bluuebunny/crossref_metadata_2025_split huggingface dataset:
Polymer-Alternating-Gas Simulation—A Case Study
Authors: Li Weirong , Dong Zhenzhen , Sun Jianlei , Schechter David S. 
Published: June 2014

Abstract
Carbon dioxide has been used commercially to recover oil from reservoirs for more than 40 years. Currently, CO2 flooding is the second most applied enhanced oil recovery (EOR) process in the world behind steam flooding. Water alternating gas (WAG) injection has been a popular method to control mobility and improve volumetric sweep efficiency for CO2 flooding. Average EOR is about 9.7% with a range between 6 and 20% for miscible WAG injection. Despite all the success of WAG injection, sweep efficiency during CO2 flooding is a typical challenge to reach higher oil recovery.
We applied polymer-alternating-gas (PAG), in which polymer flooding is combined with miscible CO2 injection, to improve the volumetric sweep efficiency of the WAG process in TR78 of the North Burbank Unit. High heterogeneity and high permeability at the top layers are the two main challenges of the North Burbank Unit. Then, we compared PAG performance with WAG and continuous gas injection (CGI). Polymer concentration and injection slug patterns were optimized during the PAG process. Simulation results show that PAG would increase oil recovery about 14.3% compared with 7.3% for WAG in TR78.
This study can not only be used to guide the development of the North Burbank Unit, but also to demonstrate that encouraging recovery can be obtained in high-heterogeneity reservoirs by using PAG.
Opportunities and Challenges of Polymer Flooding in Heavy Oil Reservoir in South of Oman
Authors: Riethmuller Gaël , Abri Ali , Al Azri Nasser , Stapel Gerco , Nijman Sander , Subhi Wahab , Mehdi Rawa 
Published: June 2014

Abstract
Polymer injection has proven in many places to be a successful EOR technique. However, selecting the polymer injection as the Enhanced Oil Recovery technique to develop quite heavy oil reservoirs with strong bottom water drive has been always a challenge in the oil industry but at the same time it can unlock the opportunities with such unconventional reservoirs.
This paper describes the key opportunities and challenges associated with implementing Enhanced Oil Recovery process in which polymer is injected into a clastic reservoir with a strong bottom aquifer drive bearing heavy-oil (250-500 cP). The high reservoir permeability (2-5 Darcy) enables stretching the viscosity limit of a standard polymer application.
There are several opportunities associated with this project but the key once are using low salinity make up water for injection, recycle back produced polymer and using Alkaline Surfactant Polymer at later phase on the project. The use of low salinity make up water was identified as the most important opportunity as it has the potential to substantially improve the project economics by reducing the polymer consumption while obtaining the same subsurface results. It also has the additional advantage to potentially improve the field UR by reducing the Sor. A number of risks are associated with this opportunity, the main ones being in situ clay swelling, reservoir souring, and decreased polymer stability if mixing with formation water occurs.
Conversely, this project is quite challenging specially with the limited analogues in the oil industry. The key challenges are the impact of back produced polymer, work around the congested urban planning and most importantly make the subsurface concept work. Finally, this paper discusses the solutions and activities to address and mitigate these key risks.
Mukhaizna Steam Surveillance Logging
Authors: Al Shaibi Rashid A. , Al Habsi Ali B. , Al Touqi Wiam K. , Al Hamadani Adil , Al Salmani Al Ghalia 
Published: June 2014

Abstract
Assessing steam injection conformance is one of the challenges faced during developing a multi-zones steam flood project. Critical flow principle was used to develop downhole steam injection control techniques using Limited Entry Perforation and steam injection nozzles and orifices. Evaluating performance of these downhole completion accessories requires adopting and modifying several surveillance tools. Injection Logging Profile (IPL) Tools are used to monitor steam distribution in multi-zones steam injection wells and to investigate steam flow behavior in the wellbore. This paper reviews steam injector surveillance techniques in a giant steam flood field located in south Oman. The article will list advantages, limitations, and the challenges faced with the various interpretation methods including temperature logs, simple flow meters, radioactive tracers, and Pulse Neutron tool surveys. Steam quality estimation methodology will be presented employing logging data and semi-analytical wellbore heat transfer models.
Rheological Assessment of VES as an EOR Fluid in Carbonate Reservoir
Authors: Sultan A. S. , Azad M. S. , Hussein I. A. , Mahmoud M. A. 
Published: June 2014

Abstract
Mobility control is the most important phenomenon that contributes to the volumetric sweep efficiency in enhanced oil recovery processes. Polymers have been used by the industry to provide the required viscosity to the injection fluids. However, applicability of polymers has its limitation. Most of the polymers easily degrade under harsh reservoir conditions. In this work, we investigated the rheological aspect of viscoelastic surfactant (VES) as an alternative to the polymer in chemical EOR processes. VES self assembles at favorable conditions to form wormlike micelles whose length can vary significantly. The conditions ascertained in this work are concentration, shear rate, temperature, time; salinity etc. In addition, the efficiency of VES with the polymer at various conditions was compared. Results indicated that VES can generate higher viscosity at the extreme conditions of reservoirs. This might be beneficial for EOR point of view. Also, the comparative studies confirm the potential of VES over polymer as an EOR fluid.
Optimization of a Large Polymer Flood Using Full-field Streamline Simulation
Authors: Choudhuri Biswajit , Thakuria Chandan , Belushi Abdul Aziz , Nurzaman Zamzam , Hashmi Khalid , Batycky Rod 
Published: June 2014

Abstract
A field scale polymer flood has been in operation since early 2010 in a major oil field of the Sultanate of Oman. The project comprises 27 patterns where water flood was on-going prior to initiation of Polymer flood in 2010. A polymer flood project has high chemical operating expenditure (Opex). Thus, optimization of a polymer flood requires continuous tracking of mass of polymer injected per unit volume of incremental oil produced for individual polymer flood patterns and then polymer throughput in individual patterns needs to be dynamically altered. To meet this objective, a full-field streamline simulation model has been built, history matched and is being used for optimizing the polymer-flood. Full-field simulation allows the proper modeling of each pattern and their interactions with off-set patterns, and these simulations can be performed in a reasonable computation time because of the efficiency of streamline modeling. Computational efficiency of streamline simulation has facilitated use of the model for routine well and reservoir management decisions. This would not have been possible with a finite difference model because of excessive run time and inability to clearly establish injection-production relationship as in a streamline model.
The model has facilitated optimization of polymer flood patterns, specifically when to stop polymer injection, slug size, and slug concentration. Individual pattern performance can be visualized effectively and their efficiency can be compared. The model is also being used for ranking the existing water-flood patterns for the next phase of polymer-flood implementation and carrying out short term production forecast.
Status of Fluid Flow Mechanisms for Miscible and Immiscible WAG
Authors: Skauge Arne , Sorbie Ken 
Published: June 2014

Abstract
Water-Alternating-Gas (WAG) injection has become a well established gas EOR method since field applications were first reported in the late 1950s. WAG can be applied by injecting CO2 or hydrocarbon gases as a miscible process where the gas is (usually multi-contact) miscible with the crude oil (MWAG) or where it is immiscible (IWAG). However, we contend that, even in "MWAG" processes, most of the reservoir is actually "near miscible", which we refer to as nMWAG and this case is discussed in detail in this paper. In many cases, WAG has been regarded as a "large scale" EOR method targeting mainly sweep improvement. However, the fluid flow mechanisms are important both for improving macroscopic sweep and also for improved microscopic displacement efficiency.
Improved microscopic efficiency by lowering residual oil saturation in the three-phase zone can greatly add to the benefit of WAG injection. Indeed, we believe that the fluid flow properties at pore scale and core scale when appropriately upscaled lead to significant oil recovery at the reservoir scale. Therefore, the pore/core scale mechanism are key factors for estimating the recovery efficiency of WAG processes. This paper reviews recent development in our understanding of the mechanisms of both immiscible and miscible /near miscible WAG processes. The discussion connects pore scale physics and core scale observations and explains the implications of these smaller scale processes on the field scale oil recovery by IWAG, MWAG and nMWAG.
Assessing Wellbore Integrity in Sustained-Casing-Pressure Annulus
Authors: Rocha-Valadez T.. , Hasan A.R.. R. , Mannan S.. , Kabir C.S.. S. 
Published: June 2014

Summary
Sustained casing pressure (SCP), exhibited by many wells, is defined as any measurable casing pressure that rebuilds after being bled down, attributable to cause(s) other than artificially applied pressures or temperature fluctuations in the well. Gas leakage, leading to SCP, may occur through the poor cement bond between the casing and the formation, packer, and/or the casing itself. All safety regulators require SCP elimination. However, test-data analysis is mostly qualitative and limited to arbitrary criteria, thereby lacking consensus. This paper attempts to provide a theoretical frame and a model for quantitative analysis of SCP-test data.
Specifically, we adapted a model for SCP that is rooted in the transport processes of the system. The model accounts for mud compressibility and assumes gas is leaking into the annulus and migrating up the annular liquid column. Some robust assumptions about the transport processes allow for expressing the governing equation as a first-order, linear differential equation that is solved with appropriate boundary conditions. The resulting algebraic expression for the casing-pressure rise (Annulus A) with time is easy to apply. A comparison of the performance of the model with field data suggests that gas influx causes a casing-pressure (Annulus A) increase in wells.
Shale-Drape Modeling for the Geologically Consistent Simulation of Clastic Reservoirs
Authors: Alpak Faruk O. , van der Vlugt Frans 
Published: June 2014

SummaryA set of algorithms, called the shale-drape function (SDF), has been developed that incorporates bounding shales (shale drapes) for channels, channel belts (also known as meander belts), lobes and lobe complexes in 3D geologic models used for reservoir simulation. Shale drapes can have a significant impact on the recovery efficiency of clastic reservoirs. Therefore, they need to be modeled when present in significant quantities (in general, more than 50 to 70% in terms of areal coverage). The function incorporates shale drapes into a geologic model with an iterative process that creates shale layers over the entire surface of reservoir objects and then places ellipsoid-shaped holes into shale surfaces until a desired areal coverage is reached. The workflow for application recommends to grid the simulation model along the boundaries of stratigraphic objects, thereby ensuring that the shales can be realistically represented in the fine-scale geomodel and preserved in the post-upscaling simulation model.
Assessing Economic Implications of Complexity in Geological Modeling and Simulation
Authors: Singh Harpreet , Srinivasan Sanjay 
Published: June 2014

Abstract
Economic forecast for assessing reservoir performance is a strong function of geological modeling. Complexity of geological modeling may vary from semivariogram-based models to multiple-point simulation technique. Semivariogram-based stochastic simulation techniques are less complex than multiple-point simulation technique in terms of the amount and type of reservoir information needed to generate the porosity and permeability maps.
This paper assesses economic implication of using geological models of varying levels of complexity. For this we compared the uncertainty in reservoir's long term economic performance obtained by using geological models with varying levels of complexity. Reservoir economic performance is assessed using both the real options valuation (ROV) analysis, a probabilistic approach, and discounted cash flow (DCF) based approach.
The results suggest that it may be appropriate to use simpler geological models for the forecast of volumetric flow rate uncertainty. We see that the economics in terms of ROV obtained from a simple geological model is not significantly different from that of a complex geological model. Similar results also hold true with DCF analysis.
This study could help answer the question of how much detail in reservoir models are necessary if the end objective is to obtain realistic assessment of net economic risk (which would be used to make correct decisions)?
Appraisal and Valuation for Proven Shale Play Acquisition Opportunities
Authors: Chorn L. , Bharali N. , Murali K. 
Published: June 2014

Abstract
Shale asset property consolidation, fractional acquisition of proven properties, and outright company acquisitions generate a growing demand for technical-economic appraisal support. Proven concept plays, attractive to larger oil and gas companies and investment firms, often have large amounts of geology and geophysical data, but may have limited production histories in as many as 100 wells within the regional play. Acquirers must address data management needs, secureaccess to experienced shale professionals, and meet timeconstraints to review, interpret, understand, and value the opportunity. The acquirer must validate the seller’s technical work and assessments, gather additional supporting technical data, develop an economic model from decline curve analyses (including CAPEX and OPEX insights), establish relevant transaction benchmarks, and qualitatively evaluate the operator’s capabilities.
Key components of the appraisal and valuation effort include setting technical and business metric thresholds, organizing key professionals’ work product and interactions, managing data inventory, validating existing analyses, filling in missing data with insights from analog plays, and consolidating results into actionable recommendations. The results of the appraisal and valuation exercise includes an itemization of positives, negatives, and residual uncertainties that the acquirer must incorporate into their portfolio evaluation process and estimate the value created, if the acquisition is consummated. This paper uses a recent successful acquisition to illustrate a workflow that compresses the time required to screen and evaluate a shale play acquisition in the US.
Reserve Technical Potential Management System: Key in Rehabilitation of Mature Field
Authors: Ruslan M. , Caretta F. , Artola R. G. , Gandolfo J. M. 
Published: June 2014

Abstract
The Reserve Technical Potential Management System (RTPMS) is divided into 5 main stages and associated together with the Petroleum Reserve Management System by SPE. The main aim by merging these two concepts is to improve understanding of the reserves pool and therefore provide a practical guideline on a standard definition for high level planning and day-to-day operations. The concept is being developed with major focus on the rehabilitation of mature fields where each barrel of oil counts and uncertainty, both technical and economical, are becoming more challenging at industry level. High decline in productivity and increased operational challenges are common issues for mature fields. Recurrently, lower recovery factors are mainly driven by reservoir characterization uncertainty and management, geological complexity, limited resources and operational efficiency. This paper addresses some of these challenges in an integrated manner.
Each stage is mapped and associated with the SPE Petroleum Reserve Management System, the project management control level, the time cycle (short: operation efficiency, medium : production optimization and long: reservoir management), a digital oilfield concept, the roles and responsibilities of the stakeholders, the technology groups and their key technologies. The five stages are defined as; 1) Actual Potential, 2) Operational Technical Potential, 3) Constrained Technical Potential, 4) Theoretical Technical Potential and 5) Ultimate Technical Potential.
The concept has been developed based on lessons learnt and best practices acquired in mature field rehabilitation projects.
The Value of Assessing Uncertainty in Oil and Gas Portfolio Optimization
Authors: Hdadou Houda , McVay Duane A. 
Published: June 2014

Abstract
It has been shown in the literature that the oil and gas industry deals with a substantial number of biases that impact project evaluation and portfolio performance. Previous studies concluded that properly estimating uncertainties will significantly impact the success of risk takers and their profits. Although a considerable number of publications investigated the impact of cognitive biases, few of these publications tackled the problem from a quantitative point of view.
The objective of this study is to demonstrate the value of quantifying uncertainty and evaluate its impact on the optimization of oil and gas portfolios, taking into consideration the risk of each project. A model has been developed to perform portfolio optimization using Markowitz's theory. In this study, portfolio optimization has been performed in the presence of different levels of overconfidence and directional bias to determine the impact of these biases on portfolio performance.
The results show that disappointment in performance occurs not only because the net present value (NPV) of the realized portfolio is lower than estimated, but also because the risk of the realized portfolio is higher than estimated. This disappointment is due to both incorrect estimation of value and risk (estimation error) and incorrect project selection (decision error). The results of the cases analyzed show that, for investors with high-risk-tolerance, moderate overconfidence and moderate optimism result in an expected disappointment of about 50% of the estimated portfolio. For investors with low-risk-tolerance, the same amounts of moderate overconfidence and optimism result in an expected disappointment up to 78% of the estimated portfolio. The value of reliably quantifying uncertainty is reducing the expected disappointment and the expected decision error. This can be achieved by eliminating overconfidence in project evaluation and portfolio optimization; optimism is reduced in the process. Consequently, overall industry performance can be improved because reliable uncertainty assessment enables identification of superior portfolios, with optimum reward and risk levels, and increases the probability of meeting expectations.
Decision Analytics, Value of Information, and Piloting in Unconventional Reservoirs
Authors: Bickel J. Eric 
Published: June 2014

Abstract
Suppose we plan to develop a field by drilling up to N wells. Each well i (= 1 to N) will produce an uncertain quantity of reserves Xi. We assume that the Xi are identically distributed with common mean m and variance s2 This is often reasonable, as companies view the development of unconventional reservoirs as a statistical plays; some wells will be profitable and others will not. Lacking an ability to identify the wells that fall into each category, a package of wells is drilled with the hope that the average reserves m will exceed some minimum threshold t.
We further assume that given m and s2 are known, the wells are probabilistically independent. Therefore, we assume the wells are independent and identically distributed (iid). In practice, the iid assumption means that (1) we do not have any reason to believe one location is likely to be more profitable than any other and (2) the drilling results at one location do not change our beliefs about the potential profitability of another location, given that m and s2 are known. If either m or s2 are uncertain then prior drilling results at one or more locations will tell us something about the future prospects for the field.
Estimating Long Term Well Performance in the Montney Shale Gas Reservoir
Authors: Dinh Vu P. , Gouge Brad A. , White Aaron 
Published: June 2014

Abstract
Establishing long term production decline in unconventional reservoirs is challenging due to the high degree of uncertainty associated with well and reservoir properties. When Arps’ hyperbolic rate decline method is applied in extremely low permeability reservoirs, we usually obtain b-parameter values higher than 1 which may lead to overestimation of future production. One practical way to constraint future production is to switch from hyperbolic to a terminal exponential rate decline at a specified time (a.k.a. "modified hyperbolic relation"). Since most Montney Shale Gas horizontal wells have not reached stabilized boundary dominated flow due to low matrix permeability, the difficulty with using this technique is that the terminal exponential decline rate cannot be established in advance and typically must be specified from experience.
This paper presents one practical approach to establishing the terminal exponential decline rate for the Montney Shale Gas in Canada. Using the analysis techniques proposed by Blasingame and Lee (1986), important formation characteristics can be estimated analytically from post transient exponential decline. By evaluating long-term production trends of existing vertical wells, reservoir pore volume can be determined along with other naturally-fractured reservoir characteristics such as matrix) fracture permeability ratio and dimesionless fracture storage. Since horizontal wells’ production performance is strongly influence by the same natural fracture reservoir characteristics, this easy to use approach provides a reasonable estimate of terminal exponential decline parameters.
The Relationship Between Operational Costs and Oil Prices: A Contribution for Probabilistic Economic Assessment
Authors: Hastenreiter L. , Hamacher S. , Montechiari J. 
Published: June 2014

Abstract
This article presents a probabilistic methodology for estimating the Net Present Value (NPV) of oil and gas production development projects. This methodology takes into account the uncertainties of important variables present in the economic evaluation, such as oil and gas production, prices, investments and operational costs. Furthermore, this paper aims to understand the impact of oil price change in the behavior of costs. It also presents a case study which allows indentifying and analyzing the results of the methodology implementation. The results show the importance of evaluating and quantifying the uncertainties in the economic appraisal, as well as the need to consider the effect of oil price changes. Hence, it points out an alternative to estimate the expect returns on investments according to a probabilistic approach, which can impact one of the most important variables for the economic project decision-making, the Net Present Value.