Rock Compressibility

2021 ◽  
pp. 57-73
Author(s):  
Amr Mohamed Badawy ◽  
Tarek Al Arbi Omar Ganat
Keyword(s):  
Rock Compressibility

Integrated Subsurface to Surface Modeling to Assess Reservoir Uncertainty Quantification to A Carbonate Reservoir

2020 ◽  
Author(s):  
A. Chaterine
Keyword(s):  
Uncertainty Quantification ◽  
Gas Production ◽  
Carbonate Reservoir ◽  
Production Volume ◽  
Production Forecast ◽  
Uncertainty Range ◽  
Field Development ◽  
Production Forecasting ◽  
Production Scheme ◽  
Rock Compressibility

This study accommodates subsurface uncertainties analysis and quantifies the effects on surface production volume to propose the optimal future field development. The problem of well productivity is sometimes only viewed from the surface components themselves, where in fact the subsurface component often has a significant effect on these production figures. In order to track the relationship between surface and subsurface, a model that integrates both must be created. The methods covered integrated asset modeling, probability forecasting, uncertainty quantification, sensitivity analysis, and optimization forecast. Subsurface uncertainties examined were : reservoir closure, regional segmentation, fluid contact, and SCAL properties. As the Integrated Asset Modeling is successfully conducted and a matched model is obtained for the gas-producing carbonate reservoir, highlights of the method are the following: 1) Up to ± 75% uncertainty range of reservoir parameters yields various production forecasting scenario using BHP control with the best case obtained is 335 BSCF of gas production and 254.4 MSTB of oil production, 2) SCAL properties and pseudo-faults are the most sensitive subsurface uncertainty that gives major impact to the production scheme, 3) EOS modeling and rock compressibility modeling must be evaluated seriously as those contribute significantly to condensate production and the field’s revenue, and 4) a proposed optimum production scenario for future development of the field with 151.6 BSCF gas and 414.4 MSTB oil that yields a total NPV of 218.7 MMUSD. The approach and methods implemented has been proven to result in more accurate production forecast and reduce the project cost as the effect of uncertainty reduction.

A Novel Model for Well Production Performance Estimate in Low-Permeability and Tight Reservoirs Considering Stress Sensitivity

2020 ◽  
Vol 142 (9) ◽  
Author(s):  
Mingda Dong ◽  
Xuedong Shi ◽  
Jie bai ◽  
Zhilong Yang ◽  
Zhilin Qi
Keyword(s):  
Pressure Gradient ◽  
Effective Stress ◽  
Stress Sensitivity ◽  
Production Performance ◽  
Low Permeability ◽  
Threshold Pressure ◽  
Threshold Pressure Gradient ◽  
Vertical Well ◽  
Tight Reservoirs ◽  
Rock Compressibility

Abstract Stress sensitivity phenomenon is an important property in low-permeability and tight reservoirs and has a large impact on the productivity of production wells, which is defined as the effect of effective stress on the reservoir parameters such as permeability, threshold pressure gradient, and rock compressibility change accordingly. Most of the previous works are focused on the effect of effective stress on permeability and threshold pressure gradient, while rock compressibility is critical of stress sensitivity but rarely noticed. A series of rock compressibility measurement experiments have been conducted, and the quantitative relationship between effective stress and rock compressibility is accurately described in this paper. In the experiment, the defects in previous experiments were eliminated by using a new-type core holder. The results show that as the effective stress increases, the rock compressibility becomes lower. Then, a stress sensitivity model that considers the effect of effective stress on rock compressibility is established due to the experimental results. The well performance of a vertical well estimated by this model shows when considering the effect of effective stress on the rock compressibility, the production rate and recovery factor are larger than those without considering it. Moreover, the effect of porosity and confining pressure on the productivity of a vertical well is also studied and discussed in this paper. The results show that the productivity of a vertical well decreases with the increase in overburden pressure, and increases with the increase in the porosity.

scholarly journals Integration of geostatistical realizations in data assimilation and reduction of uncertainty process using genetic algorithm combined with multi-start simulated annealing

2019 ◽  
Vol 74 ◽  
pp. 73 ◽  
Author(s):  
Célio Maschio ◽  
Denis José Schiozer
Keyword(s):  
Genetic Algorithm ◽  
Simulated Annealing ◽  
Data Assimilation ◽  
Relative Permeability ◽  
Reduction Process ◽  
Local Perturbation ◽  
Reservoir Properties ◽  
Water Contact ◽  
Starting Point ◽  
Rock Compressibility

This paper introduces a new methodology, combining a Genetic Algorithm (GA) with multi-start simulated annealing to integrate Geostatistical Realizations (GR) in data assimilation and uncertainty reduction process. The proposed approach, named Genetic Algorithm with Multi-Start Simulated Annealing (GAMSSA), comprises two parts. The first part consists of running a GA several times, starting with certain number of geostatistical realizations, and the second part consists of running the Multi-Start Simulated Annealing with Geostatistical Realizations (MSSAGR). After each execution of GA, the best individuals of each generation are selected and used as starting point to the MSSAGR. To preserve the diversity of the geostatistical realizations, a rule is imposed to guarantee that a given realization is not repeated among the selected individuals from the GA. This ensures that each Simulated Annealing (SA) process starts from a different GR. Each SA process is responsible for local improvement of the best individuals by performing local perturbation in other reservoir properties such as relative permeability, water-oil contact, etc. The proposed methodology was applied to a complex benchmark case (UNISIM-I-H) based on the Namorado Field, located in the Campos Basin, Brazil, with 500 geostatistical realizations and other 22 attributes comprising relative permeability, oil-water contact, and rock compressibility. Comparisons with a conventional GA algorithm are also shown. The proposed method was able to find multiple solutions while preserving the diversity of the geostatistical realizations and the variability of the other attributes. The matched models found by the GAMSSA method provided more reliable forecasts when compared with the matched models found by the GA.

Numerical Modeling of Rock/Casing Interaction in Radioactive-Marker Boreholes of the Northern Adriatic Basin, Italy

2010 ◽  
Vol 13 (06) ◽  
pp. 906-913 ◽  
Author(s):  
N.. Castelletto ◽  
M.. Ferronato ◽  
G.. Gambolati ◽  
C.. Janna ◽  
P.. Teatini
Keyword(s):  
Fe Model ◽  
Land Uplift ◽  
Northern Adriatic ◽  
Geomechanical Properties ◽  
Contact Surfaces ◽  
Rock Compressibility ◽  
Oilfield Development ◽  
In Situ Deformation ◽  
Adriatic Basin

Summary The possible influence of the well casing in reservoir-deformation measurements by the radioactive-marker technique (RMT) is investigated. The issue is quite important because RMT data may be used for a most-representative estimate of the in-situ vertical rock compressibility cM (i.e., a basic parameter to predict the land settlement caused by gas-/oilfield development or the land uplift caused by underground fluid injection). A geomechanical finite-element (FE) model is implemented to evaluate the disturbance caused by the stiffness of the steel casing and the surrounding cement on the amount of deformation around the borehole as detected by RMT. The FE model is integrated by a class of elastoplastic interface FEs (IFEs) specifically designed to account for the potential sliding of the different materials (i.e., along the contact surfaces between the steel casing and the cement, and the cement and the exploited formation). The numerical simulations make use of real casing data and geomechanical information from the Northern Adriatic basin, Italy. The results show that sliding is not likely to occur along the contact surfaces and that RMT appears to be a reliable tool for assessing the actual geomechanical properties of the depleted formation at a depth larger than 1000 m, where the in-situ deformation is negligibly affected by the casing stiffness. In shallow softer units, the compaction as measured by RMT is influenced progressively by casing, with a corresponding likely underestimate of cM.

Comparisons of Uncoupled and Various Coupling Techniques for Practical Field Examples

SPE Journal ◽  
2006 ◽  
Vol 11 (01) ◽  
pp. 89-102 ◽  
Author(s):  
P. Samier ◽  
A. Onaisi ◽  
G. Fontaine
Keyword(s):  
Cold Water ◽  
Water Injection ◽  
Reservoir Properties ◽  
Simplified Approach ◽  
High Pressure High Temperature ◽  
Coupling Techniques ◽  
Rock Compressibility ◽  
Reservoir Simulator ◽  
Practical Field

Summary Generally, in classical reservoir studies, the geomechanical behavior of the porous medium is taken into account by the rock compressibility. Inside the reservoir simulator, the rock compressibility is assumed to be constant or to vary with the pressure of the oil phase. It induces some changes in the porosity field. During the depletion phase or the cold-water injection of high-pressure/high-temperature (HP/HT) reservoirs, the stress state in and around a reservoir can change dramatically. This process might result in rock movements such as compaction, induced fracturing, and enhancement of natural fractures and/or fault activation, which continuously modify the reservoir properties such as the permeabilities and the fault transmissibilities. Modifications of such parameters strongly affect the flow pattern in the reservoir and ultimately the recovery factor. To capture the link between flow and in-situ stresses, it becomes essential to conduct coupled reservoir-geomechanical simulations. This paper compares the use of five types of approach for the reservoir simulations:A classical approach with rock compressibility using only a reservoir simulator.A loose coupled approach between a reservoir simulator (finite volumes) and a geomechanical simulator (finite elements). At given user-defined steps, the hydrocarbon pressures calculated by the reservoir simulator are transmitted to the geomechanical tool, which computes the actual stresses and feeds back iteratively the modifications of the petrophysical properties (porosities and permeabilities) to the reservoir simulator.A one-way coupling: this approach is a simplification of the loose coupled approach in that the modifications are not fed back to the reservoir simulator.A simplified approach using permeability and porosity multipliers inside a reservoir simulator. These multipliers are user-defined curves and vary with the pressure of the oil phase. This approach uses only a reservoir simulator.A coupled approach in which the structural and the flow unknowns (displacement, pressure, and saturations) are solved simultaneously. These approaches are compared for two validation cases and two field cases described in the following.

A New Relationship of Rock Compressibility with Porosity

2004 ◽  
Author(s):  
Chuanliang Li ◽  
Xiaofan Chen ◽  
Zhimin Du
Keyword(s):  
Rock Compressibility ◽  
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