Investigation and Optimization of the Effects of Geologic Parameters on the Performance of Gravity-Stable Surfactant Floods

SPE Journal ◽  
2016 ◽  
Vol 21 (03) ◽  
pp. 761-775 ◽  
Author(s):  
Shayan Tavassoli ◽  
Gary A. Pope ◽  
Kamy Sepehrnoori
Keyword(s):  
Salinity Gradient ◽  
Horizontal Wells ◽  
Sensitivity Study ◽  
Third Order ◽  
Fine Grid ◽  
Heterogeneous Reservoirs ◽  
Vertical Permeability ◽  
Well Spacing ◽  
Optimization Schemes ◽  
Very High

Summary A systematic simulation study of gravity-stable surfactant flooding was performed to understand the conditions under which it is practical and to optimize its performance. Different optimization schemes were introduced to minimize the effects of geologic parameters and to improve the performance and the economics of surfactant floods. The simulations were carried out by use of horizontal wells in heterogeneous reservoirs. The results show that one can perform gravity-stable surfactant floods at a reasonable velocity and with very-high sweep efficiencies for reservoirs with high vertical permeability. These simulations were carried out with a 3D fine grid and a third-order finite-difference method to accurately model fingering. A sensitivity study was conducted to investigate the effects of heterogeneity and well spacing. The simulations were performed with realistic surfactant properties on the basis of laboratory experiments. The critical velocity for a stable surfactant flood is a function of the microemulsion (ME) viscosity, and it turns out there is an optimum value that one can use to significantly increase the velocity and still be stable. One can optimize the salinity gradient to gradually change the ME viscosity. Another alternative is to inject a low-concentration polymer drive following the surfactant slug (without polymer). Polymer complicates the process and adds to its cost without a significant benefit in most gravity-stable surfactant floods, but an exception is when the reservoir is highly layered. The effect of an aquifer on gravity-stable surfactant floods was also investigated, and strategies were developed for minimizing its effect on the process.

EVALUATION AND MANAGEMENT OF THIN OIL COLUMN RESERVOIRS IN AUSTRALIA

1994 ◽  
Vol 34 (1) ◽  
pp. 64 ◽  
Author(s):  
H. R. Irrgang
Keyword(s):  
Column Height ◽  
Gas Oil ◽  
Well Performance ◽  
Oil Viscosity ◽  
Heterogeneous Reservoirs ◽  
Vertical Permeability ◽  
Well Spacing ◽  
Hydrocarbon Reserve ◽  
Water Cut ◽  
Dipping Strata

Thin oil columns represent a common and important class of hydrocarbon reserve which are notoriously difficult to evaluate and produce. This paper provides case studies of examples of these reservoirs in Australia and summarises the production methods, well performance and recovery efficiencies.Thin oil column reservoirs are defined here as reservoirs which will cone both water and gas when produced at commercial rates. The oil zone can have a pancake or rim geometry. Examples within Australia include Bream and Snapper (Gippsland Basin), South Pepper and Chervil (Carnarvon Basin), Chookoo (Eromanga Basin) and Taylor (Surat Basin).Parameters which are particularly important in defining the performance of these reservoirs are: horizontal and vertical permeability, column height, stratigraphie dip, well spacing, and oil viscosity. High horizontal permeability is more critical than in other reservoir types as it controls the effectiveness of gravitational forces in opposing coning and other unwanted flows by reducing pressure gradients. Low vertical permeability mitigates coning but can limit across strike drainage in dipping strata. Oil viscosity is also particularly important, even when the mobility ratio is favourable, as it controls the gas/oil ratio and water cut during coning.As coning (by definition) is inevitable the key production issue is gas cap management. The main options are:Limit gas coning by controlling completion depth and production rates.Allow gas cap shrinkage and 'chase' the oil column upwards via recompletions.Reinject gas to control gas-oil contact position.For the latter two options in particular, ultimate reserves are a strong function of the capacity of the installed production facilities, especially offshore, where fixed operating costs are high. When gas cap management is not compromised, reserves increase with higher total fluid withdrawal rates. Examples of the various gas cap management and production strategies are included.Both horizontal (South Pepper, Bream) and conventional (Chookoo, Taylor) completion techniques have been applied to thin oil column reservoirs in Australia. Horizontal completions can increase productivity, mitigate coning and increase the well drainage areas (particularly if drilled across dip in heterogeneous reservoirs). However, horizontal completions are particularly vulnerable to poor cement jobs, natural fractures and undesirable fluid contact movements.A variety of other completion techniques have been tried worldwide in thin oil columns with mixed success. These include multiple completions in the water, oil and/or gas to allow separate production, and injection of fluids to make permeability barriers or alter relative permeability.A number of scaling rules are included to assist in using offset field data for evaluation of thin oil column reservoirs. Improved understanding of these complex reservoirs will maximise their economic potential.

Frontal-Stability Analysis of Surfactant Floods

SPE Journal ◽  
2015 ◽  
Vol 20 (03) ◽  
pp. 471-482 ◽  
Author(s):  
Shayan Tavassoli ◽  
Gary A. Pope ◽  
Kamy Sepehrnoori
Keyword(s):  
Oil Recovery ◽  
Surfactant Solution ◽  
Mobility Control ◽  
Surfactant Flooding ◽  
Control Cost ◽  
Fine Grid ◽  
Heterogeneous Reservoirs ◽  
Vertical Permeability ◽  
Reservoir Conditions ◽  
The Stability

Summary Recent surfactant-flooding experiments have shown that very-efficient oil recovery can be obtained without mobility control when the surfactant solution is injected at less than the critical velocity required for a gravity-stable displacement. The purpose of this study was to develop a method to predict the stability of surfactant floods at the reservoir scale on the basis of gravity-stable surfactant-flooding experiments at the laboratory scale. The scaleup process involves calculation of the appropriate average frontal velocity for the reservoir flood. The frontal velocity depends on the well configuration. We have performed systematic numerical simulations to study the effect of key scaling groups on the performance of gravity-stable surfactant floods. We simulated 3D heterogeneous reservoirs by use of a fine grid and a third-order finite-difference method to ensure numerical accuracy. These simulations have provided new insight into the behavior of gravity-stable surfactant floods, and in particular the importance of the microemulsion properties. The capability to predict when and under what reservoir conditions a gravity-stable surfactant flood can be performed at a reasonable velocity is highly significant. When a surfactant flood can be performed without polymer (or foam) for mobility control, cost and complexity are significantly reduced. Advantages are especially significant when the reservoir temperature is high and the use of polymer becomes increasingly difficult. Our simulations show that gravity-stable surfactant floods can be very efficient using horizontal wells in reservoirs with high vertical permeability.

scholarly journals THE USE OF THE STOKES-STRUIK APPROXIMATION FOR WAVES OF FINITE HEIGHT

2011 ◽  
Vol 1 (6) ◽  
pp. 16
Author(s):  
L. E. Borgman ◽  
J. E. Chappelear
Keyword(s):  
Wave Profile ◽  
Third Order ◽  
The Third ◽  
Finite Height ◽  
Particle Velocities ◽  
Relationship Of ◽  
The Relationship ◽  
Permanent Form ◽  
Very High ◽  
Water Depths

A formal approximate solution is derived for the profile and velocity components of a wave with permanent form of finite height m moderate water depths. The approximation is carried to the third order, sufficiently far to represent all except the very high "design" waves. The relationship of the formulas to others found in the literature is discussed. The wavelengths and the coefficients in the third-order series for the wave profile, and the water particle velocities and local accelerations are tabulated for approximately 2000 waves. The depths, heights, and periods for the listed wave conditions vary respectively from 10 to 500 feet, 5 to 40 feet, and 4 to 20 seconds. The range of applicability of the theory is discussed and approximate limits estimated. As an aid in calculations, tables of the trigonometric and hyperbolic sines and cosines for integral multiples of the argument are included.

Individual Fracture Efficiency Monitoring in Horizontal Wells by Using a New 3d Fine-Grid Temperature Modelling

2021 ◽  
Author(s):  
Vitaly Virt ◽  
Vladimir Kosolapov ◽  
Vener Nagimov ◽  
Andrey Salamatin ◽  
Yulia Fesina ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Oil Recovery ◽  
Transient Analysis ◽  
Horizontal Wells ◽  
Sweep Efficiency ◽  
Fine Grid ◽  
Hydrodynamic Parameters ◽  
Multistage Hydraulic Fracturing ◽  
Multi Stage ◽  
Differential Efficiency

Abstract Profitable development of hard-to-recover reserves often involves drilling of horizontal wells with multistage hydraulic fracturing to increase the oil recovery factor. Usually to monitor the fracture sweep efficiency, pressure transient analysis is used. However, in case of several fractures this method delivers only average hydrodynamic parameters of the well-fracture system. This paper illustrates the value of temperature logging data and demonstrates possibilities of the 3-D thermo-mechanical modelling in evaluating the differential efficiency of multi-stage hydraulic fracturing.

Best Practices in DFIT Interpretation: Comparative Analysis of 62 DFITs from Nine Different Shale Plays

2022 ◽  
Author(s):  
Mark Mcclure ◽  
Garrett Fowler ◽  
Matteo Picone
Keyword(s):  
Pressure Drop ◽  
Pore Pressure ◽  
Time Pressure ◽  
Early Time ◽  
Horizontal Wells ◽  
Late Time ◽  
Fracture Length ◽  
Well Spacing ◽  
Net Pressure ◽  
The Difference

Abstract In URTeC-123-2019, a group of operators and service companies presented a step-by-step procedure for interpretation of diagnostic fracture injection tests (DFITs). The procedure has now been applied on a wide variety of data across North and South America. This paper statistically summarizes results from 62 of these DFITs, contributed by ten operators spanning nine different shale plays. URTeC-123-2019 made several novel claims, which are tested and validated in this paper. We find that: (1) a ‘compliance method’ closure signature is apparent in the significant majority of DFITs; (2) in horizontal wells, early time pressure drop due to near-wellbore/midfield tortuosity is substantial and varies greatly, from 500 to 6000+ psi; (3) in vertical wells, early-time pressure drop is far weaker; this supports the interpretation that early- time pressure drop in horizontal wells is caused by near-wellbore/midfield tortuosity from transverse fracture propagation; (4) the (not recommended) tangent method of estimating closure yields Shmin estimates that are 100-1000+ psi lower than the estimate from the (recommended) compliance method; the implied net pressure values are 2.5x higher on average and up to 5-6x higher; (5) as predicted by theory, the difference between the tangent and compliance stress and net pressure estimates increases in formations with greater difference between Shmin and pore pressure; (6) the h-function and G-function methods allow permeability to be estimated from truncated data that never reaches late-time impulse flow; comparison shows that they give results that are close to the permeability estimates from impulse linear flow; (7) false radial flow signatures occur in the significant majority of gas shale DFITs, and are rare in oil shale DFITs; (8) if false radial signatures are used to estimate permeability, they tend to overestimate permeability, often by 100x or more; (9) the holistic-method permeability correlation overestimates permeability by 10-1000x; (10) in tests that do not reach late-time impulse transients, it is reasonable to make an approximate pore pressure estimate by extrapolating the pressure from the peak in t*dP/dt using a scaling of t^(-1/2) in oil shales and t^(3/4) in gas shales. The findings have direct practical implications for operators. Accurate permeability estimates are needed for calculating effective fracture length and for optimizing well spacing and frac design. Accurate stress estimation is fundamental to hydraulic fracture design and other geomechanics applications.

Integrated Analysis of Tracer and Pressure-Interference Tests To Identify Well Interference

SPE Journal ◽  
2020 ◽  
Vol 25 (04) ◽  
pp. 1623-1635 ◽  
Author(s):  
Ashish Kumar ◽  
Puneet Seth ◽  
Kaustubh Shrivastava ◽  
Ripudaman Manchanda ◽  
Mukul M. Sharma
Keyword(s):  
Response Times ◽  
Horizontal Wells ◽  
Integrated Approach ◽  
Pressure Response ◽  
Integrated Analysis ◽  
Well Drilling ◽  
Tracer Recovery ◽  
Well Spacing ◽  
Fractured Horizontal Wells ◽  
Interference Tests

Summary In ultralow-permeability reservoirs, communication between wells through connected fractures can be observed through tracer and pressure-interference tests. Understanding the connectivity between fractured horizontal wells in a multiwell pad is important for infill well drilling and parent-child well interactions. Interwell tracer and pressure-interference tests involve two or more fractured horizontal wells and provide information about hydraulic-fracture connectivity between the wells. In this work, we present an integrated approach based on the analysis of tracer and pressure interference data to obtain the degree of interference between fractured horizontal wells in a multiwell pad. We analyze well interference using tracer (chemical tracer and radioactive proppant tracer) and pressure data in an 11-well pad in the Permian Basin. Changes in pressure and tracer concentration in the monitor wells were used to identify and evaluate interference between the source and monitor wells. Extremely low tracer recovery and weak pressure response signify the absence of connected fractures and suggest that interference through matrix alone is insignificant. Combined tracer and pressure-interference data suggest connected fracture pathways between the communicating wells. The degree of interference can be estimated in terms of pressure response times and tracer recovery. An effective reservoir model was used to simulate pressure interference between wells during production. Simulation results indicate that well interference observed during production is primarily because of hydraulically connected fractures. Combined tracer and pressure-interference analysis provides a unique tool for understanding the time-dependent connectivity between communicating wells, which can be useful for optimizing infill well drilling, well spacing, and fracture sizing in future treatment designs.

Stress Measurements in Polished Al-Mg Alloy and CrN Coating Using Multireflection Grazing Incidence Method

2014 ◽  
Vol 783-786 ◽  
pp. 2091-2096 ◽  
Author(s):  
Marianna Marciszko ◽  
Andrzej Baczmański ◽  
Krzysztof Wierzbanowski ◽  
Jean Paul Chopart ◽  
Alain Lodini ◽  
...  
Keyword(s):  
Lattice Strain ◽  
Stress Gradient ◽  
Grazing Incidence ◽  
Mg Alloy ◽  
Third Order ◽  
Crn Coating ◽  
X Ray ◽  
The Third ◽  
Microstructure Density ◽  
Very High

The multi-reflection grazing incidence X-ray diffrection was used to determine residual stress gradient in the mechanically polished Al-Mg alloy and CrN coating. Also, the root mean square values of the third order lattice strain was determined using Wiliamson-Hall method. The results obtained for Al-Mg alloy show that the stress field in the surface layer as well as the microstructure (density of dislocation) depend strongly on the sample preparation. A very high residual compressive stress, which does not change significantly with depth, was measured in the CrN coating. Moreover, a large value of the measured third order strains in the coating was found.

Computational Fluid Dynamics Study for Modeling Vortex Induced Vibrations Using High Fidelity Turbulence Models

2012 ◽  
Author(s):  
Madhusuden Agrawal ◽  
Mohammad A. Elyyan
Keyword(s):  
Drag Coefficient ◽  
Turbulence Models ◽  
Sensitivity Study ◽  
Fine Mesh ◽  
Adaptive Simulation ◽  
Model Flow ◽  
Vortex Induced Vibrations ◽  
Smooth Cylinder ◽  
High Reynolds ◽  
Very High

Flow over smooth cylinder at very high Reynolds number, ReD = 2×106, is simulated using the unsteady Scale Adaptive Simulation (SAS) turbulence model. Flow structures and vortex shedding were accurately captured. Grid sensitivity study was performed to compare averaged drag coefficient for a conformal fine mesh as well as non-conformal coarse mesh. Predicted value of drag coefficient was within 8% of the experimental value and Strouhal number compared well with the experimental observations.

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