Interwell Tracer Tests To Optimize Operating Conditions for a Surfactant Field Trial: Design, Evaluation, and Implications

2012 ◽  
Vol 15 (02) ◽  
pp. 229-242 ◽  
Author(s):  
Hao Cheng ◽  
G. Michael Shook ◽  
Malik Taimur ◽  
Varadarajan Dwarakanath ◽  
Bruce R. Smith
Keyword(s):  
Oil Recovery ◽  
Field Trial ◽  
Tracer Tests ◽  
Tracer Test ◽  
Operating Conditions ◽  
Small Scale ◽  
Hydraulic Control ◽  
Sweep Efficiency ◽  
Reservoir Properties ◽  
Swept Volume

Summary Enhanced oil recovery (EOR) by surfactant flooding is the key to unlocking the next billion barrels of oil for Minas, one of the world's largest waterflood fields. An interwell tracer test (ITT-1) was performed before a surfactant field trial (SFT) to ensure well injectivity, demonstrate pattern confinement, quantitatively describe interwell connectivity and sweep efficiency, and provide sufficient data for reservoir evaluation. The tracer test was designed by numerical simulation. The test started in November 2009 and was terminated in February 2010. Analytical interpretation based on moment analysis and numerical reservoir simulations was conducted to evaluate ITT-1 results. Interpretation of the test results indicated various operational and reservoir properties that would have likely led to failure of the surfactant pilot. Hydraulic control of the SFT pattern was not achieved; in fact, less than 20% of one tracer was recovered. Many small-scale heterogeneities were identified that led to a lower-than-expected reservoir volume contacted. Unexpected communication between the target sand and the underlying sands outside the pattern also contributed to low tracer recovery and low swept volume. The tracer test was history matched, and additional features were incorporated in the reservoir model, and a new tracer design (ITT-2) was optimized to correct low sweep efficiency and poor hydraulic control. New information from ITT-2 will be used to further optimize operating conditions for SFTs. Failure to conduct the tracer tests would have likely revealed these unfavorable reservoir and operational conditions during the SFT. Had oil recovery been poor (because of low swept volume), it would have erroneously been attributed to a poor SFT rather than to the true causes. ITT-1 is considered successful because it allowed us to redesign injection/hydraulic control during the relatively inexpensive tracer test and thus evaluate the surfactant trial without bias.

Horizontal Versus Vertical Wells: Assessment of Sweep Efficiency in a Multi-Layered Reservoir Based on Consecutive Inter-Well Tracer Tests - A Comparison Between Water Injection and Polymer EOR

2021 ◽  
Author(s):  
Bogdan-George Davidescu ◽  
Mathias Bayerl ◽  
Christoph Puls ◽  
Torsten Clemens
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Tracer Tests ◽  
Horizontal Wells ◽  
Operating Conditions ◽  
Sweep Efficiency ◽  
Flow Paths ◽  
Full Field ◽  
Polymer Injection ◽  
The Impact

Abstract Enhanced Oil Recovery pilot testing aims at reducing uncertainty ranges for parameters and determining operating conditions which improve the economics of full-field deployment. In the 8.TH and 9.TH reservoirs of the Matzen field, different well configurations were tested, vertical versus horizontal injection and production wells. The use of vertical or horizontal wells depends on costs and reservoir performance which is challenging to assess. Water cut, polymer back-production and pressures are used to understand reservoir behaviour and incremental oil production, however, these data do not reveal insights about changes in reservoir connectivity owing to polymer injection. Here, we used consecutive tracer tests prior and during polymer injection as well as water composition to elucidate the impact of various well configurations on sweep efficiency improvements. The results show that vertical well configuration for polymer injection and production leads to substantial acceleration along flow paths but less swept volume. Polymer injection does not only change the flow paths as can be seen from the different allocation factors before and after polymer injection but also the connected flow paths as indicated by a change in the skewness of the breakthrough tracer curves. For horizontal wells, the data shows that in addition to acceleration, the connected pore volume after polymer injection is substantially increased. This indicates that the sweep efficiency is improved for horizontal well configurations after polymer injection. The methodology leads to a quantitative assessment of the reservoir effects using different well configurations. These effects depend on the reservoir architecture impacting the changes in sweep efficiency by polymer injection. Consecutive tracer tests are an important source of information to determine which well configuration to be used in full-field implementation of polymer Enhanced Oil Recovery.

scholarly journals Investigation on the effect of active-polymers with different functional groups for EOR

e-Polymers ◽  
2020 ◽  
Vol 20 (1) ◽  
pp. 61-68
Author(s):  
Dong Zhang ◽  
Jian Guang Wei ◽  
Run Nan Zhou
Keyword(s):  
Functional Groups ◽  
Oil Recovery ◽  
Molecular Size ◽  
Type I ◽  
Cleaning Efficiency ◽  
Sweep Efficiency ◽  
Profile Control ◽  
Branched Chain ◽  
Swept Volume ◽  
Enhance Oil Recovery

AbstractActive-polymer attracted increasing interest as an enhancing oil recovery technology in oilfield development owing to the characteristics of polymer and surfactant. Different types of active functional groups, which grafted on the polymer branched chain, have different effects on the oil displacement performance of the active-polymers. In this article, the determination of molecular size and viscosity of active-polymers were characterized by Scatterer and Rheometer to detect the expanded swept volume ability. And the Leica microscope was used to evaluate the emulsifying property of the active-polymers, which confirmed the oil sweep efficiency. Results show that the Type I active-polymer have a greater molecular size and stronger viscosity, which is a profile control system for expanding the swept volume. The emulsification performance of Type III active-polymer is more stable, which is suitable for improving the oil cleaning efficiency. The results obtained in this paper reveal the application prospect of the active-polymer to enhance oil recovery in the development of oilfields.

Interwell Tracer Tests to Optimize Operating Conditions for a Surfactant Field Trial: Design, Evaluation and Implications

2011 ◽  
Author(s):  
Hao Cheng ◽  
G. Michael Shook ◽  
Malik Taimur ◽  
Varadarajan Dwarakanath ◽  
Bruce Raymond Smith ◽  
...  
Keyword(s):  
Field Trial ◽  
Trial Design ◽  
Tracer Tests ◽  
Operating Conditions ◽  
Design Evaluation

scholarly journals Analytical Model of Waterflood Sweep Efficiency in Vertical Heterogeneous Reservoirs under Constant Pressure

2016 ◽  
Vol 2016 ◽  
pp. 1-9 ◽  
Author(s):  
Lisha Zhao ◽  
Li Li ◽  
Zhongbao Wu ◽  
Chenshuo Zhang
Keyword(s):  
Analytical Model ◽  
Oil Recovery ◽  
Constant Pressure ◽  
Water Saturation ◽  
Water Injection ◽  
Single Layer ◽  
Sweep Efficiency ◽  
Heterogeneous Reservoirs ◽  
Water Cut ◽  
Swept Volume

An analytical model has been developed for quantitative evaluation of vertical sweep efficiency based on heterogeneous multilayer reservoirs. By applying the Buckley-Leverett displacement mechanism, a theoretical relationship is deduced to describe dynamic changes of the front of water injection, water saturation of producing well, and swept volume during waterflooding under the condition of constant pressure, which substitutes for the condition of constant rate in the traditional way. Then, this method of calculating sweep efficiency is applied from single layer to multilayers, which can be used to accurately calculate the sweep efficiency of heterogeneous reservoirs and evaluate the degree of waterflooding in multilayer reservoirs. In the case study, the water frontal position, water cut, volumetric sweep efficiency, and oil recovery are compared between commingled injection and zonal injection by applying the derived equations. The results are verified by numerical simulators, respectively. It is shown that zonal injection works better than commingled injection in respect of sweep efficiency and oil recovery and has a longer period of water free production.

An Investigation of Mechanistic Foam Modeling for Optimum Field Development of CO2 Foam EOR Application

2021 ◽  
pp. 1-20
Author(s):  
Mohammad Izadi ◽  
Phuc H. Nguyen ◽  
Hazem Fleifel ◽  
Doris Ortiz Maestre ◽  
Seung I. Kam
Keyword(s):  
Oil Recovery ◽  
Population Balance ◽  
Development Planning ◽  
Operating Conditions ◽  
Sweep Efficiency ◽  
Population Balance Modeling ◽  
Field Development ◽  
Injection Condition ◽  
Gas Mobility ◽  
Injection Rates

Summary While there are a number of mechanistic foam models available in the literature, it still is not clear how such models can be used to guide actual field development planning in enhanced oil recovery (EOR) applications. This study aims to develop the framework to determine the optimum injection condition during foam EOR processes by using a mechanistic foam model. The end product of this study is presented in a graphical manner, based on the sweep-efficiency contours (from reservoir simulations) and the reduction in gas mobility (from mechanistic modeling of foams with bubble population balance). The main outcome of this study can be summarized as follows: First, compared to gas/water injection with no foams, injection of foams can improve cumulative oil recovery and sweep efficiency significantly. Such a tendency is observed consistently in a range of total injection rates tested (low, intermediate, and high total injection rates Qt). Second, the sweep efficiency is more sensitive to the injection foam quality fg for dry foams, compared to wet foams. This proves how important bubble-population-balance modeling is to predict gas mobility reduction as a function of Qt and fg. Third, the graphical approach demonstrates how to determine the optimum injection condition and how such an optimum condition changes at different field operating conditions and limitations (i.e., communication through shale layers, limited carbon dioxide (CO2) supply, cost advantage of CO2 compared to surfactant chemicals, etc.). For example, the scenario with noncommunicating shale layers predicts the maximum sweep of 49% at fg = 55% at high Qt, while the scenarios with communicating shale layers (with 0.1-md permeability) predicts the maximum sweep of only 40% at fg = 70% at the same Qt. The use of this graphical method for economic and business decisions is also shown, as an example, to prove the versatility and robustness of this new technique.

The Effects of Interfacial Tension Dependent Relative Permeability on Sweep Efficiency and Oil Recovery Under Different Gas Injection Composition

2021 ◽  
Author(s):  
Mohd Ghazali Abd Karim ◽  
Wahyu Hidayat ◽  
Alzahrani Abdulelah
Keyword(s):  
Interfacial Tension ◽  
Simulation Model ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Gas Injection ◽  
Sweep Efficiency ◽  
Reservoir Properties ◽  
Relative Permeability Curve ◽  
Compositional Model ◽  
The Impact

Abstract The objective of this paper is to investigate the effects of interfacial tension dependent relative permeability (Kr_IFT) on oil displacement and recovery under different gas injection compositions utilizing a compositional simulation model. Oil production under miscible gas injection will result in variations of interfacial tension (IFT) due to changes in oil and gas compositions and other reservoir properties, such as pressure and temperature. Laboratory experiments show that changes in IFT will affect the two-phase relative permeability curve (Kr), especially for oil-gas system. Using a single relative permeability curve during the process from immiscible to miscible conditions will result in inaccurate gas mobility against water, which may lead to poor estimation of sweep efficiency and oil recovery. A synthetic sector compositional model was built to evaluate the effects of this phenomenon. Several simulation cases were investigated over different gas injection compositions (lean, rich and CO2), fluid properties and reservoir characterizations to demonstrate the impact of these parameters. Simulation model results show that the application of Kr_IFT on gas injection simulation modelling has captured different displacement behavior to provide better estimation of oil recovery and identify any upside potential.

scholarly journals Chemical Migration and Emulsification of Surfactant-Polymer Flooding

2019 ◽  
Vol 2019 ◽  
pp. 1-8 ◽  
Author(s):  
Jierui Li ◽  
Weidong Liu ◽  
Guangzhi Liao ◽  
Linghui Sun ◽  
Sunan Cong ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Polymer Flooding ◽  
Water Flooding ◽  
Sweep Efficiency ◽  
Equal Concentration ◽  
Multiple Sample ◽  
Water Cut ◽  
And Migration ◽  
Swept Volume ◽  
Chemical Migration

With a long sand-packed core with multiple sample points, a laboratory surfactant-polymer flooding experiment was performed to study the emulsification mechanism, chemical migration mechanism, and the chromatographic separation of surfactant-polymer flooding system. After water flooding, the surfactant-polymer flooding with an emulsified system enhances oil recovery by 17.88%. The water cut of produced fluid began to decrease at the injection of 0.4 pore volume (PV) surfactant-polymer slug and got the minimum at 1.2 PV. During the surfactant-polymer flooding process, the loss of polymer is smaller than that of surfactant, the dimensionless breakthrough time of polymer is 1.092 while that of surfactant is 1.308, and the dimensionless equal concentration distance of the chemical is 0.65. During surfactant-polymer flooding, the concentration of surfactant controls the formation of the emulsion. From 50 cm to 600 cm, as the migration distance increases, the concentration of surfactant decreases, and the emulsification strength and duration decrease gradually. With the formation of emulsion, the viscosity of the emulsion is relatively stable, which is beneficial to enhanced oil recovery. With the shear of reservoirs and migration of surfactant-polymer slug, the emulsion is formed to improve the swept volume and sweep efficiency and enhance oil recovery.

Interpretation of geologic facies in seismic volume using key rock elastic properties and high-definition facies templates

2017 ◽  
Vol 5 (2) ◽  
pp. SE11-SE27 ◽  
Author(s):  
Mahbub Alam ◽  
Sabita Makoon-Singh ◽  
Joan Embleton ◽  
David Gray ◽  
Larry Lines
Keyword(s):  
Elastic Properties ◽  
Oil Recovery ◽  
Seismic Data ◽  
Effective Porosity ◽  
Rock Properties ◽  
Small Scale ◽  
High Definition ◽  
Reservoir Properties ◽  
Particle Volume ◽  
Reservoir Architecture

We have developed a deterministic workflow in mapping the small-scale (centimeter level) subseismic geologic facies and reservoir properties from conventional poststack seismic data. The workflow integrated multiscale (micrometer to kilometer level) data to estimate rock properties such as porosity, permeability, and grain size from the core data; effective porosity, resistivity, and fluid saturations using petrophysical analyses from the log data; and rock elastic properties from the log and poststack seismic data. Rock properties, such as incompressibility (lambda), rigidity (mu), and density (rho) are linked to the fine-particle-volume (FPV) ranges of different facies templates. High-definition facies templates were used in building the high-resolution (centimeter level) near-wellbore images. Facies distribution and reservoir properties between the wells were extracted and mapped from the FPV data volume built from the poststack seismic volume. Our study focused on the heavy oil-bearing Cretaceous McMurray Formation in northern Alberta. The internal reservoir architecture, such as the stacked channel bars, inclined heterolithic strata, and shale plugs, is intricate due to reservoir heterogeneity. Drilling success or optimum oil recovery will depend on whether the reservoir model accurately describes this heterogeneity. Thus, it is very important to properly identify the distribution of the permeability barriers and shale plugs in the reservoir zone. Dense vertical well control and dozens of horizontal well pairs over the area of investigation confirm a very good correlation of the geologic facies interpreted between the wells from the seismic volume.

scholarly journals Tracer Dispersion through Karst Conduit: Assessment of Small-Scale Heterogeneity by Multi-Point Tracer Test and CFD Modeling

Hydrology ◽  
2021 ◽  
Vol 8 (4) ◽  
pp. 168
Author(s):  
Romain Deleu ◽  
Sandra Soarez Frazao ◽  
Amaël Poulain ◽  
Gaëtan Rochez ◽  
Vincent Hallet
Keyword(s):  
Spatial Heterogeneity ◽  
Single Point ◽  
Tracer Tests ◽  
Tracer Test ◽  
Breakthrough Curves ◽  
Cfd Modeling ◽  
Small Scale ◽  
Tracer Concentration ◽  
Tracer Dispersion ◽  
The Impact

Tracer tests are widely used for characterizing hydrodynamics, from stream-scale to basin-wide scale. In karstic environments, the positioning of field fluorometers (or sampling) is mostly determined by the on-site configuration and setup difficulties. Most users are probably aware of the importance of this positioning for the relevance of data, and single-point tests are considered reliable. However, this importance is subjective to the user and the impact of positioning is not well quantified. This study aimed to quantify the spatial heterogeneity of tracer concentration through time in a karstic environment, and its impact on tracer test results and derived information on local hydrodynamics. Two approaches were considered: on-site tracing experiments in a karstic river, and Computational Fluid Dynamics (CFD) modeling of tracer dispersion through a discretized karst river channel. A comparison between on-site tracer breakthrough curves and CFD results was allowed by a thorough assessment of the river geometry. The results of on-site tracer tests showed significant heterogeneities of the breakthrough curve shape from fluorometers placed along a cross-section. CFD modeling of the tracer test through the associated discretized site geometry showed similar heterogeneity and was consistent with the positioning of on-site fluorometers, thus showing that geometry is a major contributor of the spatial heterogeneity of tracer concentration through time in karstic rivers.

Simulation and Dimensional Analysis of Foam Processes in Porous Media

1998 ◽  
Vol 1 (02) ◽  
pp. 148-154 ◽  
Author(s):  
J.-X. Shi ◽  
W.R. Rossen
Keyword(s):  
Aspect Ratio ◽  
Pressure Gradient ◽  
Oil Recovery ◽  
Dimensionless Number ◽  
Gravitational Acceleration ◽  
Sweep Efficiency ◽  
Reservoir Properties ◽  
Improved Oil Recovery ◽  
Wide Range ◽  
Continuous Injection

Abstract Foam can improve sweep efficiency in gas-injection improved-oil-recovery processes. The success of continuous-injection foam processes in overcoming gravity override in homogeneous, anisotropic (kx kz) radial or rectangular reservoirs depends on a single dimensionless number first proposed by Stone and Jenkins for gas flooding without foam. Their model fits foam simulation results remarkably well over a wide range in reservoir properties and geometry, flow rates, foam quality and foam strength, density difference between phases, initial reservoir pressure, and model for the mechanisms of foam collapse. This approach leads to optimal design strategies for such processes. It may be impossible, however, for a continuous-injection foam process to suppress gravity override in some cases, due to limitations on injection-well pressure. The possibility of gravity override within the foam bank should be considered in evaluating foam propagation in field trials of foam processes Introduction Gases, such as steam, carbon dioxide, natural gas, and nitrogen, are used as driving fluids in improved-oil-recovery (IOR) processes. However, these gases have high mobilities compared with oil and, thus, tend to finger through oil as well as to channel selectively through zones of high permeability. Also, because they are less dense than oil, these gases tend to migrate to the top of the reservoir, overriding oil-rich zones. Gas channeling and gravity override lead to poor sweep efficiency. Foam can significantly reduce gas mobility and overcome these problems under certain conditions, and therefore, improve sweep efficiency. This paper examines the ability of foam to overcome gravity override in homogeneous reservoirs. By inspectional analysis, Shook et al. obtain five scaling numbers rigorously sufficient to characterize a two-phase immiscible displacement process, given certain assumptions. These assumptions include incompressible, completely immiscible phases; a homogeneous, rectangular, horizontal, possibly anisotropic (kx kz) reservoir; absence of dispersion; and relative permeabilities that fit Corey expressions. (Six groups are required to characterize a process in a tilted reservoir.) For a foam process, the number of groups required would be much larger, due to the complexities of representing foam behavior. However, though a complete characterization is not guaranteed with fewer groups, it is possible that only a portion of these groups effectively govern behavior under many conditions. Shook et al. for instance, found that only three groups are needed to characterize waterfloods under a wide range of conditions, and Craig correlated waterflood sweep efficiency in terms of a gravity number and a reservoir aspect ratio. Suitable definitions for these two parameters for foam processes would be [1] [2] where Ng is gravity number, the ratio of the vertical driving force for segregation to horizontal pressure gradient; RL is reservoir aspect ratio; Pf is the lateral pressure gradient within the foam bank in the absence of gravity segregation; is the difference in densities between gas and liquid; g is gravitational acceleration; L and H are reservoir length and height, respectively; and kx and kz are absolute horizontal and vertical permeabilities. Note that Eq. 2 uses the first power of the ratio of horizontal to vertical permeability rather than the square root of this ratio as proposed by Shook et al. and Rossen et al.; the reason is discussed below. Others have noted the importance of the relative magnitude of viscous and gravity forces in foam processes and other processes. A similar analysis may apply to capillary crossflow with foam.

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