Mohr-Coulomb Envelope Based on Geomechanical Studies: West Siberian Fields Case Studies. Applied Methods

2021 ◽  
Author(s):  
Arthur Ahatovich Kunakasov ◽  
Evgeniy Viktorovich Kharkov ◽  
Robert Aleksandrovich Chigirev
Keyword(s):  
Oil Recovery ◽  
Triaxial Compression ◽  
Strength Criterion ◽  
Strength Properties ◽  
Development Project ◽  
Reservoir Properties ◽  
Well Drilling ◽  
Efficient Planning ◽  
External Forces ◽  
Multistage Loading

Abstract The strength properties of the rock determine many physical processes occurring in the formation and at the bottom of the well. Deformation and destruction of rocks under the influence of external forces can be both a positive and a negative factor for working with formations at all stages of development. To create the optimal design of the well drilling trajectory, select the optimal development project, the fluids extraction rate from the formations, efficient planning and implementation of hydraulic fracturing procedures, prevention of emergencies during drilling and operation and reduction of oil recovery due to irreversible loss of reservoir properties and solving many other problems, it is necessary to consider possible destruction of the rock. The Mohr-Coulomb envelope (rock strength passport) can be used as a strength criterion for such tasks, it characterizes the boundary values of stresses in the rock, at which its destruction occurs according to the Mohr-Coulomb theory. At article discusses three methods for determinate strength passports based on the results of laboratory studies of rock samples: multistage loading of the sample, assessment of the sample fracture after triaxial compression strength test, the use of "twin" samples for testing. The features of each method, its advantages and limitations are disclosed, examples of construction of strength passports for rocks from fields in Western Siberia are shown. According to the research results, the most preferable is the use of "twin" samples. However, this method is associated with technical difficulties.

scholarly journals Investigation on degradation mechanism of polymer blockages in unconsolidated sandstone reservoirs

e-Polymers ◽  
2020 ◽  
Vol 20 (1) ◽  
pp. 55-60
Author(s):  
Wenting Dong ◽  
Dong Zhang ◽  
Keliang Wang ◽  
Yue Qiu
Keyword(s):  
Oil Recovery ◽  
Degradation Mechanism ◽  
Injection Pressure ◽  
Polymer Flooding ◽  
Core Flooding ◽  
Reservoir Properties ◽  
Thermal Analyzer ◽  
Sandstone Reservoirs ◽  
Suction Index ◽  
Weighing Method

AbstractPolymer flooding technology has shown satisfactorily acceptable performance in improving oil recovery from unconsolidated sandstone reservoirs. The adsorption of the polymer in the pore leads to the increase of injection pressure and the decrease of suction index, which affects the effect of polymer flooding. In this article, the water and oil content of polymer blockages, which are taken from Bohai Oilfield, are measured by weighing method. In addition, the synchronous thermal analyzer and Fourier transform infrared spectroscopy (FTIR) are used to evaluate the composition and functional groups of the blockage, respectively. Then the core flooding experiments are also utilized to assess the effect of polymer plugs on reservoir properties and optimize the best degradant formulation. The results of this investigation show that the polymer adsorption in core after polymer flooding is 0.0068 g, which results in a permeability damage rate of 74.8%. The degradation ability of the agent consisting of 1% oxidizer SA-HB and 10% HCl is the best, the viscosity of the system decreases from 501.7 to 468.5 mPa‧s.

scholarly journals Development of an analytical model to predict oil reservoirs performance using mechanical waves propagation

2021 ◽  
Author(s):  
Hesham A. Abu Zaid ◽  
◽  
Sherif A. Akl ◽  
Mahmoud Abu El Ela ◽  
Ahmed El-Banbi ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Field Measurements ◽  
Field Trials ◽  
Oil Field ◽  
Reservoir Properties ◽  
Actual Performance ◽  
Reservoir Performance ◽  
Mechanical Waves ◽  
Incremental Oil Recovery ◽  
Wave Induced

The mechanical waves have been used as an unconventional enhanced oil recovery technique. It has been tested in many laboratory experiments as well as several field trials. This paper presents a robust forecasting model that can be used as an effective tool to predict the reservoir performance while applying seismic EOR technique. This model is developed by extending the wave induced fluid flow theory to account for the change in the reservoir characteristics as a result of wave application. A MATLAB program was developed based on the modified theory. The wave’s intensity, pressure, and energy dissipation spatial distributions are calculated. The portion of energy converted into thermal energy in the reservoir is assessed. The changes in reservoir properties due to temperature and pressure changes are considered. The incremental oil recovery and reduction in water production as a result of wave application are then calculated. The developed model was validated against actual performance of Liaohe oil field. The model results show that the wave application increases oil production from 33 to 47 ton/day and decreases water-oil ratio from 68 to 48%, which is close to the field measurements. A parametric analysis is performed to identify the important parameters that affect reservoir performance under seismic EOR. In addition, the study determines the optimum ranges of reservoir properties where this technique is most beneficial.

Production Optimization Coupling Multiple Reservoirs and Facilities With Sour Gas Re-Injection for Miscible EOR in South Oman

2021 ◽  
Author(s):  
Kamlesh Kumar ◽  
Varun Pathak ◽  
Pankaj Agrawal ◽  
Zaal Alias ◽  
Tushar Narwal ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Production System ◽  
Gas Injection ◽  
Ghg Emissions ◽  
Development Project ◽  
Production Optimization ◽  
Oil Reservoirs ◽  
Fully Implicit ◽  
Gas Utilization ◽  
Sour Gas

Abstract Effective gas utilization is critical to any gas injection development project to maximize recoveries for a given purchase of make-up gas, whilst reducing the Green Gas House (GHG) emissions. This paper describes the use of a fully implicit Integrated Production System Model (IPSM) for two inter-connected production system networks, coupling multiple, critically sour oil reservoirs undergoing Miscible Gas Injection (MGI) for Enhanced Oil Recovery (EOR) using produced sour gas from oil and condensate fields in South Oman. The IPSM model links sixteen reservoir models with varying levels of complexities to the facilities network. Complexities in the facilities include multiple nodal constraints that necessitate the use of an Equation of State model (EOS). The IPSM model honors the gas balance implicitly. Gas flood optimization includes prioritizing low GOR production wells (at reservoir and well level) whilst maintaining reservoir pressure above Minimum Miscibility Pressures (MMP). Development schedule optimization also helps in optimizing the compressor size, the key Capex component. Compositional modeling allows continuous tracking of souring levels at different nodes, providing integrity status of overall production system network. The current IPSM model helps in optimization of schedule for the phased development of the oil reservoirs and eventually the most efficient gas utilization. This has enabled low pressure operation in some reservoirs providing oil at very low unit technical cost while waiting for gas availability. Compositional tracking for H2S helps in operating the facilities within design limits whilst planning future developments to cater to this design. Some key parameters can be parameterized for quick sensitivity analysis for an informed decision making for business opportunities. The production potential of the system is also tracked to ensure there is a cushion in the system to deal with any unexpected changes. This feature helps in planning and optimizing the scheduled turn-around activities for these two inter-connected production system networks. The novelty of this work is collaboration across multiple disciplines, especially the surface and subsurface because of complex interactions between facilities constraints and reservoir performance (associated with produced gas reinjection). Compositional tracking and injection gas apportionment across multiple reservoirs is key to the overall value maximization in this complex development.

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.

Prediction of mobile water in a tight gas sandstone reservoir using NMR and fractional flow model

2014 ◽  
Vol 54 (2) ◽  
pp. 1
Author(s):  
Maria Anantawati ◽  
Suryakant Bulgauda
Keyword(s):  
Steady State ◽  
Relative Permeability ◽  
Flow Model ◽  
Bound Water ◽  
Free Water ◽  
Development Project ◽  
Asia Pacific ◽  
Fractional Flow ◽  
Reservoir Properties ◽  
Mobile Water

One of the objectives of petrophysical interpretation is the estimation of the respective volumes of formation fluids. With traditional interpretation using conventional openhole logs it is only possible to determine the total amount of water. The challenge is to determine the volumes of bound water (clay-bound and capillary-bound) and free water. At the moment, NMR is the only measurement that can help distinguish the volumes of each water component (clay-bound, capillary-bound and mobile), using cut-offs on T2 (transverse relaxation time). However NMR interpretation also requires information on reservoir properties. Alternatively, steady-state relative permeability and fractional flow of water can be used to determine the potential of mobile water. The study area, located in the Cooper Basin, South Australia, is the target of a planned gas development project in the Patchawarra formation. It comprises multiple stacked fluvial sands which are heterogeneous, tight and of low deliverability. The sands are completed with multi-stage pin-point fracturing as a key enabling technology for the area. A comprehensive set of data, including conventional logs, cores and NMR logs, were acquired. Routine and special core analysis were performed, including NMR, electrical properties, centrifuge capillary pressure, high-pressure mercury injection, and full curve steady state relative permeability. A fractional flow model was built based on core and NMR data to determine potential mobile water and the results compared with production logs. This paper (SPE 165766) was prepared for presentation at the SPE Asia Pacific Oil & Gas Conference and Exhibition, held in Jakarta, Indonesia, from 22–24 October 2013.

scholarly journals Application of a physics-based lumped parameter model to evaluate reservoir parameters during CO2 storage

2020 ◽  
Vol 10 (8) ◽  
pp. 3925-3935
Author(s):  
Samin Raziperchikolaee ◽  
Srikanta Mishra
Keyword(s):  
Oil Recovery ◽  
Co2 Storage ◽  
Field Application ◽  
Oil Field ◽  
Lumped Parameter Model ◽  
Linear Regression Method ◽  
Oil Reservoir ◽  
Michigan Basin ◽  
Reservoir Properties ◽  
Lumped Parameter

Abstract Evaluating reservoir performance could be challenging, especially when available data are only limited to pressures and rates from oil field production and/or injection wells. Numerical simulation is a typical approach to estimate reservoir properties using the history match process by reconciling field observations and model predictions. Performing numerical simulations can be computationally expensive by considering a large number of grids required to capture the spatial variation in geological properties, detailed structural complexity of the reservoir, and numerical time steps to cover different periods of oil recovery. In this work, a simplified physics-based model is used to estimate specific reservoir parameters during CO2 storage into a depleted oil reservoir. The governing equation is based on the integrated capacitance resistance model algorithm. A multivariate linear regression method is used for estimating reservoir parameters (injectivity index and compressibility). Synthetic scenarios were generated using a multiphase flow numerical simulator. Then, the results of the simplified physics-based model in terms of the estimated fluid compressibility were compared against the simulation results. CO2 injection data including bottom hole pressure and injection rate were also gathered from a depleted oil reef in Michigan Basin. A field application of the simplified physics-based model was presented to estimate above-mentioned parameters for the case of CO2 storage in a depleted oil reservoir in Michigan Basin. The results of this work show that this simple lumped parameter model can be used for a quick estimation of the specific reservoir parameters and its changes over the CO2 injection period.

scholarly journals Effect of salinity on oil production: review on low salinity waterflooding mechanisms and exploratory study on pipeline scaling

2020 ◽  
Vol 75 ◽  
pp. 50 ◽  
Author(s):  
Tao Zhang ◽  
Yiteng Li ◽  
Chenguang Li ◽  
Shuyu Sun
Keyword(s):  
Oil Recovery ◽  
Rapid Development ◽  
Preliminary Investigation ◽  
Petroleum Industry ◽  
Phase Field Model ◽  
Scale Formation ◽  
Wettability Alteration ◽  
Reservoir Properties ◽  
Low Salinity ◽  
Low Salinity Waterflooding

The past decades have witnessed a rapid development of enhanced oil recovery techniques, among which the effect of salinity has become a very attractive topic due to its significant advantages on environmental protection and economical benefits. Numerous studies have been reported focusing on analysis of the mechanisms behind low salinity waterflooding in order to better design the injected salinity under various working conditions and reservoir properties. However, the effect of injection salinity on pipeline scaling has not been widely studied, but this mechanism is important to gathering, transportation and storage for petroleum industry. In this paper, an exhaustive literature review is conducted to summarize several well-recognized and widely accepted mechanisms, including fine migration, wettability alteration, double layer expansion, and multicomponent ion exchange. These mechanisms can be correlated with each other, and certain combined effects may be defined as other mechanisms. In order to mathematically model and numerically describe the fluid behaviors in injection pipelines considering injection salinity, an exploratory phase-field model is presented to simulate the multiphase flow in injection pipeline where scale formation may take place. The effect of injection salinity is represented by the scaling tendency to describe the possibility of scale formation when the scaling species are attached to the scaled structure. It can be easily referred from the simulation result that flow and scaling conditions are significantly affected if a salinity-dependent scaling tendency is considered. Thus, this mechanism should be taken into account in the design of injection process if a sustainable exploitation technique is applied by using purified production water as injection fluid. Finally, remarks and suggestions are provided based on our extensive review and preliminary investigation, to help inspire the future discussions.

Anisotropic shear strength of a residual soil of sandstone

2008 ◽  
Vol 45 (3) ◽  
pp. 367-376 ◽  
Author(s):  
Adriano Virgilio Damiani Bica ◽  
Luiz Antônio Bressani ◽  
Diego Vendramin ◽  
Flávia Burmeister Martins ◽  
Pedro Miguel Vaz Ferreira ◽  
...  
Keyword(s):  
Shear Strength ◽  
Effective Stress ◽  
Yield Surface ◽  
Triaxial Compression ◽  
Strength Properties ◽  
Triaxial Tests ◽  
Residual Soil ◽  
Compression Tests ◽  
Soil Stiffness ◽  
Particle Bonding

This paper discusses results of laboratory tests carried out with a residual soil originated from the weathering of eolian sandstone from southern Brazil. Parent rock features, like microfabric and particle bonding, are remarkably well preserved within this residual soil. Stiffness and shear strength properties were evaluated with consolidated drained (CID) and consolidated undrained (CIU) triaxial compression tests. Undisturbed specimens were tested with two different orientations between the specimen axis and bedding surfaces (i.e., parallel (δ = 0°) or perpendicular (δ = 90°)) to investigate the effect of anisotropy. When CID triaxial tests were performed with δ = 0°, the yield surface associated with the structure was much larger than when tests were performed with δ = 90°. Coincidently, CIU tests with δ = 0° showed peak shear strengths much greater than for δ = 90° at comparable test conditions. Once the peak shear strength was surpassed, CIU tests followed collapse-type effective stress paths not shown by corresponding tests with remolded specimens. A near coincidence was observed between the yield surface determined with CID tests and the envelope of collapse-type effective stress paths for δ = 0° and δ = 90°.

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