INTEGRATION OF SEISMIC, WIRELINE LOGS AND CORE DATA INTO A GENETIC CHARACTERISATION FRAMEWORK

1994 ◽  
Vol 34 (1) ◽  
pp. 337
Author(s):  
P.M. Wong ◽  
I.J. Taggart ◽  
F.X. Jian
Keyword(s):  
Seismic Data ◽  
Petroleum Industry ◽  
Group Model ◽  
Kriging Method ◽  
Well Control ◽  
Model Studies ◽  
Porosity Variation ◽  
Flow Units ◽  
Wireline Logs ◽  
A New Technique

Whilst the adequate characterisation of reservoir heterogeneity is an acknowledged problem in the petroleum industry, surprisingly little use is made of seismic data to predict lithofacies and porosity in reservoir regions without adequate well control. Previous attempts at using seismic data to predict lithofacies and porosity variations are reviewed and a new technique based on simultaneous use of seismic and wireline logs is proposed. This new procedure is based on a two-step collocated co-kriging method. The first step simulates lithofacies architecture and is followed by the estimation of porosity values for each lithofacies group. Model studies show that this approach results in an improved description of reservoir lithofacies architecture and porosity variation. Moreover, the proposed technique is consistent with concepts of genetic reservoir characterisation, which aims to characterise the reservoir in terms of lithological flow units. The cokriging results are shown to be more reliable than those obtained using older and more established techniques.

About this title - Seismic Characterization of Carbonate Platforms and Reservoirs

10.1144/sp509 ◽  
2021 ◽  
Vol 509 (1) ◽  
pp. NP-NP
Author(s):  
J. Hendry ◽  
P. Burgess ◽  
D. Hunt ◽  
X. Janson ◽  
V. Zampetti
Keyword(s):  
Seismic Data ◽  
Oil And Gas ◽  
Carbonate Platform ◽  
Carbonate Platforms ◽  
Oil And Gas Exploration ◽  
Seismic Modelling ◽  
Flow Units ◽  
Development Data ◽  
Seismic Characterization

Modern seismic data have become an essential toolkit for studying carbonate platforms and reservoirs in impressive detail. Whilst driven primarily by oil and gas exploration and development, data sharing and collaboration are delivering fundamental geological knowledge on carbonate systems, revealing platform geomorphologies and how their evolution on millennial time scales, as well as kilometric length scales, was forced by long-term eustatic, oceanographic or tectonic factors. Quantitative interrogation of modern seismic attributes in carbonate reservoirs permits flow units and barriers arising from depositional and diagenetic processes to be imaged and extrapolated between wells.This volume reviews the variety of carbonate platform and reservoir characteristics that can be interpreted from modern seismic data, illustrating the benefits of creative interaction between geophysical and carbonate geological experts at all stages of a seismic campaign. Papers cover carbonate exploration, including the uniquely challenging South Atlantic pre-salt reservoirs, seismic modelling of carbonates, and seismic indicators of fluid flow and diagenesis.

scholarly journals Facies Analysis and Depositoinal Environment of D-3 Reservoir Sands Vin Field, Eastern Niger Delta

2019 ◽  
pp. 1-19
Author(s):  
Onyewuchi, Chinedu Vin ◽  
Minapuye, I. Odigi
Keyword(s):  
Seismic Data ◽  
Niger Delta ◽  
Depositional Environment ◽  
Gamma Ray ◽  
Facies Analysis ◽  
Depositional Environments ◽  
Width Ratio ◽  
Neutron Density ◽  
Wireline Logs ◽  
Isopach Map

Facies analysis and depositional environment identification of the Vin field was evaluated through the integration and comparison of results from wireline logs, core analysis, seismic data, ditch cutting samples and petrophysical parameters. Well log suites from 22 wells comprising gamma ray, resistivity, neutron, density, seismic data, and ditch cutting samples were obtained and analyzed. Prediction of depositional environment was made through the usage of wireline log shapes of facies combined with result from cores and ditch cuttings sample description. The aims of this study were to identify the facies and depositional environments of the D-3 reservoir sand in the Vin field. Two sets of correlations were made on the E-W trend to validate the reservoir top and base while the isopach map was used to establish the reservoir continuity. Facies analysis was carried out to identify the various depositional environments. The result showed that the reservoir is an elongate , four way dip closed roll over anticline associated with an E-W trending growth fault and contains two structural high separated by a saddle. The offshore bar unit is an elongate sand body with length: width ratio of >3:1 and is aligned parallel to the coast-line. Analysis of the gamma ray logs indicated that four log facies were recognized in all the wells used for the study. These include: Funnel-shaped (coarsening upward sequences), bell-shaped or fining upward sequences, the bow shape and irregular shape. Based on these categories of facies, the depositional environments were interpreted as deltaic distributaries, regressive barrier bars, reworked offshore bars and shallow marine. Analysis of the wireline logs and their core/ditch cuttings description has led to the conclusion that the reservoir sandstones of the Agbada Formation in the Vin field of the eastern Niger Delta is predominantly marine deltaic sequence, strongly influenced by clastic output from the Niger Delta. Deposition occurred in a variety of littoral and neritic environment ranging from barrier sand complex to fully marine outer shelf mudstones.

scholarly journals Evidence for massive emission of methane from a deep‐water gas field during the Pliocene

2020 ◽  
Vol 117 (45) ◽  
pp. 27869-27876
Author(s):  
Martino Foschi ◽  
Joseph A. Cartwright ◽  
Christopher W. MacMinn ◽  
Giuseppe Etiope
Keyword(s):  
Deep Water ◽  
Seismic Data ◽  
Three Dimensional ◽  
Petroleum Industry ◽  
Atmospheric Methane ◽  
Borehole Data ◽  
Gas Field ◽  
Modern Times ◽  
Water Gas ◽  
Fluid Flow Modeling

Geologic hydrocarbon seepage is considered to be the dominant natural source of atmospheric methane in terrestrial and shallow‐water areas; in deep‐water areas, in contrast, hydrocarbon seepage is expected to have no atmospheric impact because the gas is typically consumed throughout the water column. Here, we present evidence for a sudden expulsion of a reservoir‐size quantity of methane from a deep‐water seep during the Pliocene, resulting from natural reservoir overpressure. Combining three-dimensional seismic data, borehole data and fluid‐flow modeling, we estimate that 18–27 of the 23–31 Tg of methane released at the seafloor could have reached the atmosphere over 39–241 days. This emission is ∼10% and ∼28% of present‐day, annual natural and petroleum‐industry methane emissions, respectively. While no such ultraseepage events have been documented in modern times and their frequency is unknown, seismic data suggest they were not rare in the past and may potentially occur at present in critically pressurized reservoirs. This neglected phenomenon can influence decadal changes in atmospheric methane.

scholarly journals Petrophysical evaluation of reservoir sand bodies in Kwe Field Onshore Eastern Niger Delta

2016 ◽  
Vol 20 (2) ◽  
pp. 383-393
Author(s):  
T.M. Asubiojo ◽  
S.E. Okunuwadje
Keyword(s):  
Niger Delta ◽  
Depositional Environment ◽  
Gamma Ray ◽  
Petrophysical Properties ◽  
System Quality ◽  
Flow Units ◽  
Wireline Logs ◽  
And Performance ◽  
Niger Delta Basin ◽  
Sand Bodies

Reservoir sand bodies in Kwe Field, coastal swamp depobelt, onshore eastern Niger Delta Basin were evaluated from a composite log suite comprising gamma ray, resistivity, density and neutron logs of five (5) wells with core photographs of one (1) reservoir of one well. The aim of the study was to evaluate the petrophysical properties of the reservoirs while the objectives were to identify the depositional environment and predict the reservoir system quality and performance. The study identified three reservoir sand bodies in the field on the basis of their petrophysical properties and architecture. Reservoir A has an average NTG (61.4 %), Ø (27.50 %), K (203.99 md), Sw (31.9 %) and Sh (68.1 %); Reservoir B has an average NTG (65.6 %), Ø (26.0 %), K (95.90 md), Sw (28.87 %) and Sh (71.13 %) while Reservoir C has an average NTG (70.4 %), Ø (26.1 %), K (91.4 md), Sw (25.0 %) and Sh (75.03 %) and therefore show that the field has good quality sandstone reservoirs saturated in hydrocarbon. However, the presence of marine shales (or mudstones) interbedding with these sandstones may likely form permeability baffles to vertical flow and compartmentalize the reservoirs. These reservoirs may therefore have different flow units. Integrating wireline logs and core data, the reservoir sand bodies were interpreted as deposited in an estuarineshoreface setting thus indicating that the Kwe Field lies within the marginal marine mega depositional environment.Keywords: Estuarine, Shoreface, Reservoir, Sand, Kwe, field

THE HYDROCARBON POTENTIAL OF THE PENOLA TROUGH, OTWAY BASIN

1995 ◽  
Vol 35 (1) ◽  
pp. 358 ◽  
Author(s):  
R. Lovibond ◽  
R.J. Suttill ◽  
J.E. Skinner ◽  
A.N. Aburas
Keyword(s):  
Early Cretaceous ◽  
Seismic Data ◽  
Oil And Gas ◽  
Direct Detection ◽  
Source Rocks ◽  
Well Control ◽  
Potential Reservoir ◽  
Half Graben ◽  
History Of

The Penola Trough is an elongate, Late Jurassic to Early Cretaceous, NW-SE trending half graben filled mainly with synrift sediments of the Crayfish Group. Katnook-1 discovered gas in the basal Eumeralla Formation, but all commercial discoveries have been within the Crayfish Group, particularly the Pretty Hill Formation. Recent improvements in seismic data quality, in conjunction with additional well control, have greatly improved the understanding of the stratigraphy, structure and hydrocarbon prospectivity of the trough. Strati-graphic units within the Pretty Hill Formation are now mappable seismically. The maturity of potential source rocks within these deeper units has been modelled, and the distribution and quality of potential reservoir sands at several levels within the Crayfish Group have been studied using both well and seismic data. Evaluation of the structural history of the trough, the risk of a late carbon dioxide charge to traps, the direct detection of gas using seismic AVO analysis, and the petrophysical ambiguities recorded in wells has resulted in new insights. An important new play has been recognised on the northern flank of the Penola Trough: a gas and oil charge from mature source rocks directly overlying basement into a quartzose sand sequence referred to informally as the Sawpit Sandstone. This play was successfully tested in early 1994 by Wynn-1 which flowed both oil and gas during testing from the Sawpit Sandstone. In mid 1994, Haselgrove-1 discovered commercial quantities of gas in a tilted Pretty Hill Formation fault block adjacent to the Katnook Field. These recent discoveries enhance the prospectivity of the Penola Trough and of the Early Cretaceous sequence in the wider Otway Basin where these sediments are within reach of the drill.

THE YELLOWTAIL OIL DISCOVERY

1983 ◽  
Vol 23 (1) ◽  
pp. 170
Author(s):  
A. R. Limbert ◽  
P. N. Glenton ◽  
J. Volaric
Keyword(s):  
Oil Recovery ◽  
Seismic Data ◽  
Joint Venture ◽  
Seismic Survey ◽  
3D Seismic ◽  
Well Control ◽  
Reservoir Volume ◽  
3D Data ◽  
Small Feature ◽  
Gippsland Basin

The Esso/Hematite Yellowtall oil discovery is located about 80 km offshore in the Gippsland Basin. It is a small accumulation situated between the Mackerel and Kingfish oilfields. The oil is contained in Paleocene Latrobe Group sandstones, and sealed by the calcareous shales and siltstones of the Oligocene to Miocene Lakes Entrance Formation. Structural movement and erosion have combined to produce a low relief closure on the unconformity surface at the top of the Latrobe Group.The discovery well, Yellowtail-1, was the culmination of an exploration programme initiated during the early 1970's. The early work involved the recording and interpretation of conventional seismic data and resulted in the drilling of Opah- 1 in 1977. Opah-1 failed to intersect reservoir- quality sediments within the interpreted limits of closure although oil indications were encountered in a non-net interval immediately below the top of the Latrobe Group. In 1980 the South Mackerel 3D seismic survey was recorded. The interpretation of these 3D data in conjunction with the existing well control resulted in the drilling of Yellowtail-1 and subsequently led to the drilling of Yellowtail-2.In spite of the intensive exploration to which this small feature has been subjected, the potential for its development remains uncertain. Technical factors which affect the viability of a Yellowtail development are:The low relief of the closure makes the reservoir volume highly sensitive to depth conversion of the seismic data.The complicated velocity field makes precise depth conversion difficult.The thin oil column reduces oil recovery efficiency.The detailed pattern of erosion at the top of the Latrobe Group may be beyond the resolution capability of 3D seismic data.The 3D seismic data may not be capable of defining the distribution of the non-net intervals within the trap.The large anticlinal closures and topographic highs in the Gippsland Basin have been drilled, and the prospects that remain are generally small or high risk. Such exploration demands higher technology in the exploration stage and more wells to define the discoveries, and has no guarantee of success. The Yellowtail discovery is an illustration of one such prospect that the Esso/Hematite joint venture is evaluating.

Well Control Simulation With Nonaqueous Drilling Fluids

2020 ◽  
Vol 143 (3) ◽  
Author(s):  
Felipe Chagas ◽  
Paulo R. Ribeiro ◽  
Otto L. A. Santos
Keyword(s):  
Drilling Fluid ◽  
Petroleum Industry ◽  
Critical Issue ◽  
Drilling Fluids ◽  
Operational Parameters ◽  
Data Set ◽  
Well Control ◽  
Operational Conditions ◽  
Control Research ◽  
Drilling Operations

Abstract The demand for energy has increased recently worldwide, requiring new oilfield discoveries to supply this need. Following this demand increase, challenges grow in all areas of the petroleum industry especially those related to drilling operations. Due to hard operational conditions found when drilling complex scenarios such as high-pressure/high-temperature (HPHT) zones, deep and ultradeep water, and other challenges, the use nonaqueous drilling fluids became a must. The reason for that is because this kind of drilling fluid is capable to tolerate these extreme drilling conditions found in those scenarios. However, it can experience changes in its properties as a result of pressure and temperature variations, requiring special attention during some drilling operations, such as the well control. The well control is a critical issue since it involves safety, social, economic, and environmental aspects. Well control simulators are a valuable tool to support well control operations and preserve the well integrity, verifying operational parameters and to assist drilling engineers in the decision-making process during well control operations and kick situations. They are also important computational tools for rig personnel training. This study presents well control research and development contributions, as well as the results of a computational well control simulator that applies the Driller's method and allows the understanding the thermodynamic behavior of synthetic drilling fluids, such as n-paraffin and ester base fluids. The simulator employed mathematical correlations for the drilling fluids pressure–volume–temperature (PVT) properties obtained from the experimental data. The simulator results were compared to a test well data set as well to the published results from other kick simulators.

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