Study of Reservoir Properties of Turonian Formation Using Digital Core Analysis

2021 ◽  
Author(s):  
Ivan Yakimchuk ◽  
Dmitry Korobkov ◽  
Vera Pletneva ◽  
Olga Ridzel ◽  
Igor Varfolomeev ◽  
...  
Keyword(s):  
Rock Properties ◽  
Relative Permeabilities ◽  
Reservoir Properties ◽  
Digital Rock ◽  
Gas Recovery ◽  
Rock Types ◽  
Digital Core ◽  
Reservoir Conditions ◽  
Capillary Pressures ◽  
Rock Analysis

Abstract The work demonstrates results of reservoir properties evaluation using a complex of laboratory and multiscale digital core or digital rock analysis. Rock properties (including relative phase permeabilities) were studied at different scales: from nanometers to meter (whole core). For the first time, cores from Turonian formation were characterized with digital rock analysis, which provided stationary relative permeabilities for gas-water under reservoir conditions. Lab determination of relative permeabilities was rather challenging for some low-permeability samples (<0.02 md), while digital analysis was successful even for them. Gas recovery in a depletion mode from different rock types was studied on a whole core model for different capillary pressures. Such studies are not conducted in the lab.

Digital Rock Typing DRT Algorithm Formulation with Optimal Supervised Semantic Segmentation

2022 ◽  
Author(s):  
Omar Alfarisi ◽  
Djamel Ouzzane ◽  
Mohamed Sassi ◽  
TieJun Zhang
Keyword(s):  
Carbonate Rock ◽  
Chemical Properties ◽  
Rock Physics ◽  
Semantic Segmentation ◽  
Rock Properties ◽  
Digital Rock Physics ◽  
Digital Rock ◽  
Rock Types ◽  
Fluid Saturation ◽  
Rock Typing

<p><a></a>Each grid block in a 3D geological model requires a rock type that represents all physical and chemical properties of that block. The properties that classify rock types are lithology, permeability, and capillary pressure. Scientists and engineers determined these properties using conventional laboratory measurements, which embedded destructive methods to the sample or altered some of its properties (i.e., wettability, permeability, and porosity) because the measurements process includes sample crushing, fluid flow, or fluid saturation. Lately, Digital Rock Physics (DRT) has emerged to quantify these properties from micro-Computerized Tomography (uCT) and Magnetic Resonance Imaging (MRI) images. However, the literature did not attempt rock typing in a wholly digital context. We propose performing Digital Rock Typing (DRT) by: (1) integrating the latest DRP advances in a novel process that honors digital rock properties determination, while; (2) digitalizing the latest rock typing approaches in carbonate, and (3) introducing a novel carbonate rock typing process that utilizes computer vision capabilities to provide more insight about the heterogeneous carbonate rock texture.<br></p>

Digital Rock Typing DRT Algorithm Formulation with Optimal Supervised Semantic Segmentation

2022 ◽  
Author(s):  
Omar Alfarisi ◽  
Djamel Ouzzane ◽  
Mohamed Sassi ◽  
TieJun Zhang
Keyword(s):  
Carbonate Rock ◽  
Chemical Properties ◽  
Rock Physics ◽  
Semantic Segmentation ◽  
Rock Properties ◽  
Digital Rock Physics ◽  
Digital Rock ◽  
Rock Types ◽  
Fluid Saturation ◽  
Rock Typing

<p><a></a>Each grid block in a 3D geological model requires a rock type that represents all physical and chemical properties of that block. The properties that classify rock types are lithology, permeability, and capillary pressure. Scientists and engineers determined these properties using conventional laboratory measurements, which embedded destructive methods to the sample or altered some of its properties (i.e., wettability, permeability, and porosity) because the measurements process includes sample crushing, fluid flow, or fluid saturation. Lately, Digital Rock Physics (DRT) has emerged to quantify these properties from micro-Computerized Tomography (uCT) and Magnetic Resonance Imaging (MRI) images. However, the literature did not attempt rock typing in a wholly digital context. We propose performing Digital Rock Typing (DRT) by: (1) integrating the latest DRP advances in a novel process that honors digital rock properties determination, while; (2) digitalizing the latest rock typing approaches in carbonate, and (3) introducing a novel carbonate rock typing process that utilizes computer vision capabilities to provide more insight about the heterogeneous carbonate rock texture.<br></p>

Suitability of Natural Geomedia for Radwaste Storage

1982 ◽  
Vol 15 ◽  
Author(s):  
W. S. Fyfe
Keyword(s):  
Rock Properties ◽  
Fracture Flow ◽  
Time Prediction ◽  
Sedimentary Sequences ◽  
Rock Types ◽  
Direct Observations ◽  
Long Time ◽  
Mining Disturbance ◽  
Selection Of

ABSTRACTSelection of the best rock types for radwaste disposal will depend on their having minimal permeability, maximal flow dispersion, minimal chance of forming new wide aperture fractures, maximal ion retention, and minimal thermal and mining disturbance. While no rock is perfect, thinly bedded complex sedimentary sequences may have good properties, either as repository rocks, or as cover to a repository.Long time prediction of such favorable properties of a rock at a given site may be best modelled from studies of in situ rock properties. Fracture flow, dispersion history, and geological stability can be derived from direct observations of rocks themselves, and can provide the parameters needed for convincing demonstration of repository security for appropriate times.

scholarly journals Fluid Saturation Predictions in a “Transition Zone” Carbonate Reservoir, Abu Dhabi

GeoArabia ◽  
1996 ◽  
Vol 1 (4) ◽  
pp. 551-566
Author(s):  
Anthony Kirkham ◽  
Mohamed Bin Juma ◽  
Tilden A.M. McKean ◽  
Anthony F. Palmer ◽  
Michael J. Smith ◽  
...  
Keyword(s):  
Transition Zone ◽  
Free Water ◽  
Analysis Data ◽  
Carbonate Reservoir ◽  
Rock Types ◽  
Fluid Saturation ◽  
Porosity And Permeability ◽  
Capillary Pressures ◽  
Seismic Amplitudes ◽  
Low Amplitude

ABSTRACT The field is a low amplitude structure with a chalky, Lower Cretaceous, Thamama reservoir characterised by a large hydrocarbon transition zone. Porosity generally decreases with depth within the trap although porosity versus depth trends are skewed by tilting. Porosity and permeability mapping was therefore achieved using templates based on seismic amplitudes. Special core analysis data were used to construct algorithms of Leverett J functions versus saturation for a variety of rock types mapped throughout the 3-D geological model of the field. The templated poroperms were then combined with capillary pressures to predict fluid saturations from these algorithms. The modelling of fluid distributions was therefore dependent upon heterogeneities imposed by the rock fabrics. Calibrating the model-predicted saturations against log-derived saturations at the wells involved regression techniques which were complicated by: notional structural tilting of the free water level, imbibition, hysteresis and permeability averaging procedures. Filtered “stick displays” proved useful in assessing the quality of the calibrations and were invaluable tools for highlighting and investigating data anomalies.

Geological model and optimal well placement substantiation at the western part Tyumen suite layers of Khanty-Mansiysk Autonomous Okrug — Ugra

2021 ◽  
pp. 8-24
Author(s):  
S. R. Bembel ◽  
R. V. Avershin ◽  
R. M. Bembel ◽  
V. I. Kislukhin
Keyword(s):  
Seismic Survey ◽  
Geological Model ◽  
Reservoir Properties ◽  
Well Placement ◽  
Oil Reserves ◽  
Multi Stage ◽  
Reservoir Conditions ◽  
Hydrodynamic Calculations ◽  
Field Information ◽  
Clay Barriers

The middle Jurassic Tyumen sediments have been involved in the development of oil facilities in the territory of the Khanty-Mansiysk Autonomous Okrug — Ugra for the last decade. The Jk2-5 formation is represented by complex interlayering of poorly permeable sandy-aleurite lenses and clay barriers with low reservoir properties. Recoverable oil reserves of the Jk2-5 formation on the Krasnoleninsky arch amounts to several hundred million tons. According to the collector permeability, the reserves of the object are classified as hard-to-recover. There are no effective technologies to involve such reserves in the development now. Standard methods of drilling and operation of inclined wells doesn't allow achieving acceptable oil production rates under these reservoir conditions. Based on the analysis of seismic survey data, correlation of well sections, field information, a geological model of a productive reservoir on the Krasnoleninsky arch was created. The multi-step hydrodynamic calculations made it possible to clarify the parameters of the profile of horizontal wells, the number and configuration of operations for multi-stage hydraulic fracturing. Based on the results of the research, recommendations were developed to well placement, drilling and well operation for specific field areas in order to increase the oil resource development efficiency.

Factors Controlling Porosity Permeability Relationship for Reservoir Quality Prediction: A Case Study of Malay Basin Reservoir, Malaysia

2021 ◽  
Author(s):  
Fadzlin Hasani Kasim ◽  
Budi Priyatna Kantaatmadja ◽  
Wan Nur Wan M Zainudin ◽  
Amita Ali ◽  
Hasnol Hady Ismail ◽  
...  
Keyword(s):  
Reservoir Characterization ◽  
Visual Analysis ◽  
Mineral Dissolution ◽  
Rock Properties ◽  
Reservoir Quality ◽  
Hydrocarbon Potential ◽  
Lower Grade ◽  
Reservoir Properties ◽  
Reservoir Evaluation ◽  
Porosity And Permeability

Abstract Predicting the spatial distribution of rock properties is the key to a successful reservoir evaluation for hydrocarbon potential. However, a reservoir with a complex environmental setting (e.g. shallow marine) becomes more challenging to be characterized due to variations of clay, grain size, compaction, cementation, and other diagenetic effects. The assumption of increasing permeability value with an increase of porosity may not be always the case in such an environment. This study aims to investigate factors controlling the porosity and permeability relationships at Lower J Reservoir of J20, J25, and J30, Malay Basin. Porosity permeability values from routine core analysis were plotted accordingly in four different sets which are: lithofacies based, stratigraphic members based, quartz volume-based, and grain-sized based, to investigate the trend in relating porosity and permeability distribution. Based on petrographical studies, the effect of grain sorting, mineral type, and diagenetic event on reservoir properties was investigated and characterized. The clay type and its morphology were analyzed using X-ray Diffractometer (XRD) and Spectral electron microscopy. Results from porosity and permeability cross-plot show that lithofacies type play a significant control on reservoir quality. It shows that most of the S1 and S2 located at top of the plot while lower grade lithofacies of S41, S42, and S43 distributed at the middle and lower zone of the plot. However, there are certain points of best and lower quality lithofacies not located in the theoretical area. The detailed analysis of petrographic studies shows that the diagenetic effect of cementation and clay coating destroys porosity while mineral dissolution improved porosity. A porosity permeability plot based on stratigraphic members showed that J20 points located at the top indicating less compaction effect to reservoir properties. J25 and J30 points were observed randomly distributed located at the middle and bottom zone suggesting that compaction has less effect on both J25 and J30 sands. Lithofacies description that was done by visual analysis through cores only may not correlate-able with rock properties. This is possibly due to the diagenetic effect which controls porosity and permeability cannot visually be seen at the core. By incorporating petrographical analysis results, the relationship between porosity, permeability, and lithofacies can be further improved for better reservoir characterization. The study might change the conventional concept that lower quality lithofacies does not have economic hydrocarbon potential and unlock more hydrocarbon-bearing reserves especially in these types of environmental settings.

3-D seismic imaging and interpretation of Brushy Canyon slope and basin thin‐bed reservoirs, northwest Delaware Basin

Geophysics ◽  
1998 ◽  
Vol 63 (5) ◽  
pp. 1507-1519 ◽  
Author(s):  
B. A. Hardage ◽  
J. L. Simmons ◽  
V. M. Pendleton ◽  
B. A. Stubbs ◽  
B. J. Uszynski
Keyword(s):  
Oil Recovery ◽  
Seismic Reflection ◽  
Reservoir Properties ◽  
Entire Study ◽  
Fine Grained ◽  
Delaware Basin ◽  
Reflection Amplitude ◽  
Production Wells ◽  
Reservoir Conditions ◽  
Subsalt Imaging

A study was done at Nash Draw field, Eddy County, New Mexico, to demonstrate how engineering, drilling, geologic, geophysical, and petrophysical technologies should be integrated to improve oil recovery from Brushy Canyon reservoirs at depths of approximately 6600 ft (2000 m) on the northwest slope of the Delaware basin. These thin‐bed reservoirs were deposited in a slope‐basin environment by a mechanism debated by researchers, a common model being turbidite deposition. In this paper, we describe how state‐of‐the‐art 3-D seismic data were acquired, interpreted, integrated with other reservoir data, and then used to improve the sitting of in‐field wells and to provide facies parameters for reservoir simulation across this complex depositional system. The 3-D seismic field program was an onshore subsalt imaging effort because the Ochoan Rustler/Salado, a high‐velocity salt/anhydrite section, extended from the surface to a depth of approximately 3000 ft (900 m) across the entire study area. The primary imaging targets were heterogenous siltstone and fine‐grained sandstone successions approximately 100 ft (30 m) thick and comprised of complex assemblages of thin lobe‐like deposits having individual thickness of 3 to 6 ft (1 to 2 m). The seismic acquisition was complicated further by (1) the presence of active potash mines around and beneath the 3-D grid that were being worked at depths of 500 to 600 ft (150 to 180 m), (2) shallow salt lakes, and (3) numerous archeological sites. We show that by careful presurvey wave testing and attention to detail during data processing, thin‐bed reservoirs in this portion of the Delaware basin can be imaged with a signal bandwidth of 10 to 100 Hz and that siltstone/sandstone successions 100 ft (30 m) thick in the basal Brushy Canyon interval can be individually detected and interpreted. Further, we show that amplitude attributes extracted from these 3-D data are valuable indicators of the amount of net pay and porosity‐feet in the major reservoir successions and of the variations in the fluid transmissivity observed in production wells across the field. Relationships between seismic reflection amplitude and reservoir properties determined at the initial calibration wells have been used to site and drill two production wells. The first well found excellent reservoir conditions; the second well was slightly mispositioned relative to the targeted reflection‐amplitude trend and penetrated reservoir facies typical of that at other producing wells. Relationships between seismic reflection amplitude and critical petrophysical properties of the thin‐bed reservoirs have also allowed a seismic‐driven simulation of reservoir performance to be initiated.

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