bluuebunny/crossref_metadata_2025_split huggingface dataset:
Degradation (or Lack Thereof) and Drag Reduction of HPAM During Transport in Pipelines
Authors: Stéphane Jouenne , Jérôme Anfray , Philippe R. Cordelier , Khalid Mateen , David Levitt , Inès Souilem , Philippe Marchal , Lionel Choplin , Jonathon Nesvik , Waldman Tom E. 
Published: June 2014

Abstract
Rules of thumb that are used in the industry for polymer flooding projects, tend to limit the distance over which HPAM polymers can be transported in pipelines without undergoing significant degradation. However, in sensitive environments such as offshore facilities where footprint minimization is required, centralization of the polymer hydration process and longdistance transport may be desirable. More reliable rules are required to design the pipe network and to estimate mechanical degradation of polymers during transport in turbulent conditions.
In this work, we present evidence in the form of both empirical, large-scale pipeline experiments as well as theoretical development refuting the claim that polymer pipeline transport is limited by mechanical degradation. Our work concludes that mechanical degradation occurs at a critical velocity which increases as a function of pipe diameter. Provided the critical velocity is not reached in a given pipe, there is no limit to the distance over which polymer solution can be transported.
In addition, the drag reduction of viscous polymer solutions was measured as a function of pipe length, pipe diameter, fluid velocity and polymer concentration. An envelope was defined to fix the minimum and maximum drag reductions expected for a given velocity on larger pipes. For pipes with diameter varying between 14″ and 22″ at a velocity higher than 1 m/s, the drag reduction percentage is anticipated to be between 45 and 80%. A more refined model was developed to predict drag reduction with less uncertainty.
In conclusion, classical design rules applied for water transport (fluid velocity &lt;3m/s) can be applied to the design of a polymer network. Therefor, for tertiary polymer projects, the existing water injection network should be compatible with the mechanical requirements of polymer transportation.
Colloidal Dispersion Gels (CDG): Field Projects Review
Authors: Manrique E. , Reyes S. , Romero J. , Aye N. , Kiani M. , North W. , Thomas C. , Kazempour M. , Izadi M. , Roostapour A. , Muniz G. , Cabrera F. , Lantz M. , Norman C. 
Published: June 2014

Abstract
Colloidal Dispersion Gels (CDG's) have been successfully tested in Argentina, China, USA, and recently in Colombia. However, questions remain whether CDG's can be injected in large volumes and propagate deep into the formation without reducing injectivity and also improve sweep efficiency.
This paper summarizes 31 implemented and ongoing CDG projects in Argentina, Colombia and the U.S. since 2005. Project summary review includes main reservoir properties, operating conditions, pore volume of chemical injected, general project performance, and especially, a detailed analysis of injection logs addressing the injectivity of CDG. Additionally, a general approach for history matching CDG floods is described.
CDG injection volumes in projects reviewed vary from a few thousand barrels to hundreds of thousands of barrels. Projects evaluated did not show injectivity reduction even after more than 600,000 barrels injected in one well. Polymer concentration and polymer: crosslinker ratios ranged from 250 to 1,200 ppm and 20:1 to 80:1, respectively. Aluminum citrate is the most common crosslinker used in field projects. However, chromium triacetate has been used in high salinity and hardness conditions. Key variables to sustain the injection of large volumes of CDG below maximum operating pressure are polymer: crosslinker ratios, polymer concentration, and injection rates to a lesser extent. CDG projects have evolved from small to large treatment volumes showing a positive impact on oil recoveries. Despite large volumes of CDG injected production of polymer in offset producers has rarely been detected. Wellhead pressure response, CDG viscosity, and adsorption/retention (RRF) represents the most important variables needed to match CDG floods.
This study provides the status of the technology and field evidence that CDG's can be injected in large volumes and can propagate into the reservoir without injectivity constraints. This review will also provide guidance to successfully design and evaluate CDG pilot projects. Lessons learned from operating and modeling CDG projects will also be presented.
The Effects of CO2 Concentration in Flue Gas Injection for Heavy Oil Recovery from Fractured Reservoirs during GOGD Process
Authors: Mohsenzadeh A. , Escrochi M. , Afraz M. V. , Ayatollahi Sh. , Karimi Gh. , Iran. Shiraz , Al-wahaibi Y. 
Published: June 2014

Abstract
Considerable heavy oil is accumulated in naturally fractured carbonate reservoirs, with very low oil recovery efficiency through costly production techniques. In this experimental study, the effects of different injecting gases on the performance of immiscible gas injection and the GOGD process have been investigated at reservoir conditions from full sized carbonate cores in a long fractured laboratory model. During this study on heavy crude oil, three different gases: pure CO2, pure N2, and their mixture as synthetic flue gas injection; were used to study the performance of isothermal GOGD process. It was found that the oil recovery before gas breakthrough was mostly from the fracture; however the injected gas mostly affected the amount of oil recovery and its rate from the matrix part. The piston wise displacement during N2 injection and oil swelling during CO2 injection were found to be the most important mechanisms affecting the oil recovery performance before gas breakthrough. On the other hand, It was found that the oil recovery efficiency for CO2 injection after gas breakthrough was mainly due to gas dissolution mechanism and for N2 injection it was because of high oil-gas density difference; both resulted in approximately 14% recovery efficiency of the remained OIP. However, flue gas injection activated both mechanisms simultaneously with their adverse effects and the recovery efficiency decreased to approximately 10% of the remained OIP. It was also concluded that the GOGD mechanism needs to be stimulated by other compatible techniques such as thermal methods, to increase heavy oil recovery from the matrixes of the fractured formations.
Performance Evaluation and Design Aspects of Polymer and Hot Water Co-Injection in an Offshore Heavy Oil Field under Challenging Conditions
Authors: Mukherjee Soujatya , Süss Michael Peter 
Published: June 2014

Abstract
The field discussed in this paper is a highly unconsolidated sandstone reservoir with medium oil viscosities and a large bottom aquifer. Earlier simulations predicted poor primary recovery and a water flooding scenario showed early water breakthrough owing to viscous fingering. As a result, oil recovery from water flooding was severely curtailed because of unfavourable mobility ratio resulting in a low ultimate recovery factor. Therefore, enhanced oil recovery (EOR) was thought of as a possible recourse to increase recovery of this field.
Preliminary polymer flooding study carried out on the basis of the initial geological model helped in identifying some of the key design aspects impacting polymer flooding outcomes. In order to remedy these aspects, the revised geological model focused primarily on reducing uncertainties concerning property modelling and facies distribution. Screening dynamic simulations were performed to construct a recovery distribution function. The P50 case was taken forward for a more in-depth analysis of the current polymer flooding scenarios.
However, polymer flooding a thin heavy oil reservoir with a large bottom aquifer is a highly challenging scenario. Polymer losses to the aquifer are to be expected, even more so because the vertical permeability in the reservoir formation is extremely high. Although simulation results show acceleration in oil production due to improved displacement efficiency resulting from polymer slugs, the polymer losses are quite substantial and probably would render such a process uneconomic. In addition, significant amounts of oil are pushed into the aquifer as a result of injecting viscous water phase into the oil. In an attempt to mitigate these losses, a hybrid scenario was studied, in which hot water and polymer flooding is performed simultaneously. It is shown that under certain operating conditions oil losses can be eliminated, and the absolute amount of polymer losses can be reduced substantially.
Solvent Stimulation to Restore Productivity of Polymer Pattern Producer Wells - A Case Study
Authors: al kalbani Ali , Chandan Thakuria , Kawthar Saqr , Ravula Chakravarthi , Choudhuri Biswajit , Hashmi Khalid 
Published: June 2014

Abstract
The first field scale Polymer flood project in the Middle East region is under operation in an oil field of The Sultanate of Oman since early 2010. The oil field discussed here contains viscous oil (90 cp) was discovered in 1956 and is located in eastern part of South Oman Salt basin. First commercial production started in 1980 from this field. The field has gone through different development phases in its 30 years of history prior starting tertiary recovery phase by polymer flooding.
This Polymer flood project comprises of 27 patterns coversing about one third of the total field IOIP (initial oil in place). It is worth mentioning that whole field is under water flooding and water injection was going on prior to initiation of Polymer flood in 27 injectors.
So far, this project has been running successfully with good performance contributing to significant oil gain. During this successful journey of about 4 years, the project has passed through many expected and unexpected challenges. The well and reservoir management team has been working actively in all those challenges with novel approaches to increase efficiency of this project.
One of the key challenges encountered is reduction in productivity of producer wells in comparison to earlier water flood with same injection volume. In a few polymer wells production rates even dropped by more than 50%. The main challenges for these wells seeing higher drop in liquid rate is that there is no or minimal oil gain in-spite of reduction in water cut due to disproportionate decline in liquid rate.
This reduction in production rate smay be attributed to decrease in producible fluid mobility, high fluid density with polymer slug and skin formation near wellbore. At the same pressure drawdown of the artificial lift pump withdraws less fluid due to increase in fluid density with polymer breakthrough. There are also possibilities of plugging as a result of moving solid fines from the more viscous fluids near the well bore. These caused more drawdown and less fluid produced and resulted in high gross reduction in some wells. In order to overcome these gross decline, chemical treatment using mutual solvent has been carried out in a few wells as trial and has given good result. A detailed analysis is going on to investigate possible causes and accordingly design suitable remedial actions. This paper describes briefly about the principles involved in this solvent stimulation jobs and results of field implementation with real field examples.
Chemical EOR for Heavy Oil: The Canadian Experience
Authors: Delamaide Eric , Bazin Brigitte , Rousseau David , Degre Guillaume 
Published: June 2014

Abstract
Chemical EOR methods such as polymer flooding and ASP (Alkaline-Surfactant-Polymer) are generally not considered suitable for oil viscosities over one or two hundred cp (polymer) or even less (SP/ASP). However this perception is changing, in particular due to field results obtained from a number of chemical EOR pilots or full field floods implemented in Canada in higher viscosity oil in the past few years.
Canada is a country well-known for its heavy oil production; recovery processes such as Cold Heavy Oil Production with Sand (CHOPS) and Steam Assisted Gravity Drainage (SAGD) have been invented there. However cold production is limited in terms of the level of recovery it can achieve and thermal techniques also have limitations in particular when reservoirs are thin. Thus Canadian companies have been pursuing chemical EOR to increase recovery in those types of reservoirs.
The aim of this paper is to review some of the Canadian projects for which public information is available. Several mostly unpublished projects will be discussed in details, and conclusions will be drawn on the applicability of chemical EOR methods in heavy oil.
The practical experience gained in Canada can be applied in other regions of the globe where chemical EOR has so far not been considered or has been screened out because of high viscosity.
Evaluation of Novel Surfactant for Nitrogen-Foam-Assisted EOR in High Salinity Carbonate Reservoirs
Authors: Bageri Ali S. , Sultan Abdullah S. , Kandil Mohamed E. 
Published: June 2014

Abstract
The use of Nitrogen in Foam Assisted Water-Alternating-Gas (FAWAG) can be an alternative to the use of polymer, especially in carbonate reservoirs which generally have low permeability and contain vugs and fractures, for improving the displacement efficiency in chemical-EOR process. In this process foam performs the role of a mobility control agent. By FAWAG process, reducing gas mobility can be achieved by creating more resistance to gas flow since gas bubbles are surrounded in foam by lamella. Oil displacement by foam is strongly dependent on reservoir temperature, pressure and crude oil composition. A number of surfactants have been tested with foam-assisted-N2 flooding. We are presenting a new class of surfactant.
Two approaches were applied to determine the favorable concentration of each surfactant studied: solubility test and foam stability. The effect of salinity was investigated to determine the optimum concentration surfactant. Phase behavior was evaluated and it was observed that oil-in-water micro-emulsion is Winsor Type I. It is believe that low IFT can be obtained at high solubility ratio for the optimum salinity concentration. The performance of foam flooding with nitrogen (N2) for oil recovery in limestone carbonate rocks was studied. The success of the FAWAG process was determined by evaluation of oil recovery, pressure response and effluent from coreflooding experiments. The effects of core permeability, alkaline, and type of surfactants on the performance of the FAWAG were evaluated as well. Maximum recovery of 47.7% of residual oil in place in low permeability was observed compared to 43% of residual oil in place on high permeability core. In addition, the more recovery was obtained when using surfactant without alkaline.
Impact on Crude Dehydration Due To Back Production Of Polymer
Authors: Al Kalbani H. , Al Mandhari M. S. , Al-Hadhrami H. , Philip G. 
Published: June 2014

Abstract
Polymer flooding is an enhanced oil recovery technique that can increase production and improve recovery from mature fields. As polymer flooding is usually considered after other production strategies have been employed, the produced fluids are usually processed through existing facilities. These facilities have not been designed specifically for handling produced polymer which can affect the facility performance. For a polymer flood field in the Sultanate of Oman, the impact on crude dehydration was identified as a major risk to the existing facilities. A series of tests on emulsion breaking and heater fouling were conducted to determine the potential impact and identify any means of mitigating them. Produced fluids from the field containing polymer were tested along with synthetic polymer designed to mimic the produced polymer properties. A polymer handling limit was established for emulsion breaking in the facilities as well as the fouling potential for the crude oil heaters and a temperature threshold above which fouling occurs.
Evaluation of Foaming Agents for EOR Applications in Carbonate Reservoirs
Authors: Fuseni Alhasan , Han Ming , Al-Aseeri Abdulrahman 
Published: June 2014

Abstract
Enhanced oil recovery applications in carbonate reservoirs present the unique challenges of high salinity and high temperature. For foam applications, foaming agents that have good stability at those harsh conditions are therefore desirable. Crude oil, especially light crude has been known to be a destabilizer for foams and therefore foaming agents need to be designed to handle reservoirs with such oil. In this work, we sought to improve our understanding of the de-foaming behavior of Arabian light crude oil on foams generated using an anionic foaming agent and an amine oxide surfactant. Potential anionic and amphoteric foaming agents dissolved in seawater were screened using the dynamic foam analyzer as well as the high temperature high pressure cell. The stability of foam in the presence and absence of crude oil was studied using both nitrogen and air. Foam decay curves were plotted as a function of time.
Foam decay with time for both types of surfactant fitted a log decay curve confirming the assumption of exponential decay behavior. A semi-log plot of foam decay revealed interesting phenomena along the decay curve. Three regions were shown by the semi-log plot representing liquid drainage, drainage and coalescence and coalescence alone. In general, foam decay was faster in the presence of oil than without oil as shown by the foam half-life calculated for each case. The effect of pressure on foam stability was also investigated at a temperature of 90°C. Generally, foam stability tended to be better at higher pressures in most cases. Foam stability parameters were also evaluated to indicate the relative stabilities of foams generated. The amine oxide, while having excellent solubility in seawater also had a longer liquid drainage section as well as a longer decay time in the presence of oil, than the anionic foaming agent. The harsh conditions of high salinity and high temperature present in carbonate reservoirs therefore favor the amphoterics as better candidates.
Microemulsion Flow in Porous Media: Potential Impact on Productivity Loss
Authors: Izadi Mehdi , Kazemi Hossein , Manrique Eduardo J , Kazempour Mahdi , Rohilla Neeraj 
Published: June 2014

Abstract
Surfactant-polymer (SP) flooding is an enhanced oil recovery (EOR) technique used to mobilize residual oil by lowering the oil-water interfacial tension, micellar solubilization, and lowering the displacing phase mobility to improve sweep efficiency. Surfactant-polymer flooding, also known as micellar flooding, has been studied both in the laboratory and field pilot tests for several decades. Traditionally, a tapered polymer solution follows the injected surfactant. However, in recent years co-injection of surfactant and relatively high concentration polymer solution has been used in several field trials. Despite significant increase in oil recovery in the early stage of surfactant-polymer flooding, in some projects, the early increase in oil productivity period has been short followed by significant reduction in well productivity. We believe productivity loss results from surfactant-polymer interaction and fluid rheology alterations near production well. To evaluate this hypothesis, we injected microemulsion (with and without polymer) in Berea core plugs at residual oil saturation, and chased the surfactant with polymer solution or water. The objective was to determine the cause of productivity reduction and to develop a numerical model for simulating SP flooding in the field.
To achieve our objective, we searched for causes of productivity loss in field when using SP flooding. The search indicated that polymer-microemulsion interactions lead to high-pressure drop and significant productivity loss at the production well. Numerical modeling of several core floods pointed to the same conclusions because the numerical model required a large residual resistance factor (RRF) or a highly viscous aqueous phase near the production end. This information will be used to improve the design of future ASP/SP fluid systems.
An Innovative Process to Unlock Heavy Oil Resources in a Highly Fractured Carbonate Field
Authors: Salmi Salim S. , Romeiro Pedro , Balushi Mohammed Al 
Published: June 2014

Abstract
Mukhaizna field is one of the old fields in Southern Central of Oman. It was discovered in 1975, where Gharif was the primary target. Since then, the oil production was solely coming from Gharif reservoirs. Due to regular evidence of potential presence of hydrocarbon in Kahmah and Khuf groups from conventional wireline logs and old mud logs. Therefore, by early 2010, petrophysics was used heavily to validate the status of Kahmah group in terms of reservoir properties, mobility, pay thickness, and productivity across block-53 in Mukhaizna. The outcome of this analysis, Kahmah group found to hold more than 500 million barrels of heavy oil in place. Later, the appraisal was executed in phases and productivity was validated by placement of horizontal wells within this group at different locations.
This paper will demonstrate the discovery process, appraisal results and focus on a very innovative thermal enhanced oil recovery technique introduced by Occidental Mukhaizna. This technique is expected to unlock similar resources of heavy oil in highly fractured carbonate in Oman and the region with estimated oil in place to be greater than 130 billion barrels.
Improving Condensate Recovery of a Rich Sour Gas Condensate Field by Gas Recycling
Authors: Cobanoglu M. , Khayrutdinov F. , Linthorst S. , Iqbal M. 
Published: June 2014

Abstract
This paper concerns a gas condensate reservoir located in the South of Oman. The field is characterized by compositional grading resulting in a CGR range of 500-1700 m3/MMm3. The field is sour containing approximately 3% H2S and 15% CO2. The reservoir is a dolomite stringer floating and encased in the Ara Salt at an average depth of 4000m. Gross thickness is approximately 100m and the average porosity is 11pu, average permeability is 25mD. The initial reservoir pressure is 470 bara and the dew point pressure (depth related) is 20-30 bara below the initial reservoir pressure. The aquifer is anticipated to be weak with high salt content of 280,000 ppm, which is a flow assurance concern for production. First production started in 2013.
The gas-condensate field is part of an integrated gas-oil project with 8 oil and 2 gas fields where some of the oil fields are planned to be developed by miscible gas injection using non-associated gas. Integrated modelling enabled the selection of a development concept that optimizes the UR of the oil and gas Fields, ensures the gas sales commitments, while making maximum use of the existing facilities and thereby maximizing the value of the project.
The subsurface complexity required a full field compositional modelling approach to address: Quantification of uncertainties on field performanceOptimization of the field development planSupport the appraisal/development drilling campaign
The Integrated dynamic model results show that the condensate recovery factor is increased from 18% (depletion) to 24% by partial recycling with first injection expected in 2020. The Field will be the first PDO gas field developed under partial gas recycling.
This paper presents a methodology to evaluate/optimize the rich gas condensate reservoir including gas recycling and will also cover modelling challenges of compositional gradient and condensate banking.