bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case Study of the Mannville B ASP Flood
Authors: McInnis Lee E , Hunter Kate D , Ellis-Toddington Tyler T , Grawbarger David J 
Published: July 2013

AbstractIn May 2006, the Warner Mannville B ASP flood was the first field wide ASP flood implemented in Canada. The objective was to successfully implement a commercially viable ASP flood. In this project produced water is treated and reinjected into the reservoir. As of December 2012, an incremental 420 103m3 (2.65 million bbl) of oil has been recovered with an expected total incremental recovery of 777 103m3 (4.89 million bbl), which represents 11.1% of the OOIP. In October 2008, after 0.35 pore volume of ASP injection, the project moved into the Polymer only injection phase. Polymer injection will continue as long as is economically feasible.A comprehensive monitoring and testing program was implemented to evaluate flood response and performance. This allowed for the optimization of the flood through continuous adjustment to flow rates and led to successful infill drilling locations.Many challenges have been encountered during this project, including: silicate scale production, treating issues related to the water quality of the recycled injection water, and loss of injectivity in many injection wells.The challenges were overcome and it has been an economic success with a cumulative positive cashflow within 5 years. The results of this flood have led to the implementation of an additional four floods. The lessons learned from this project have improved numerous aspects of how future floods are designed and implemented.
Polymer Flooding of Heavy Oil Under Adverse Mobility Conditions
Authors: Levitt David , Jouenne Stephane , Bondino Igor , Santanach-Carreras Enric , Bourrel Maurice 
Published: July 2013

AbstractPolymer flooding is investigated in laboratory corefloods for potential application in a 2000 cP - 5000 cP heavy oil field. An incremental oil recovery is noted with the addition of very low concentrations of partially-hydrolyzed polyacrylamide (HPAM), either in secondary or tertiary (i.e. after waterflooding) injection. However, increasing polymer viscosity from 3 cP to 60 cP does not significantly change recovery from two pore volumes (PV) of tertiary polymer injection.Existing scaling groups for viscous instability are investigated. Corefloods in this study and others are found to be in or near the transition zone, where recovery may be sensitive to variables such as core diameter, while field floods are all in the &"pseudo-stable" region, where this may not be the case.Mounting evidence suggests that polymer flooding can be economically applied to very viscous oils, despite the fact that it is not feasible to obtain unit mobility ratio with non-thermal methods. Additional work is necessary to determine appropriate optimization methods and criteria for these floods.
Rejuvenating Viscous Oil Reservoirs by Polymer Injection: Lessons Learned in the Field
Authors: Mogollón José Luis , Lokhandwala Taher 
Published: July 2013

Abstract
Viscous oils have adverse mobility that causes production to decline rapidly following a period of primary recovery. Traditionally, enhanced oil recovery (EOR) for this kind of oil has mostly relied on reducing viscosity and increasing mobility using thermal methods or miscible gas injection. However, in some cases-for example, deep reservoirs, thin sands, or restricted offshore applications-these methods might not be feasible. This paper discusses published field studies using polymer flooding EOR for viscous oil and provides recommendations for its applicability.
In countries with reservoirs that present challenges for use of traditional EOR methods, such as Canada, China, and Suriname, polymer flooding has been field tested as a reliable oil-sweeping method while minimizing the risk of high water cut. With oil viscosities at reservoir conditions up to 5000 cp and reasonable economic conditions, polymer flooding has been shown to be an attractive EOR alternative. The study cases presented show that polymer concentrations need only be between 800 to 1,500 ppm to ensure successful results.
Concerns about low or poor injectivity of polymers are being overcome using fracturing and horizontal wells, while high-value, limited-space challenges on offshore platforms are being addressed through modular and minimized installations. Additionally, most conventional waterflood monitoring and surveillance techniques are also applicable to polymer floods, while polymer use in backflow tests and as a tracer has also been proposed.
This study's projection shows a 90% probability of positive net present value (NPV) under broad ranges of uncertainty for oil price, recovery factor (RF), capital expenditures (CAPEX), and operational expenditures (OPEX). The results of this paper show that polymer flooding presents a clear and feasible alternative for increasing the RF of viscous oil. To this end, a detailed study is provided of its advantages and the reservoir condition range of applicability.&lt;/p&gt;
Decision Making Tool to Assist in Choosing Between Polymer Flooding and Infill Well Drilling: Case Study
Authors: Alusta Gamal , Mackay Eric , Fennema Julian , Armih Khari 
Published: July 2013

Abstract
In previous publications, we introduced a methodology to assist in choosing between polymer flooding and infill well drilling. The method has been firstly applied to a synthetic scenario with constant economic parameters, which has demonstrated the impact that oil price can have on the decision making process (Alusta, et. al. SPE 143300) and the method is then applied and tested with varied operational and economic parameters to investigate whether it is better to start polymer flooding earlier or later in the life of the project (Alusta et al., SPE 150454).
The method was then applied to actual field data where the choice of infill well drilling has already been made, to test the robustness of the method against a conventional decision making process for which there is historical data. Application of the method identified that polymer injection would indeed be economically unfavourable (Alusta et al., SPE 163298).
The approach is then carried out in a field where the choice has yet to be made, a field which is currently under waterflood management, and where the operator is considering polymer flooding as an alternative (or in addition) to infill well drilling. Application of the method has identified that under certain technical conditions (related to polymer concentration and duration of polymer injection) and certain economic conditions (related to oil price and operating costs) polymer flooding entails a significant risk of failure, but that if appropriate technical choices are made, and under prevailing economic conditions, polymer flooding is very beneficial for this field, and a combination of polymer flooding and infill well drilling is optimal.
We consider that this approach will be very useful to the industry in helping to make the appropriate choice between potentially various EOR techniques and infill well drilling, taking full account of reservoir engineering AND economic considerations TOGETHER.&lt;/p&gt;
Mechanistic Study on the Influence of Water Alternating Miscible CO2 Flooding of Chalk Reservoirs on Oil Recovery and Ionic Interaction with Asphaltene
Authors: Hamouda Aly A. 
Published: July 2013

AbstractCO2 is injected into mature reservoirs for both sequestration and EOR. The effect of CO2 flooding on asphaltene stability has been extensively addressed in literature. In contrast, asphaltene / water interaction has not received much attention in literature.The objective of the paper is to address the asphaltenic oil recovery by water alternating CO2 injection (WACO2) and asphaltene/ions interaction. Different water compositions, such as synthetic seawater (SSW) and low salinity water (LSW), Na2SO4, MgCl2 ions, and ion free water (DW), are used. SO4-2 and Mg+2 ions were selected based on previous work on their interaction with chalk minerals and modifying the surfaces to more water wet. CO2 is injected in miscible mode within the WACO2 recovery process. For simplicity outcrop cores and model oil were used. Model oil consists of n-C10, 0.35wt% asphaltene (extracted from a Middle East crude oil) and natural surfactant (stearic acid, SA). The effects of water injection rates were also investigatd to address the oil recovery efficiency in the cores and assess the water/oil/rock interaction as a function of injection rates. Imbibition process with various water compositions was tested for cores unflooded and flooded with CO2. This is to address the effect of CO2 on the fluids interaction.It was shown that higher oil recovery was obtained when Mg+2 solution was used as imbibing fluid after CO2 flooding compared to SO4-2 solution. The opposite was observed without the CO2 flooding where higher recovery was obtained when Na2SO4 solution was used as an imbibing solution compared to that with MgCl2 as imbibing fluid.
Innovative Field-Scale Application of Injecting Condensate Gas and Recycling Gas into Medium Oil Pool: Case Study in Sudan
Authors: Tang Xueqing , Wang Ruifeng , Zhang Hui 
Published: July 2013

Abstract
This paper illustrates an innovative field-scale application of injecting condensate gas and recycling gas in Jake field, Sudan. This field has two production series, namely AG condensate gas pools and Bentiu oil pool from bottom to up, with the former 3520 ft. below the Bentiu reservoir and 1695 psi of initial reservoir pressure difference. Bentiu pool of Jake field is a medium crude oil (29 API) pool with strong aquifer support. Well productivity was 500 BOPD. Operator intended to inject high-pressure condensate gas into Bentiu pool to increase field output, whereas was confronted with following challenges: 1) injection of condensate gas in an easy-to-operate wellbore configuration; 2) optimization of injection parameters to achieve highest output; 3) suppress aquifer water breakthrough.
Field scale application had been optimized and implemented since 2010:1) High-pressure condensate gas had been injected into two updip crest Bentiu wells in the same well bore, following a huff-and-puff process, well output amounted 4,000 to 13,800 BOPD under natural flow; 2) 1/4 recycling gas volume from compressors was re-injected into 12 downdip wells at controllable pressure to avoid early water breakthrough; 3) The remaining recycling gas was utilized to gas-lift other five updip wells.
Oil producers were reduced from 19 to 7 comparing to original field development plan, while oil rate ascended from 22,000 to 30,000 BOPD, with watercut dropping to 7% from 15%, achieving a high offtake rate of 6%. Reservoir simulation indicated ultimate recovery factor is expected to be over 50% with such full-field gas injection.
Conclusions drawn from field scale injection of condensate gas and recycling gas were as follows:1) condensate gas injection in the same well bore was technically innovative and operationally robust; 2) recycled gas injection into downdip wells helped detain water breakthrough; 3) field scale application had evidenced outstanding success with high output and high offtake rate.
Using Chromatographic Fingerprint Technique to Monitor Individual Zone Production in ASP Flooding
Authors: Liu Xincang , Zhang Dong , Ding Jian , Ran Fajiang , Zhao Mingchuan , Li Shiyong 
Published: July 2013

Abstract
It&#39;s very important to evaluate layered producing performances at different stages in the course of oilfield development, but due to limitations of monitoring well conditions and logging expenses, it is difficult to comprehensively and systematicly monitor all the producers, and this will bring troubles to adjustments and evaluations during oil field development. To solve this problem, the Chromatographic Fingerprint technique is introduced to monitor layered producing performances in test area F which has four target zones in Daqing Oilfied. After response of alkaline-surfactant-polymer (ASP) flooding, screw pumps are adopted to some producers to minimize scaling in F area where producing profile surveys for annulus wells aren&#39;t adaptable to mornitor the layed producing status. Pre-test in lab shows that the Chromatographic Fingerprint technique is feasible for the four individual test zones for there are distinct chromatographic fingerprint differences, and ASP injected solution has less influences on fingerprints. A fuzzy interpretation template has been successfully set up for commingled 4-6 layers production numerical simulation by using EPB neural network model, and relative errors can be controlled below 10%. The technique has been applied to the producers for 180 times. In-situ test results are stable and correspond to the static information of lays. It indicates that the Chromatographic Fingerprint technique is suitable for monitoring individual zone producing performances of ASP flooding. The results from the fuzzy interpretation template have provided powerful data to re-recognize the connectivity of heterogeneous reservoir between injectors and producers. It can be applied to producers whose producing intervals belong to the fuzzy interpretation template. The oil production proportion of per lay&#39;s can be easily achieved after the sample from the well fluid is analysed with chromatography and calculated with the fuzzy interpretation template. The technique has proved to be economical and it is not astricted by well conditions, so it can play an important role to guide development programs&#39; adjustments and evaluations in oilfields.
Monitoring Water Alternate Gas (WAG) Process Using Streaming Potential Measurement
Authors: Anuar S. M. , Jaafar M. Z. , Sulaiman W. R. , Ismail A. R. 
Published: July 2013

Abstract
Spontaneous potential (SP) is commonly measured during reservoir characterization. SP signals are also generated during hydrocarbon production due to the streaming potential occurrence. Measurement of SP could be used to detect and monitor water encroaching on a well. SP signals could also be monitored during production, with pressure support provided by water alternate gas (WAG) process. The objectives of this study are to quantify the magnitude of the SP signal during production by WAG injection and to investigate the possibility of using SP measurements to monitor the sweep efficiency.
Measurement of streaming potential has been previously proposed to detect the water encroachment towards a production well. The peak of the signal corresponds to the waterfront where there is a change of saturation from ionic water to non-polar hydrocarbon. Similar trend is predicted in the case of WAG where we have several interfaces between the injected water and the injected gas.
The results indicate that the magnitude of the SP generated in hydrocarbon reservoir during WAG process can be large and peaks at the location of the moving water front. Gas, which can be assumed to be non-polar, exhibit no electrokinetic effect.&nbsp; These observations suggest that WAG displacement process can be monitored indirectly from the signal acquired. Water or gas override can be detected and controlled if wells were equipped with inflow-control valves. As a conclusion, the SP measurement is a promising method to monitor the effectiveness of a WAG process.
This study is significant because monitoring the progress of water and gas in a WAG process is key in the effectiveness of this enhanced oil recovery method. Measurement of the streaming potential provides another method besides using tracers to monitor the WAG profile. Better monitoring will lead to more efficient displacement and great benefits in term of economy and environment.
A Discussion of Different Approaches for Managing the Timing of EOR Projects
Authors: Sayavedra Leo , Mogollon Jose Luis , Boothe Mike , Lokhandwala Taher , Hull Rob 
Published: July 2013

Abstract
Studies indicate that as much as 60% of the initial oil-in-place may remain after secondary recovery. At the same time, Enhanced Oil Recovery (EOR) methods are growing more cost effective, with 3% of current worldwide production now attributable to EOR.
EOR projects, however, are strongly influenced by economics and long-run crude oil prices. In addition, EOR investment decisions are also heavily impacted by the timing of the switch from primary recovery to water flooding, and then later, the timing of the switch from water flooding to tertiary oil recovery. The question is what are the key approaches and decision parameters that drive the timing of these decisions? Do you design for EOR up front during concept development planning or do you wait and address EOR as a field matures?
This paper will discuss the trade-offs between adopting two distinctly different approaches for making EOR switching decisions, designing EOR up front vs. implementation as the field matures. One approach embraces proactively designing for and executing EOR during the initial development of a field. The other approach bases switching decisions on the conditional indicators of the reservoir, coupled with a view toward the long-run oil price. This paper will also explore the key decision parameters that impact the choice of which EOR approach to pursue.
Injection and Production Profile Modification for Enhanced Oil Recovery: Mechanical or Chemical Methods?
Authors: Kim Amos S. , Thornton Kim V. , Boothe Michael L. 
Published: July 2013

Abstract
Enhanced oil recovery (EOR) is fundamental to increasing the ultimate recovery of a reservoir. Among several parameters that govern the success of an EOR project, profile modification is a key factor when flooding heterogeneous reservoirs with multiple zones. Given the time and economic constraints, simultaneous flooding of all zones of interest is preferred although it can be difficult for reasons such as a varying pressure and fluid injectivity/productivity profile caused by permeability contrasts between zones. Injection fluids can bypass low-permeability oil-saturated zones, not achieving the full benefit of injection if the profile is not properly modified. Failure to modify production profiles can lead to early water and gas breakthrough. To mitigate these problems, various approaches such as mechanical downhole equipment or chemical treatments have been used.
This paper presents a comparison of the use of mechanical versus chemical conformance control systems in different scenarios. Conformance control is defined as the process that helps improve the drive mechanism for better sweep of reservoir. The basic premises of both mechanical and chemical systems are introduced. Their applicability, operational benefits, and disadvantages are also described. A 3D reservoir simulator is used to illustrate the varying sweep efficiencies, depending on the conformance control method used. The result from the best case with both injector and producer profile modification demonstrated nearly double the oil recovery compared to the base case with no treatment.
Applicability of Hydroxyethylcellulose Polymers for Chemical EOR
Authors: Abbas Sayeed , Sanders Aaron W. , Donovan James C. 
Published: July 2013

Abstract
Polymer flooding is a well established tertiary EOR technique to improve mobility control of a waterflood. Currently partially hydrolyzed polyacrylamide (HPAM) is the industry workhorse in polymer EOR in reservoirs with low salinity and temperature. Biopolymers including hydroxyethylcellulose (HEC) and Xanthan are soluble and excellent viscosifiers in high salinity conditions. This paper will provide a literature review on the use of biopolymers for EOR and focus specifically on the benefits of HEC as a mobility control polymer.
Monitoring Foam Stability in Foam Assisted Water Alternate Gas (FAWAG) Processes Using Electrokinetic Signals
Authors: Omar S.. , Jaafar M. Z. , Ismail A. R. , Sulaiman W. R. 
Published: July 2013

AbstractThe natural pressure in hydrocarbon reservoirs is only sufficient in producing small amount of hydrocarbon at the end of the depletion stage. Therefore, in order to enhance or increase the hydrocarbon recovery, water or other fluids are injected into the formation to extract the hydrocarbon from the pore space. This common practice is known as Improved or Enhanced Oil Recovery (IOR or EOR). Foam is purposely used in some of the EOR displacement processes in order to control the mobility ratio, hence improving the volumetric sweep efficiency.The efficiency of a foam displacement process in EOR depends largely on the stability of the foam films. In laboratory, foam stability is usually measured through physical observation of the foam bubble in a glass tube. Unfortunately, this direct observation is not possible in the reservoir. Therefore, indirect measurement such as the measurement of electrokinetic signal would be a better alternative. This study aims to determine the correlation between the foam stability and the associated streaming potential signals which resulted from the flowing fluid in foam assisted water alternate gas (FAWAG) process.The experimental work will be conducted at the Reservoir and Drilling Engineering Laboratories at the Faculty of Petroleum and Renewable Energy Engineering (FPREE), UTM. The investigation includes sample preparation, sample analysis, displacing fluid formation, rheological properties test and electrokinetic signal measurement by using NI Data Acquisition System (NIDAS). It is expected that the burst of the foam bubble will change the pattern of the electrokinetic signals.The research findings could lead to a new approach in monitoring a FAWAG process. Application in the real field could benefit the oil and gas industry in term of making the EOR process more efficient and more economic.
Peptide Mimetic of the S100A4 Protein Modulates Peripheral Nerve Regeneration and Attenuates the Progression of Neuropathy in Myelin Protein P0 Null Mice
Authors: Moldovan Mihai , Pinchenko Volodymyr , Dmytriyeva Oksana , Pankratova Stanislava , Fugleholm Kåre , Klingelhofer Jorg , Bock Elisabeth , Berezin Vladimir , Krarup Christian , Kiryushko Darya 
Published: July 2013

AbstractWe recently found that S100A4, a member of the multifunctional S100 protein family, protects neurons in the injured brain and identified two sequence motifs in S100A4 mediating its neurotrophic effect. Synthetic peptides encompassing these motifs stimulated neuritogenesis and survival in vitro and mimicked the S100A4-induced neuroprotection in brain trauma. Here, we investigated a possible function of S100A4 and its mimetics in the pathologies of the peripheral nervous system (PNS). We found that S100A4 was expressed in the injured PNS and that its peptide mimetic (H3) affected the regeneration and survival of myelinated axons. H3 accelerated electrophysiological, behavioral and morphological recovery after sciatic nerve crush while transiently delaying regeneration after sciatic nerve transection and repair. On the basis of the finding that both S100A4 and H3 increased neurite branching in vitro, these effects were attributed to the modulatory effect of H3 on initial axonal sprouting. In contrast to the modest effect of H3 on the time course of regeneration, H3 had a long-term neuroprotective effect in the myelin protein P0 nul mice, a model of dysmyelinating neuropathy (Charcot-Marie-Tooth type 1 disease), where the peptide attenuated the deterioration of nerve conduction, demyelination and axonal loss. From these results, S100A4 mimetics emerge as a possible means to enhance axonal sprouting and survival, especially in the context of demyelinating neuropathies with secondary axonal loss, such as Charcot-Marie-Tooth type 1 disease. Moreover, our data suggest that S100A4 is a neuroprotectant in PNS and that other S10C proteins, sharing high homology in the H3 motif, may have important functions in PNS pathologies.