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.

scholarly journals Integrated Halo Model And Hydrodynamic Simulation For Optimization Oil Production In Crystalline Fractured Reservoirs

2021 ◽  
Author(s):  
Hung Vo Thanh ◽  
Kang-Kun Lee
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Fractured Reservoirs ◽  
Petroleum Industry ◽  
Oil Production ◽  
Modelling And Simulation ◽  
Development Plan ◽  
Sweep Efficiency ◽  
Field Development ◽  
The World

Abstract Basement formation is known as the unique reservoir in the world. The fractured basement reservoir was contributed a large amount of oil and gas for Vietnam petroleum industry. However, the geological modelling and optimization of oil production is still a challenge for fractured basement reservoirs. Thus, this study aims to introduce the efficient workflow construction reservoir models for proposing the field development plan in a fractured crystalline reservoir. First, the Halo method was adapted for building the petrophysical model. Then, Drill stem history matching is conducted for adjusting the simulation results and pressure measurement. Next, the history-matched models are used to conduct the simulation scenarios to predict future reservoir performance. The possible potential design has four producers and three injectors in the fracture reservoir system. The field prediction results indicate that this scenario increases approximately 8 % oil recovery factor compared to the natural depletion production. This finding suggests that a suitable field development plan is necessary to improve sweep efficiency in the fractured oil formation. The critical contribution of this research is the proposed modelling and simulation with less data for the field development plan in fractured crystalline reservoir. This research's modelling and simulation findings provide a new solution for optimizing oil production that can be applied in Vietnam and other reservoirs in the world.

Data Analytics into Hydraulic Modelling for Better Understanding of Well/Surface Network Limits, Proactively Identify Challenges and, Provide Solutions for Improved System Performance in the Greater Burgan Field

2021 ◽  
Author(s):  
Qasem Dashti ◽  
Saad Matar ◽  
Hanan Abdulrazzaq ◽  
Nouf Al-Shammari ◽  
Francy Franco ◽  
...  
Keyword(s):  
Production Management ◽  
Planning Process ◽  
System Optimization ◽  
Development Planning ◽  
Operating Conditions ◽  
Flow Assurance ◽  
Operational Parameters ◽  
Field Development ◽  
Hydraulic Models ◽  
Surface Network

Abstract A network modeling campaign for 15 surface gathering centers involving more than 1800 completion strings has helped to lay out different risks on the existing surface pipeline network facility and improved the screening of different business and action plans for the South East Kuwait (SEK) asset of Kuwait Oil Company. Well and network hydraulic models were created and calibrated to support engineers from field development, planning, and operations teams in evaluating the hydraulics of the production system for the identification of flow assurance problems and system optimization opportunities. Steady-state hydraulic models allowed the analysis of the integrated wells and surface network under multiple operational scenarios, providing an important input to improve the planning and decision-making process. The focus of this study was not only in obtaining an accurate representation of the physical dimension of well and surface network elements, but also in creating a tool that includes standard analytical workflows able to evaluate wells and surface network behavior, thus useful to provide insightful predictive capability and answering the business needs on maintaining oil production and controlling unwanted fluids such as water and gas. For this reason, the model needs to be flexible enough in covering different network operating conditions. With the hydraulic models, the evaluation and diagnosis of the asset for operational problems at well and network level will be faster and more effective, providing reliable solutions in the short- and long-terms. The hydraulic models enable engineers to investigate multiple scenarios to identify constraints and improve the operations performance and the planning process in SEK, with a focus on optimal operational parameters to establish effective wells drawdown, evaluation of artificial lifting requirements, optimal well segregation on gathering centers headers, identification of flow assurance problems and supporting production forecasts to ensure effective production management.

INTEGRATED TECHNOLOGY OF BROWN FIELD STUDY TO INCREASE PRODUCTION AND OIL RECOVERY

2020 ◽  
pp. 61-66
Author(s):  
I.A. Zhdanov ◽  
E.S. Pakhomov ◽  
A.M. Aslanyan ◽  
R.R. Farakhova ◽  
D.N. Gulyaev ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Field Studies ◽  
Development Planning ◽  
Reservoir Modeling ◽  
Integrated Analysis ◽  
Well Testing ◽  
Reservoir Model ◽  
Scenario Development ◽  
Sweep Efficiency ◽  
High Level

Paper presents the results of integrated analysis of historically available data and additional field studies at the brown field. The results of the analysis increase the reliability of the geological and hydrodynamic reservoir model, current recovery and identification of areas, which are most promising for production enhancement operations for production increase and recovery increase. The integrated analysis of available data includes such tools as prelaminar data analysis of production and pressure changes (Prime) for high level reserves localization, multiwell retrospective testing (MRT) and pulsecode testing (PCT) for evaluation of reservoir geology, sweep efficiency and current reservoir saturation, geological and hydrodynamic reservoir modeling including petrofacies and model adaptation to the production logging, MRT, PCT and well-testing findings, multi-scenario development planning (MSDP) for the most economically profitable operations recommendation and supervision of their implementation. MSDP is based on the usage by several teams of reservoir engineers web-facility PloyPlan, which automatically translates the field activities (like drilling, workover, conversion, surveillance, etc.) into the model runs and reverts back with production and surveillance results and financial statements, based on which it is easy to choose the most profitable field operations. Up to today Prime analysis, field studies and reservoir model calibration on their results are finished.

Analytical Modeling of Oil Recovery by Steam Injection: Part 2-Asymptotic and Approximate Solutions (include associated papers 10943 and 10951 )

1981 ◽  
Vol 21 (02) ◽  
pp. 179-190 ◽  
Author(s):  
Y.C. Yortsos ◽  
G.R. Gavalas
Keyword(s):  
Heat Transfer ◽  
Oil Recovery ◽  
Dimensionless Parameter ◽  
Approximate Solutions ◽  
Steam Injection ◽  
Operating Conditions ◽  
Liquid Zone ◽  
Approximate Expressions ◽  
Zone Growth ◽  
Injection Rates

Abstract This article studies the development of asymptotic and approximate solutions for the growth of the steam zone in steam injection processes in one-dimensional reservoirs at constant injection rates. These solutions generally are derived by using integral balances which include heat losses to the surroundings and the hot liquid zone. In this way, the effects of preheating caused by heat transport in the hot liquid zone ahead of the steam front are accounted for completely. At the beginning of injection, the advance of the front is well described by the Marx-Langenheim (ML) model, provided that the injection rates are sufficiently high. At longer times, deviations occur and a criterion is developed in terms of a single heat transfer dimensionless parameter, R, that defines the time interval of applicability of the ML model. The asymptotic behavior at large times depends solely on a dimensionless parameter, F, defined as the ratio of the latent to the total heat injected. It is shown that the final dimensionless expression does not depend on R (i.e., on the injection rates) although the time taken to reach the asymptotic state is influenced significantly by R. An approximate analytical solution that reduces to the respective asymptotic expressions at small and large times is obtained under conditions of high injection rates (R »1). The solution is shown to give a better approximation to the steam-zone growth rate for intermediate and large times than the approximate expressions developed by Marx and Langenheim, Mandl and Volek (MV), and Myhill and Stegemeier (MS). For a wider range of operating conditions, including low injection rates (i.e., for R between 1 and), an approximate numerical solution based on a quasisteady state approximation is presented. The proposed solution requiring very modest computation is expected to give reliable results under a variety of operating conditions. Introduction In a previous paper we dealt with the derivation of upper bounds for the volume of the steam zone in one-, two-, or three-dimensional reservoirs. The resulting expressions incorporate minimal information regarding heat transfer in the hot liquid zone and find applications in setting an upper estimate to oil recovery at constant or variable injection rates. To obtain more precise results concerning the steam zone growth, an alternative approach is initiated involving a detailed description of heat transfer in the hot liquid zone. The subject of heat transfer by convection, conduction, and lateral heat losses in the region ahead of a moving condensation front has been discussed separately in another paper. Here we make use of the results obtained in that paper to derive approximate solutions to the volume of the steam zone as a function of time. The relative importance of including preheating effects in the hot liquid zone and the surroundings when calculating the performance of a steam drive is demonstrated by comparing the solutions obtained against simple approximate expressions developed by Marx and Langenheim, and subsequently revised by Mandl and Volek, and Myhill and Stegemeier. From the comparison with exact results, the range of validity of the previous approximations can be delineated. SPEJ P. 179^

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 Development Performance and Pressure Field Evolution of ASP Flooding

2020 ◽  
Vol 2020 ◽  
pp. 1-22
Author(s):  
Junjian Li ◽  
Hao Wang ◽  
Jinchuan Hu ◽  
Hanqiao Jiang ◽  
Rongda Zhang ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Pressure Field ◽  
Laboratory Model ◽  
Displacement Efficiency ◽  
Sweep Efficiency ◽  
Field Development ◽  
Whole Process ◽  
Asp Flooding ◽  
Average Formation ◽  
Physical And Chemical

ASP (alkali-surfactant-polymer) is acknowledged as an effective technology to improve the oil recovery. The microscopic displacement efficiency and macroscopic sweep efficiency have been discussed in detail for the past few years. However, development performance, especially pressure characteristics, needs to be further studied. This paper aims to explore the pressure evolution performance during ASP flooding, of which the results will shed light on development characteristics of ASP flooding. The study on ASP flooding pressure field development is conducted by laboratory and numerical methodology. A large sandpack laboratory model with vertical heterogeneous layers is used to monitor pressure performance during the ASP flooding. With the help of interpolation methods, a precise and intuitive pressure field is obtained based on pressure data acquired by limited measurement points. Results show that the average formation pressure and its location are changing all the time in the whole process. In addition, the influence of heterogeneity and viscosity on recovery and pressure is also probed in this paper. We built a numerical simulation model to match the experiment data considering the physical and chemical alternation in ASP flooding. Also, response surface methodology (RSM) is adopted to obtain the formula between pressure functions and influencing factors.

Optimization of Foam Enhanced Oil Recovery: Balancing Sweep and Injectivity

2013 ◽  
Vol 16 (01) ◽  
pp. 51-59 ◽  
Author(s):  
M. Namdar Zanganeh ◽  
W.R.. R. Rossen
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Mobility Control ◽  
Injection Well ◽  
Productivity Index ◽  
Production Well ◽  
Sweep Efficiency ◽  
Well Productivity ◽  
Gas Mobility

Summary Foam is a means of improving sweep efficiency that reduces the gas mobility by capturing gas in foam bubbles and hindering its movement. Foam enhanced-oil-recovery (EOR) techniques are relatively expensive; hence, it is important to optimize their performance. We present a case study on the conflict between mobility control and injectivity in optimizing oil recovery in a foam EOR process in a simple 3D reservoir with constrained injection and production pressures. Specifically, we examine a surfactant-alternating-gas (SAG) process in which the surfactant-slug size is optimized. The maximum oil recovery is obtained with a surfactant slug just sufficient to advance the foam front just short of the production well. In other words, the reservoir is partially unswept by foam at the optimum surfactant-slug size. If a larger surfactant slug is used and the foam front breaks through to the production well, productivity index (PI) is seriously reduced and oil recovery is less than optimal: The benefit of sweeping the far corners of the pattern does not compensate for the harm to PI. A similar effect occurs near the injection well: Small surfactant slugs harm injectivity with little or no benefit to sweep. Larger slugs give better sweep with only a modest decrease in injectivity until the foam front approaches the production well. In some cases, SAG is inferior to gasflood (Namdar Zanganeh 2011).

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.

Implementing a Water Soluble Solvent Based Enhanced Oil Recovery Technology - Aspects of Field Development Planning

2016 ◽  
Author(s):  
P. te Riele ◽  
C. Parsons ◽  
P. Boerrigter ◽  
J. Plantenberg ◽  
B. Suijkerbuijk ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Development Planning ◽  
Water Soluble ◽  
Field Development
Sign in / Sign up

Export Citation Format

Share Document