Intrastratal regimes and reservoir properties of productive horizons in Sangachal-deniz–Duvanny-deniz–Khara-zira adasy fields

2021 ◽  
pp. 65-69
Author(s):  
R.R. Kazimov ◽  
Keyword(s):  
Deep Structure ◽  
3D Models ◽  
Formation Pressure ◽  
Structural Form ◽  
Reservoir Properties ◽  
Initial Formation ◽  
Reservoir Characteristics ◽  
Core Samples ◽  
Parameter Values

The paper reviews the intrastratal regimes and reservoir properties of V, VII and VIII horizons in Sangachal-deniz–Duvanny-deniz–Khara-zira adasy fields. As a result of studies of core samples taken from 1700–5750 m depth, lithological-reservoir characteristics of the rocks have been analyzed, the changing intervals of parameter values shown as well. Therefore, instratal regimes of productive horizons have been analyzed, the dependence of initial formation pressure on hydrostatic and saturation pressures specified. Considering all mentioned above, 3D models of deep structure of SDKhZ (by VII horizon) field have been developed, corresponding vector directions in structural form of studied area defined as well.

scholarly journals FEATURES OF LABORATORY NMR STUDY OF DRILL CUTTINGS

2019 ◽  
Vol 2 (3) ◽  
pp. 30-37
Author(s):  
Mariya Shumskayte ◽  
Mikhail Revva ◽  
Nikita Golikov ◽  
Vyacheslav Glinskikh
Keyword(s):  
Particle Size ◽  
Production Well ◽  
Reservoir Properties ◽  
Nmr Studies ◽  
Drill Cuttings ◽  
Initial Information ◽  
Nmr Method ◽  
Core Samples ◽  
Nmr Study ◽  
Measured Sample

NMR studies of core samples of different disintegration degrees were carried out to determine their reservoir properties depending on the degree of size reduction. It was established that the results do not depend on the particle size of the measured sample and are consistent with the results of standard petrophysical studies performed on core samples. It is shown that the data operatively obtained on the drill cuttings by the NMR method can be used as initial information in interpreting production well logging before conducting detailed petrophysical core studies. The results of studying drill cuttings allow to obtain reservoir properties of productive layers even at intervals without core sampling.

scholarly journals Porosity and Permeability Measurements Integration of The Upper Cretaceous in Balad Field, Central Iraq

2021 ◽  
Vol 54 (1B) ◽  
pp. 24-42
Author(s):  
Fawzi Al-Beyati
Keyword(s):  
Image Analysis ◽  
Log Analysis ◽  
Core Analysis ◽  
Well Log ◽  
Reservoir Properties ◽  
Thin Sections ◽  
Core Samples ◽  
Porosity And Permeability ◽  
Well Log Analysis ◽  
Porosity Range

The corrected porosity image analysis and log data can be used to build 3D models for porosity and permeability. This can be much realistic porosity obtainable because the core test data is not always available due to high cost which is a challenge for petroleum companies and petrophysists. Thus, this method can be used as an advantage of thin section studies and for opening horizon for more studies in the future to obtain reservoir properties. Seventy-two core samples were selected and the same numbers of thin sections were made from Khasib, Sa`di, and Hartha, formations from Ba-1, Ba-4, and Ba-8 wells, Balad Oilfield in Central Iraq to make a comprehensive view of using porosity image analysis software to determine the porosity. The petrophysical description including porosity image analysis was utilized and both laboratory core test analysis and well log analysis were used to correct and calibrate the results. The main reservoir properties including porosity and permeability were measured based on core samples laboratory analysis. The results of porosity obtained from well log analysis and porosity image analysis method are corrected by using SPSS software; the results revealed good correlation coefficients between 0.684 and 0.872. The porosity range values are 9-16% and 9-27% for Khasib and Sa’di in Ba-1 Well, respectively; 10-21%, 9-25%, and 16-27% for Khasib, Sa’di and Hartha in Ba-4 Well, respectively; and 11-24% and 15-24% for Khasib and Hartha in Ba-8 Well, respectively according to petrographic image analysis. By using the laboratory core analysis, the porosity range values are 12-26% and 17-24% for Khasib and Sa’di in Ba-1 Well, respectively; 6-28% and 14-27% for Sa’di and Hartha in Ba-4 Well, respectively; and 17-19% and 15-24% for Sa’di and Hartha in Ba-8 Well, respectively. Finally, the well log analysis showed that the porosity range values are 11-16% and 7-27% for Khasib and Sa’di in Ba-1 Well, respectively; 4-18%, 21-26%, and 16-19% for Khasib, Sa’di and Hartha in Ba-4 Well, respectively; and 9-24% and 15-23% for Khasib and Hartha in Ba-8 Well, respectively. The permeability range values based on laboratory core analysis are 1.51-8.97 md and 0.29-2.77 md for Khasib and Sa’di in Ba-1 Well, respectively; 0.01-24.5 md and 0.28-6.47 md for Sa’di and Hartha in Ba-4 Well, respectively; and 0.86-2.25 md and 0.23-3.66 for Sa’di and Hartha in Ba-8 Well, respectively.

scholarly journals Application of geophysical methods in the extrapolation of sedimentological data on unmastered areas of deposits (on the example of Pennsylvanian carbonate reservoir, Akanskoye oilfield, east of Russian Platform)

2021 ◽  
pp. 128-134
Author(s):  
B. V. Platov ◽  
◽  
A. N. Kolchugin ◽  
E. A. Korolev ◽  
D. S. Nikolaev ◽  
...  
Keyword(s):  
Seismic Data ◽  
Geophysical Methods ◽  
Russian Platform ◽  
Carbonate Reservoir ◽  
Reservoir Properties ◽  
Reservoir Characteristics ◽  
The North ◽  
Study Results ◽  
Core Study ◽  
Well Data

A feature of the oil-bearing carbonate deposits of the lower Pennsylvanian in the east of the Russian platform is their rapid vertical and horizontal change. It is often difficult to make correlations between sections, especially in the absence of core data when using only geophysical data. In addition, not all facies are reliably identified and traceable from log data and not all have high reservoir properties. Authors made an attempt to trace the promising facies both to adjacent wells and, in general, to the entire field area using core study results and translation of these results using log and seismic data. The data showed pinching of rocks with high reservoir characteristics in the direction of the selected profile (from south to north within the field). Coastal shallow water facies, represented by Grainstones and Packstones, with high reservoir properties in the south of the field, are replaced by lagoon facies and facies of subaerial exposures, represented by Wakestones and Mudstones with low reservoir characteristics, in the north of the field. The authors suggest that this approach can be applicable for rocks both in this region and for areas with a similar structure. Keywords: pinch-out; well data; seismic data; limestone; facies; reservoir rocks.

Reservoir And Production Characterization Through Multi-well Pressure Deconvolution Analysis to Optimize Field Development Strategy in Pematang Lantih Field, Jambi

2021 ◽  
Author(s):  
Andhy Kurniawan ◽  
Reffi Erany ◽  
Artur Aslanyan ◽  
Danila Gulyaev ◽  
Sameer Joshi ◽  
...  
Keyword(s):  
Data Availability ◽  
Production Performance ◽  
Productivity Index ◽  
No Production ◽  
Oil Well ◽  
Formation Pressure ◽  
Reservoir Properties ◽  
Test Technique ◽  
Deconvolution Analysis ◽  
Maintenance System

Abstract Target reservoir and production characterization study was carried out in Pematang Lantih field, Jambi, Indonesia. The Talang Akar Formation has 10 underlying reservoirs from 600 m to 900m TVDSS. This multi-layers sandstone structure is driven by regional tectonic stress and complicated by several faults. Sharp oil well production decline was observed during 3 years period since initial production in 2015, with GOR increase. Arresting production decline was the key objective for efficiency increase, hence improved reservoir characterization was needed, as cross-well reservoir properties/interference were unclear. Multiwell Retrospective Test (MRT) is a recent development used to study reservoirs by carrying out automatic matching of historical production rates and bottom hole. It provides practical, fast yet robust analysis for reservoir evaluation. It can quantify inter-well pressure interference and evaluate cross-well reservoir properties. The main goal of this study was to get better reservoir understanding and evaluate ability of this technique to deliver additional value at current reservoir conditions, considering initial data availability/quality. The key technology element used is multi-well pressure deconvolution, which is a highly parallelizable decoding algorithm running on multi-core workstation. The analysis is carried out on historical well pressure and production data. Hence no field operation is needed and there is no production deferment since it does not require additional field data acquisition. The technique delivers formation pressure history and productivity index history in tested well reconstruction. It is also proficient to reconstruct cross-well interference and estimate cross-well transmissibility from offset wells towards the tested well. Another result is evaluation of formation pressure decline impact on oil production of the existing wells. The study area has reservoir pressure that dropped below bubble point and continues declining. Historical data over 3 years, from a cell consisting of 4 producers was analyzed using this technique. The analysis found uniform formation transmissibility between the analyzed wells at Pematang Lantih field. Transmissibility was estimated by analyzing cross-well transient responses (CTR) calculated with multi-well deconvolution. CTR is a function representing BHP response to neighbor well single rate production. CTR is interpreted with interference test technique thus estimating transmissibility values. The analysis result confirmed that all 3 offset wells have a pressure impact towards the pressure-tested well (PLT-X) with quantified values. Connectivity analysis showed the expectation of rapid production decline if there was no pressure maintenance system. The recommendation was to estimate the economics of pressure maintenance system implementation in order to improve production performance. By using multi-well deconvolution analysis, the entire 3-years cell production history was converted into a single unit-rate pressure transient that enabled deep reservoir investigation and calculation of field reserves undisturbed by dynamic well boundaries.

An Analysis of Petrophysical Property Cutoff Properties of Tight Reservoir and its Influences Factors in West Liaohe Depression Yuanyanggou Area

2013 ◽  
Vol 868 ◽  
pp. 547-550 ◽  
Author(s):  
Lin Cong ◽  
Yang Liu ◽  
Jing Chao Lei ◽  
Wen Long Li ◽  
Hao Qing Sun
Keyword(s):  
Oil And Gas ◽  
Burial Depth ◽  
Formation Temperature ◽  
Formation Pressure ◽  
Tight Sandstone ◽  
Reservoir Properties ◽  
Oil And Gas Exploration ◽  
Petrophysical Property ◽  
Reservoir Development ◽  
Oil Production Technology

Petrophysical property cutoff effective reservoir properties can be affected by reservoir properties, crude property, depth, formation temperature, formation pressure and other factors, among which reservoir properties, burial depth and formation temperature are the main factors in effective reservoir development degree of deep tight sandstone, formation pressure has a great impact on the effective reservoir development, while fluid properties have a relatively small impact. The development of oil production technology would reduce petrophysical property cutoff, which will lead to the transformation of non-effective reservoir earlier reckoned into effective reservoir in the future. Therefore, it is necessary in oil and gas exploration to continuously analyze lower limit of effective reservoir physical properties.

scholarly journals THE INFLUENCE OF ROCK LITHOGENESIS TYPES ON POROSITY AND PERMEABILITY (THE CASE OF PERMOCARBONIFEROUS DEPOSIT OF THE USINSKOYE FIELD)

2020 ◽  
Vol 20 (2) ◽  
pp. 104-114
Author(s):  
Nikita A. Popov ◽  
◽  
Ivan S. Putilov ◽  
Anastasiia A. Guliaeva ◽  
Ekaterina E. Vinokurova ◽  
...  
Keyword(s):  
Physical Parameters ◽  
Void Space ◽  
Reservoir Properties ◽  
Full Size ◽  
The Core ◽  
Core Samples ◽  
Porosity And Permeability ◽  
Research Findings ◽  
Influence Of Properties ◽  
First Time

The paper analyzes a methodology aimed at differentiation of porosity, permeability and petrographic properties depending on facies attributes. Based on the Dunham classification, we offer in-depth studies of the influence of rock fabric, including full-size core samples, on changes in porosity and permeability. The work deals with the Permo-Carboniferous deposit of the Usinskoye field. Reservoir properties of the considered strata are highly heterogeneous. Along with highly porous and cavernous rocks, there are low porous and fractured varieties in the section, which refer to rocks of various lithological compositions. The porosity and permeability properties were analysed for more than 9,000 standard core samples and approximately 1,000 full-size core samples, taking into account the scale factor and including microfractures, large caverns and rock matrix, commensurable with the sample sizes.The analysis of the maximum variation range is of particular importance for structurally complex carbonate reservoirs. Furthermore, based on the conducted lithologic, petrographic and petrophysical studies, the authors identified four types of reservoirs and eight different types of lithogenesis, as well as estimated geological and physical parameters for each of them. Based on the cumulative correlation plots, four zones of heterogeneity were identified. They are subject to the influence of properties of the core samples of different lithogenesis types. This is the first time that the influence of various petrotypes/lithotypes on changes in the reservoir porosity and permeability has been studied for the Usinskoye field based on the petrographic and petrophysical research findings. All the conducted experiments show that the rocks of the Permo-Carboniferous deposit of the Usinskoye field are extremely heterogeneous in their permeability properties that vary much. Thus, it is necessary to differentiate the core-to-core petrophysical correlations depending on a void space fabric and lithology of rocks.

scholarly journals Static reservoir modeling using stochastic method: a case study of the cretaceous sequence of Gamtoos Basin, Offshore, South Africa

2021 ◽  
Author(s):  
O. L. Ayodele ◽  
T. K. Chatterjee ◽  
M. Opuwari
Keyword(s):  
South Africa ◽  
Water Saturation ◽  
3D Models ◽  
Sequential Gaussian Simulation ◽  
Reservoir Modeling ◽  
Northwestern Part ◽  
Analysis Model ◽  
Reservoir Properties ◽  
Depositional Sequence ◽  
Gaussian Simulation

AbstractGamtoos Basin is an echelon sub-basin under the Outeniqua offshore Basin of South Africa. It is a complex rift-type basin with both onshore and offshore components and consists of relatively simple half-grabens bounded by a major fault to the northeast. This study is mainly focused on the evaluation of the reservoir heterogeneity of the Valanginian depositional sequence. The prime objective of this work is to generate a 3D static reservoir model for a better understanding of the spatial distribution of discrete and continuous reservoir properties (porosity, permeability, and water saturation). The methodology adopted in this work includes the integration of 2D seismic and well-log data. These data were used to construct 3D models of lithofacies, porosity, permeability, and water saturation through petrophysical analysis, upscaling, Sequential Indicator Simulation, and Sequential Gaussian Simulation algorithms, respectively. Results indicated that static reservoir modeling adequately captured reservoir geometry and spatial properties distribution. In this study, the static geocellular model delineates lithology into three facies: sandstone, silt, and shale. Petrophysical models were integrated with facies within the reservoir to identify the best location that has the potential to produce hydrocarbon. The statistical analysis model revealed sandstone is the best facies and that the porosity, permeability, and water saturation ranges between 8 and 22%, 0.1 mD (< 1.0 mD) to 1.0 mD, and 30–55%. Geocellular model results showed that the northwestern part of the Gamtoos Basin has the best petrophysical properties, followed by the central part of the Basin. Findings from this study have provided the information needed for further gas exploration, appraisal, and development programs in the Gamtoos Basin.

Prediction of Equivalent Liquid Permeability from Gas Permeability Measurements: A Recurrent Neural Network Approach

2021 ◽  
Author(s):  
Husam Alkinani ◽  
Abo Taleb Al-Hameedi ◽  
Shari Dunn-Norman
Keyword(s):  
Neural Network ◽  
Recurrent Neural Network ◽  
Measurement Errors ◽  
Mean Squared Error ◽  
Gas Permeability ◽  
Core Sample ◽  
Reservoir Properties ◽  
Core Samples ◽  
Liquid Permeability ◽  
Hidden Layer

Abstract One of the most vital reservoir properties is permeability. It is usually measured using core samples with two major measurement methods; using gas or using liquid. The purpose of this work is to use a data-driven recurrent neural network model to estimate the equivalent liquid permeability based on gas permeability. By using this model, the equivalent liquid permeability can be predicted for the permeability of core samples with rich clay minerals measured using gas (or any core sample that is measured using gas). This will give an alternative way to the currently used method (Klinkenberg method). Core sample data measurements of more than 500 cores were obtained from limestone formations. The data went through a processing step to eliminate any measurement errors. Then, the data were clustered into training, validation, and testing. After many iterations, a decision was made to have a network with four hidden layer and twenty neurons in each hidden layer, and four delays in the input and the output. The findings showed that the network had stopped training after nine epochs with a validation mean squared error (MSE) of 5.3. The model exhibited excellent performance during training, validation, and testing with an overall R2 of 0.91 which is excellent. These findings prove that the model can closely track the actual equivalent liquid permeability measurements using the gas permeability measurements data within a reasonable margin of error. With the rise of machine learning and other artificial intelligence (AI) methods as well as the potential application in the petroleum industry, these methodologies can revolutionize the industry and save time and money.

Experience of Surfactant-Polymer Flooding Simulation on a Sandstone Reservoir

2021 ◽  
Author(s):  
Alexey Kudryashov ◽  
Kiryl Karseka ◽  
Denis Mityurich ◽  
Vasilii Lompik ◽  
Alexander Cheremisin ◽  
...  
Keyword(s):  
Laboratory Experiments ◽  
3D Model ◽  
3D Models ◽  
Polymer Flooding ◽  
Efficiency Evaluation ◽  
Pilot Site ◽  
Core Samples ◽  
1D Model ◽  
Sandstone Reservoir ◽  
Physical And Chemical

Abstract The aim of the work is to create representative 1D- and 3D-models of surfactant-polymer flooding, considering the most significant physical and chemical phenomena that occur during this process, and further efficiency evaluation of the method. The paper describes approaches to reproduce and verify laboratory experiments results of recovery factor increase during surfactant-polymer flooding on core samples using 1D-model, as well as approaches to optimize the compositions and injection schemes of chemicals during the efficiency evaluation of the technology on a 3D-model of the pilot site.

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