survey area, is known to exist from check-shot data. This gradient is shown to be more accurately determined from the horizon velocity analysis than from the stacking velocity vertical functions. This supports the conclusion that HSVA and IVA (in this case, and perhaps in general), are a more accurate source of velocity control for depth conversion than more routinely used regular stacking velocities. In this example, the relative accuracy of HSVA and IVA velocities is shown to be within 10m/s of check-shot data, compared to several tens of m/s for velocity derived from stacking velocity vertical functions.

Shallow VSP work in the U.S. Appalachian coal basin

Most geophysical applications in North American coal exploration have centered around the conventional surface seismic reflection method to provide continuous subsurface coverage for evaluating both good and anomalous coal reserve areas (Ruskey, 1981; Dobecki and Bartel, 1982; Greaves, 1984; Lawton, 1985; Lyatsky and Lawton, 1988; Gochioco and Cotten, 1989; Lawton and Lyatsky, 1989; Gochioco and Kelly, 1990; Gochioco, 1991; Henson and Sexton, 1991). The surface seismic reflection method, however, has inherent resolution limitations because the seismic wavelet must propagate substantial distances through the weathered layer, resulting in rapid attenuation of the desired higher frequencies. Since the depths and thicknesses of coal seams are usually known before‐hand, it is imperative that the seismic reflection associated with the target coal seam is absolutely identified in the seismic section to avoid misinterpretations. However, it is common that checkshot data and sonic and density logs are not available to generate synthetic seismograms to assist in the interpretation of coal seismic data. To overcome some of these limitations, the vertical seismic profiling (VSP) technique was tested in a coal exploration program to provide additional information for correlation with surface seismic reflection [or common‐depth‐point (CDP)] data and a synthetic seismogram generated from density and sonic logs.

Time To Depth: Where Geologists and Geophysicists Meet

Accurate depth conversions are critical in any exploration area to avoid time-consuming and costly errors in a drilling program. Onshore and offshore, detailed well prognoses from the explorationist are key for the drilling engineer to develop an economical and safe well plan. ln addition, depth conversion is used to calculate the burial depths required for determining geothermal history, provide a depth model for accurate geosteering, and provide for fluid flow simulation. This article explores the necessary steps an interpreter uses to derive and qualify the depth conversion of the seismic interpretation within the workstation environment. Geophysical interpretation begins by identifying regional seismic markers, basinal unconformities, and sequence boundaries to develop a general structural framework. Once the basic framework is established, the task of identifying the seismically represented geologic zones begins. To accurately match geologic tops to seismic reflectors, the interpreter needs a high-quality sonic Jog from which a synthetic seismogram is generated. Check-shot or vertical seismic profile (VSP) data are used to calibrate the sonic curve; the final calibration will define the time and depth relationship along the borehole path. Often the interpreter must rely on other sources for velocity information, i.e., apparent velocities from depth markers tied to regional seismic markers, processing velocities, or a known regional velocity function. Better Synthetic Seismograms Sonic Log Calibration. The sonic log data is critical for accurately creating a synthetic seismogram used in the initial time-to-depth correlations. A density Jog is also important, although standard density values can be applied when no Jog is available. ln the absence of sonic information, a pseudo-sonic Jog may be computed from other logs, such as resistivity. Several activities are commonly performed before the synthetic seismogram is created: editing of the check-shot or velocity information for sonic calibration, generation of a reflectivity series (RC curve), and selection of analytical and extracted wavelets for synthetic convolution.

Impact of 3-D Seismic Data on the Nigerian National Petroleum Corporation/Chevron Nigeria Limited Joint Venture Development Drilling Program

The Nigerian National Petroleum Corporation/Chevron Nigeria Limited joint venture has been acquiring three-dimensional (3-D) seismic data over its concessions since 1984. To date, 1700 km[sup 2] have been recorded and processed at a cumulative cost of US $39 million. During 1991 - 1992, 20 development wells were drilled based directly on new 3-D seismic interpretations. These wells have added 148 million bbl of oil in new recoverable reserves, and to date have added 37,000 bbl/day to the joint venture's production. In addition, the 3-D interpretations have resulted in a sizable inventory of wells for future development drilling. The new 3-D interpretations provided more accurate pictures of fault patterns, fluid contacts, channel trends, stratigraphic continuity, and velocity/amplitude anomalies. In addition, the 3-D data were invaluable in designing low risk, directional well trajectories to tap relatively thin oil legs under large gas caps. Wells often were programmed to hit several objectives at their respective gas/oil contacts, resulting in maximized net oil sand pays and reducing the risk of gas production. In order to do this, directional [open quotes]sharpshooting,[close quotes] accurate depth conversion of the seismic time maps, was critical. By using the 3-D seismic, checkshot, and sonic data to develop a variablemore » velocity space, well-top prognoses within 50 ft at depths of 6,000-10,000 ft were possible, and were key to the success of the program. As the joint venture acreage becomes more mature, development wells will be drilled for smaller numbers of stacked objectives, and sometimes for single sands. Highly accurate 3-D interpretations and depth conversions will become even more critical in order to tap thinner pay zones in a cost-effect manner.« less

Use of Time-Depth Conversion in Velocity Modeling of Well Data from an Onshore Field Dataset, Niger Delta Area, Nigeria

The estimation of subsurface velocity is very important in seismic reflection as it controls the quality of the depth images, which is the basis of most geological interpretation. In this paper, time depth conversion technique had been used to develop a one-dimensional velocity model of an onshore field, using a layer-cake method in creating the model and seismic interpretation program to build the velocity model. The Sonic data and the checkshot data of field obtained were converted to time images to represent the true geological depth. The resulting velocity obtained from the model ranges from 188-2677ms-1, which is a true reflection of the subsurface layers velocities (from the unconsolidated to consolidated layers velocities) of most Niger Delta area.