scholarly journals Study of the Influence of Change in the Sandstone and Aleurolite Collector Properties on the Geological Modeling Quality

2021 ◽  
Vol 21 (3) ◽  
pp. 117-122
Author(s):  
Aleksey Yu. Vishnyakov
Keyword(s):  
Economic Assessment ◽  
Core Material ◽  
Reliable Estimate ◽  
Hydrodynamic Models ◽  
Reservoir Properties ◽  
Gas Field ◽  
Rock Density ◽  
Methodical Approach ◽  
Permeability Distribution ◽  
Statistical Sample

The initial data when creating both geological and hydrodynamic reservoir models can lead to errors in the modeling results and the subsequent distortion of the economic assessment and prospects of an oil or gas field. In order to improve the predictive reliability of reservoir hydrodynamic models, a core material study for the Tula object of four fields at the Babkinskaya anticline was carried out. The ratio analysis of porosity (Kp), rock density () and permeability (Kperm) for sandstones and aleurolites was carried out. Using a statistical core sampling based on porosity, density and permeability parameters, a separation by sedimentation processes was carried out for all considered lithological differences. For aleurolite and sandstone, we could talk about the differentiation of characteristics in the process of reservoir properties formation. The values of the parameters Kp, and Kperm, determined from laboratory core studies, were combined into a single statistical sample for the possibility of developing a methodology that would be aimed at describing Kperm using the integrated laboratory studies, namely by adding rock to the analysis. As a result of statistical analysis, it was found that permeability in intervals with low reservoir properties was controlled with the same significance degree by both porosity and rock density for all lithological differences. At the same time, the presence of highly permeable reservoirs for sandstones and their practically absence for aleurolites were noted. For all lithological differences, relationships were established between the permeability coefficient not only with porosity, but also with rock density. The methodology for constructing statistical models for calculating permeability from the values of porosity and rock density was implemented separately for the fields of the eastern and western parts of the Babkinskaya anticline. The described approach to taking into account the influence of rock density on permeability made it possible to determine the differentiated influence of lithotypes on the filtration characteristics of the reservoir. When modeling a reservoir, it is necessary to move from linearity to nonlinearity and take into account that the problem of permeability distribution in the reservoir being solved is somewhat more complicated: in different areas, sometimes the permeability is not controlled by porosity in principle, but somewhere only this parameter prevails. The methodical approach was recommended for 3D modeling. Revealing the relationships between the parameters was most important when developing a methodology for tuning the model in the interwell space. The development of a reliable estimate of permeability for the vast majority of wells will significantly improve the efficiency of hydrodynamic modeling. At the same time, it is necessary to comprehensively take into account the identified relationships between the petrophysical characteristics of production layers. The use of the approach to the analysis of petrophysical characteristics will allow obtaining a more reliable and less subjective hydrodynamic model of the formation.

scholarly journals Lithofacial Zoning of Producing Horizons of Oil and Gas Fields Using Artificial Neural

2020 ◽  
pp. 96-105
Author(s):  
І. О. Fedak ◽  
Ya. М. Koval
Keyword(s):  
Neural Network ◽  
Artificial Neural Network ◽  
Oil And Gas ◽  
Pore Space ◽  
Development Project ◽  
Core Material ◽  
Geological Model ◽  
Reservoir Properties ◽  
Gas Field ◽  
Artificial Neural

The quality of an oil and gas field development project depends greatly on the accuracy of forecasting the processes that occur in the pore space of reservoirs during the extraction of hydrocarbons under certain technolo-gical conditions in production wells. The forecasting is possible if there is a geological model of the field. The more detailed the model is, the more accurate the prediction will be. The whole amount of information used to create a geological model of a field is of discrete nature, and its level of detail is determined by the number of wells that have discovered pay formations. One of the most important elements of the geological model is the nature of changes in reservoir properties of productive formations along their stretch and perpendicular to bedding. The creation of elements of this type requires information from laboratory studies of core material, interpretation of the wells logging results and methods for predicting the nature of changes in reservoir properties in the interwell space. The presence of these elements makes it possible to investigate the situation in which sedimentation (within the existing wells) took place and what types of facies the geological sections of the drilled producing intervals correspond to. Lithofacial zoning of the productive formation according to this information makes it possible to trace the regularities of distribution of facies of various types, to establish their mutual location, and accordingly to predict the nature of changes in reservoir properties in the interwell space. The lack of a sufficient amount of core material is a typical problem that makes it difficult to identify facies. There is another way to solve this problem – this is the identification of facies according to the morphology of logging curves. Nowadays, this problem is solved at a qualitative level. In this paper, it is proposed to apply a quantitative method for identifying facies using an artificial neural network. In particular, the morphology of curves is formalized by a number of parameters that form the input vector of an artificial neural network. At the output of the network, the clusters of logging curves with a similar morpho-logy are formed. The authors refer these clusters to a certain type of facies analytically. On the basis of the information obtained, lithofacial zoning of the productive formations is carried out.

The Clipper Field, Blocks 48/19a, 48/19c, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 691-698
Author(s):  
M. J. Sarginson
Keyword(s):  
North Sea ◽  
Upper Permian ◽  
Lower Permian ◽  
Reservoir Properties ◽  
Gas Field ◽  
Field Development ◽  
Matrix Permeability ◽  
Recoverable Reserves ◽  
Reservoir Permeability ◽  
Sandstone Formation

AbstractThe Clipper Gas Field is a moderate-sized faulted anticlinal trap located in Blocks 48/19a, 48/19c and 48/20a within the Sole Pit area of the southern North Sea Gas Basin. The reservoir is formed by the Lower Permian Leman Sandstone Formation, lying between truncated Westphalian Coal Measures and the Upper Permian evaporitic Zechstein Group which form source and seal respectively. Reservoir permeability is very low, mainly as a result of compaction and diagenesis which accompanied deep burial of the Sole Pit Trough, a sub basin within the main gas basin. The Leman Sandstone Formation is on average about 715 ft thick, laterally heterogeneous and zoned vertically with the best reservoir properties located in the middle of the formation. Porosity is fair with a field average of 11.1%. Matrix permeability, however, is less than one millidarcy on average. Well productivity depends on intersecting open natural fractures or permeable streaks within aeolian dune slipface sandstones. Field development started in 1988. 24 development wells have been drilled to date. Expected recoverable reserves are 753 BCF.

scholarly journals Dependences Of Reservoir Oil Properties On Surface Oil

2020 ◽  
Author(s):  
Sudad H Al-Obaidi ◽  
Galkin AP
Keyword(s):  
Hydrodynamic Models ◽  
Reservoir Properties ◽  
High Quality ◽  
Data Dependencies ◽  
Models Of Development ◽  
Production Wells ◽  
Exploration And Production ◽  
High Degree ◽  
Selection Of

Knowledge of the properties of reservoir oil is necessary when calculating reserves, creating projects development, creating hydrodynamic models of development objects. Reservoir oil properties are determined by downhole samples taken, as usual, from exploration and production wells. In some cases, it is impossible to create conditions for the selection of high-quality downhole samples at exploration and production wells. In such cases, we must use samples of surface oil to obtain information about the reservoir properties of this oil. In this work and as a result of the analysis of the accumulated data, dependencies with a high degree of correlation were obtained, which make it possible to quickly assess the expected parameters of reservoir oil, having only the density of surface oil.

scholarly journals Formation evaluation and reservoir characteristics of the Messinian Abu Madi sandstones in Faraskour Gas Field, onshore Nile Delta, Egypt

2020 ◽  
Author(s):  
Mahmoud Leila ◽  
Ali Eslam ◽  
Asmaa Abu El-Magd ◽  
Lobna Alwaan ◽  
Ahmed Elgendy
Keyword(s):  
Water Saturation ◽  
Nile Delta ◽  
Hydrocarbon Exploration ◽  
The Other ◽  
Reservoir Rock ◽  
Reservoir Quality ◽  
Pore System ◽  
Reservoir Properties ◽  
Gas Field ◽  
Irreducible Water Saturation

Abstract The Messinian Abu Madi Formation represents the most prospective reservoir target in the Nile Delta. Hydrocarbon exploration endeavors in Nile Delta over the last few decades highlighted some uncertainties related to the predictability and distribution of the Abu Madi best reservoir quality facies. Therefore, this study aims at delineating the factors controlling the petrophysical heterogeneity of the Abu Madi reservoir facies in Faraskour Field, northeastern onshore part of the Nile Delta. This work provides the very first investigation on the reservoir properties of Abu Madi succession outside the main canyon system. In the study area, Abu Madi reservoir is subdivided into two sandstone units (lower fluvial and upper estuarine). Compositionally, quartzose sandstones (quartz > 65%) are more common in the fluvial unit, whereas the estuarine sandstones are often argillaceous (clays > 15%) and glauconitic (glauconite > 10%). The sandstones were classified into four reservoir rock types (RRTI, RRTII, RRTIII, and RRTIV) having different petrophysical characteristics and fluid flow properties. RRTI hosts the quartzose sandstones characterized by mega pore spaces (R35 > 45 µm) and a very well-connected, isotropic pore system. On the other side, RRTIV constitutes the lowest reservoir quality argillaceous sandstones containing meso- and micro-sized pores (R35 > 5 µm) and a pore system dominated by dead ends. Irreducible water saturation increases steadily from RRTI (Swir ~ 5%) to RRTIV (Swir > 20%). Additionally, the gas–water two-phase co-flowing characteristics decrease significantly from RRTI to RRTIV facies. The gaseous hydrocarbons will be able to flow in RRTI facies even at water saturation values exceeding 90%. On the other side, the gas will not be able to displace water in RRTIV sandstones even at water saturation values as low as 40%. Similarly, the influence of confining pressure on porosity and permeability destruction significantly increases from RRTI to RRTIV. Accordingly, RRTI facies are the best reservoir targets and have high potentiality for primary porosity preservation.

THE INTEGRATED USE OF PETROPHYSICAL, AVO, SEISMIC INVERSION AND 3D VISUALISATION TOOLS FOR RESERVOIR CHARACTERISATION

2001 ◽  
Vol 41 (2) ◽  
pp. 131
Author(s):  
A.G. Sena ◽  
T.M. Smith
Keyword(s):  
Seismic Data ◽  
New Technology ◽  
Seismic Inversion ◽  
Well Log ◽  
Reservoir Properties ◽  
Gas Field ◽  
Geological Interpretation ◽  
3D Visualisation ◽  
Quantitative Understanding ◽  
Inversion Techniques

The successful exploration for new reservoirs in mature areas, as well as the optimal development of existing fields, requires the integration of unconventional geological and geophysical techniques. In particular, the calibration of 3D seismic data to well log information is crucial to obtain a quantitative understanding of reservoir properties. The advent of new technology for prestack seismic data analysis and 3D visualisation has resulted in improved fluid and lithology predictions prior to expensive drilling. Increased reservoir resolution has been achieved by combining seismic inversion with AVO analysis to minimise exploration risk.In this paper we present an integrated and systematic approach to prospect evaluation in an oil/gas field. We will show how petrophysical analysis of well log data can be used as a feasibility tool to determine the fluid and lithology discrimination capabilities of AVO and inversion techniques. Then, a description of effective AVO and prestack inversion tools for reservoir property quantification will be discussed. Finally, the incorporation of the geological interpretation and the use of 3D visualisation will be presented as a key integration tool for the discovery of new plays.

FORMATION EVALUATION AND STATIC MODELLING IN THE WHEATSTONE GAS FIELD

2006 ◽  
Vol 46 (1) ◽  
pp. 161 ◽  
Author(s):  
P. Theologou ◽  
M. Whelan
Keyword(s):  
Experimental Design ◽  
Early Stage ◽  
Potential Range ◽  
Reservoir Properties ◽  
Gas Field ◽  
Formation Evaluation ◽  
Place Assimilation ◽  
Logging While Drilling ◽  
Realistic Information ◽  
The Impact

The Wheatstone gas discovery is located about 110 km north-northwest of Barrow Island in the Dampier Subbasin, northwest Australia. Gas was intersected within the AA sands of the Mungaroo Formation, and within a thin overlying Tithonian sand. Core was acquired through the base of the Tithonian sand and the upper section of the Mungaroo Formation.A combination of logging while drilling, wireline logging, core acquisition and special core analysis has formed the basis of an extensive formation evaluation program for Wheatstone–1. The acquisition of this dataset, and associated interpretation, has allowed Chevron to maximise its ability to characterise the reservoir early in the field’s history, and thereby has helped our understanding of the uncertainties associated with the formation evaluation and geological modelling of this fluvial system. Petrological studies indicate that reservoir properties and mineralogy are strongly correlated with the mean grain size of the formation. The mineralogy of the sands is relatively simple with minor quartz overgrowth, K-feldspar dissolution and kaolinite precipitation being the dominant diagenetic events. The better quality sands are generally devoid of significant amounts of clays such as illite-smectite. Within the Tithonian sand, more exotic mineral suites are present including glauconitic and phosphatic minerals.A comparison of resistivity data from wireline and logging while drilling (LWD) across cored and non-cored intervals through the Mungaroo Formation has revealed the impact that slow coring has had on formation filtrate invasion. It has been interpreted that the combination of slow rate of penetration, non-optimised mud properties, and coring assembly design resulted in deep invasion through cored intervals. Deep resistivity response through the invaded formation was subdued, and initially resulted in an underestimation of reserves. The incorporation of saturation information from capillary pressure data has provided for a more realistic view of gas-in-place.In this early stage of field appraisal, the generation of representative and fit-for-purpose reservoir models is somewhat difficult due to the small amount of available data existing away from the well. To provide realistic information on the potential range of gas-in-place for the field, experimental design methodology was incorporated into the modelling work-flow. Experimental design allows for rapid and comprehensive modelling of the possible range of the dependant variables, in this case GIIP (gas initially in place). Assimilation of geological analogues, formation evaluation and their inherent uncertainties has attempted to capture the range of GIIP in this world-class gas discovery.

scholarly journals Productivity Criteria for Complex Reservoirs Based on the Study of Deep-Adsorbed Gases

2021 ◽  
Vol 133 (2) ◽  
pp. 27-30
Author(s):  
D. A. Kobylinskiy ◽  
Keyword(s):  
Research Method ◽  
Oil And Gas ◽  
Geological Structure ◽  
Core Material ◽  
Test Results ◽  
The West ◽  
Gas Field ◽  
The Core ◽  
Oil And Gas Field ◽  
Complex Geological Structure

The work is devoted to the development of geochemical criteria for determining the nature of saturation for deep-adsorbed gases in the core. As the object of investigation used the core material selected in the fields in the Nadym-Pyrskoy oil and gas field. In each sample, 72 components were determined, namely, hydrocarbons of different material groups: normal, branched, polycyclic, and aromatic compounds from butane to dodecane. With respect to the quantitative distribution and correlation among the components, qualitative geochemical indicators of sediment productivity have been developed. The saturation character established by the criteria of deep-adsorbed gases was confirmed by the test results. In this regard, this research method significantly increases the effectiveness of diagnostics of prospective deposits, the application of which is relevant in the territory of the West Siberian oil and gas basin, especially when studying deep-submerged deposits of complex geological structure.

scholarly journals Building of Turbiditic Gas Field Dynamic Model with a Simplified 3D Simulation Software

2018 ◽  
Vol 3 (3) ◽  
pp. 141
Author(s):  
Octria Adi Prasojo ◽  
Vladimir Alejandro Choque Flores ◽  
Matthieu Plantevin ◽  
Reza Syahputra
Keyword(s):  
Simulation Model ◽  
History Matching ◽  
Structural Model ◽  
Simulation Software ◽  
3D Simulation ◽  
Well Testing ◽  
Data Quality Control ◽  
Reservoir Properties ◽  
Gas Field ◽  
3D Simulation Model

This study provides a novel approach of building 3D simulation model with extremely shorter time needed using Rubis simulation software from Kappa Engineering. The study focused on X Field that is located in a turbiditic setting, mainly consisted of separated channel bodies filled with gas, located in a slope apron or passive continental margin of Mahakam Delta. Methods of the study is quite contradictive with common reservoir simulation where it includes data integration, data quality control, model geometry building, reservoir properties distribution, and is followed by wells definition to build the 3D simulation model. Afterward, the reliability of the structural model was checked by the volume calculation for each segment from GeoX model where all dynamic and static data used in the simulation were checked using history matching data derived from well-testing. In conclusion, simulation was run and X Field will be producing for 23 years with 3 years and 10 months plateau rate. Where the static and dynamic data are already provided, the simulation conducted here was very beneficial during the exploration phase of a gas field where the whole process of modeling and simulation could be done only for 3 to 6 months.

scholarly journals Dual hydrocarbon–geothermal energy exploitation: potential synergy between the production of natural gas and warm water from the subsurface

2019 ◽  
Vol 98 ◽  
Author(s):  
Jeroen van der Molen ◽  
Elisabeth Peters ◽  
Farid Jedari-Eyvazi ◽  
Serge F. van Gessel
Keyword(s):  
Natural Gas ◽  
Financial Risk ◽  
Net Present Value ◽  
Gas Production ◽  
Added Value ◽  
Reservoir Properties ◽  
Gas Field ◽  
Gas Recovery ◽  
Water Breakthrough ◽  
High Standards

Abstract The decline of domestic natural gas production, increasing dependency on gas imports and lagging development of renewable energy production may pose serious challenges to the current high standards of secure energy supply in the Netherlands. This paper examines synergy between hydrocarbon- and geothermal exploitation as a means to reinforce energy security. The Roden gas field is used as an example to demonstrate potential delay of water breakthrough in the gas well and a resulting increase of recovered gas (up to 19%), by positioning of a geothermal doublet in the water leg of the gas field. The reservoir simulations show that the total increase of gas production primarily depends on the amount of aquifer support. An optimal configuration of gas- and geothermal wells is key to maximise gas recovery and strongly depends on the distribution of reservoir properties. The study also reveals that this option can still be beneficial for gas fields in a late stage of production. Net Present Value calculations show that the added value from the geothermal doublet on total gas production could lead to an early repayment of initial investments in the geothermal project, thereby reducing the overall financial risk. If no subsidies are taken into account, the additional profits can also be used to finance the geothermal project up to break-even level within 15 years. However, this comes with a cost as the additional profits from improved gas recovery are significantly reduced.

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