bluuebunny/crossref_metadata_2025_split huggingface dataset:
Research on Reutilization Technology of Residual Polymer in Formation after Polymer Flooding
Authors: Caili Dai , Qing You , Yefei Wang , Fulin Zhao , Shuler Patrick 
Published: July 2010

Abstract
There is a large amount of residual polymer existing in the forms of solution, adsorption and entrapment in formation after polymer flooding. Then the water cut increases quickly along high permeable zone when displacing water. In order to improve sweep efficiency of water flooding and fully use residual polymer in formation, the reutilization technology of residual polymer in formation is proposed and developed. When the reutilization agents (including flocculating agent and fixed agent) are injected, they react with residual polymer and the floc units as well as the cross-linking units are formed which could block high permeability zone and control cross flow. As a result, the sweep efficiency of water flooding and oil recovery could be enhanced. In this paper, the optimized flocculating agent was selected through suspension experiments and the fixed effect for polymer was studied in sand pack cores, and the residual resistance factor was used as the evaluation criterion. The experiments showed that solid particles can be used as flocculating agent and the optimized flocculating agent is stabilized sodium clay; the cross-linking agent can be used as fixed agent and the optimal fixed agent is selected depending on formation temperature and the salinity. This technology was successfully applied in Henan oilfield, Shengli oilfield and Daqing oilfield. The water cut and produced polymer concentration decreased dramatically and oil production increased obviously. This technology which belongs to quaternary oil recovery is a preferred improved oil recovery technology after polymer flooding and has a broad application prospect.
Experimental Investigation of Biosurfactants Produced by Bacillus Species and their Potential for MEOR in Omani Oil Field
Authors: Al-Sulaimani H. , Al-Wahaibi Y. , Al-Bahry S. , Elshafie A. , Al-Bemani A. , Joshi S. , Zargari S. 
Published: July 2010

Abstract
Enhanced oil recovery techniques are usually controlled by the cost associated with them as the fluctuation in the oil price, over the last years, is now commercially accepted. Microbial Enhanced Oil Recovery (MEOR) is one of the technologies that can potentially be implemented with an exceptionally low operating cost. Apart from economical interests of MEOR, microbial bio-products are found to be more environmentally friendly. Besides, some of the bio-products are more chemically stable in reservoir conditions of high temperature and salinity.
In this study, biosurfactants produced by Bacillus licheniformis species isolated from oil contaminated soils from different parts of the Sultanate of Oman were investigated. Eight different production media using different sugars as carbon source such as: glucose, sucrose and cane molasses were tested on three of the potential strains to select the best medium that maximized the production of biosurfactants which was supported by the interfacial tension (IFT) reduction. All isolates were tested on their potential media to screen for the best biosurfactant producer among the available strains. It was found that the strain W19 gave the maximum IFT reduction (from 46.6 to 3.28 mN/m) in 16 hours of incubation when grown in medium 7.
Further studies on W19 were done to test the interaction of biosurfactant produced by this strain with porous media in core flooding experiments as a tertiary recovery stage. The results showed high potential of using this bacterium during ex situ MEOR applications where 10% of residual oil was recovered after injecting the biosurfactant solution. Further recovery was observed after concentrating the same biosurfactant solution where additional 13% of residual oil was recovered.
Numerical Modelling of Geomechanical Effects During Steam Injection in Sagd Heavy Oil Recovery
Authors: Zandi S. , Renard G. , Nauroy J. F. , Guy N. , Tijani M. 
Published: July 2010

Abstract
Steam Assisted Gravity Drainage (SAGD) is a thermal process that has found wide application in high permeability heavy oil or bitumen reservoirs, mainly in the Western part of Canada.
In this process, steam injection continuously modifies reservoir pore pressure and temperature, which can change the effective stress in the reservoir, resulting in a complex interaction of geomechanical effects and multiphase flow in the cohesionless porous media. Quantification of the state of deformation and stress in the reservoir is therefore essential for the correct prediction of reservoir productivity but also for the interpretation of 4D seismics used to follow the development of the steam chamber. On another side, this quantification is crucial for the evaluation of surface uplift, risk of loss of seal integrity, hydro fracturing and well failure. Simultaneous study and analysis of interrelated geomechanics and fluid flow in the reservoir are thus crucial for the management of the process at different stages.
The objective of this paper is to show the importance of taking into account the role of geomechanics in the numerical modelling of SAGD and to provide a better description of the rock contribution to fluid flow in this process. A geomechanics- reservoir partially coupled approach is presented that allows to iteratively take the impact of geomechanics into account in the fluid flow calculations and therefore performs a better prediction of the process. The proposed approach is illustrated on a realistic field case.
A Case Study of ASP Multi-well Groups’ Development Characteristics in Daqing Oil Field
Authors: Rue Song , Dianping Xu , Xiwen Zuo , Zhanlin Ma , Hua Qing , Yali Liu 
Published: July 2010

Abstract
Alkali-Surfactant-Polymer (ASP) pilot and enlarged field tests are all successful in Daqing Oil Field, demonstrating ASP process can greatly enhance oil recovery by 20% OOIP and bring more economic benefits. But the previous tests were all carried in one group of wells which couldn't reflect performances and adaptability of ASP industrial application. Therefore, the commercial field test in multi-well groups with homemade surfactant has been carried out to study performances, scaling characteristics and matching adjusting technologies and to accelerate industrial generalization of ASP flood. The test shows that ASP flood is suitable for the reservoir whose connecting proportion of river channel sand is above 70%, and permeability is over 0.3um2. The larger the well space is, the longer time alkali takes to transfer in reservoir, which results in serious chromatographic separation, scaling, and decrease of injecting-producing capability. Development result can be improved by fracturing on injectors and producers, ceramsite fracturing proppant being the best choice, and by low-carbon mixed organic acid on heavily scaled producers during the late development stage to remove blockage, but the influence of scale can't be totally eliminated. Due to lateral and inter-layers’ heterogeneity in the reservoir, less recovery has been achieved than in the pilot test. We can know from the test that if the well-space is shortened in industrial application, and anti-scaling method is optimized, oil recovery will be further improved.
Experimental Investigation of Asphaltene Induced Permeability Reduction
Authors: Hayashi Yoshihisa , Okabe Hiroshi 
Published: July 2010

Abstract
CO2 injection is one of efficient enhanced oil recovery (EOR) methods among gas flooding, however, asphaltene precipitation during CO2 injection might lead to production loss and reduced efficiency. To understand the mechanism of asphaltene deposition is necessary to develop effective engineering practice for minimizing the formation damage and to design the treatment program for restoring well productivity. The paper presents the development of the experimental apparatus for asphaltene precipitation during pressure decline and gas injection in addition to the results of asphaltene phase behavior and coreflood tests to identify the dominating factors associated with permeability reduction. Asphaltene phase behavior is studied to determine the relationship among pressure, temperature and asphaltene precipitation. Asphaltene onset pressure is measured by Solids Detection System (SDS). The pressure decline induces asphaltene deposition and the consistent result is obtained by the measurement of asphaltene content using SARA analysis. These results are used to estimate Asphaltene Deposition Envelope (ADE). ADE reveals the risk of asphaltene deposition when the pressure is decreased. It is a useful measure to predict flow problem in the reservoir and at the facilities due to asphaltene precipitation. The reversibility of asphaltene precipitation and re-dissolution is also investigated. Gas injection coreflood experiments are conducted on sandstone and carbonate cores to evaluate the asphaltene precipitation and its permeability reduction. Asphaltene is selectively deposited near the inlet of the core for CO2 injection, while asphaltene is equally distributed in the core for the hydrocarbon (associated) gas injection. Additional experiments confirm that the permeability is decreased with increase of asphaltene precipitation. The experimental investigation is necessary to further understanding of the asphaltene behavior in order to prevent asphaltene induced permeability reduction when the risk of asphaltene precipitation is expected due to gas injection and pressure decline.
Integrated Heavy Oil Production with HTL Field-Located Upgrading – Using Upgrading By-Products as a Fuel Source for EOR
Authors: Kuhach J. , Koshka E. , Pelham J. 
Published: July 2010

Abstract
Ivanhoe Energy Inc.'s proprietary HTL upgrading technology is designed to cost effectively process heavy oil in the field and produce a stable upgraded synthetic oil that meets pipeline requirements. Upgrading by-products are converted on-site to steam for enhanced oil recovery (EOR). In developed markets, HTL improves the economics of heavy oil production by reducing or eliminating the need for natural gas and diluent, and by capturing the majority of the heavy to light oil price differential. In remote areas, where natural gas and diluent are not available, integrated HTL production frees otherwise stranded resources. HTL accomplishes all of this at a much smaller scale, at lower per barrel capital costs, and with less impact on the environment compared with conventional technologies.
After years of piloting, development and commercial demonstration, HTL upgrading is in the process of commercial implementation. Integrated HTL/thermal EOR projects are progressing in Canada and Ecuador, illustrating applications in developed and undeveloped markets, respectively. This paper provides a description of the HTL upgrading process, with a particular focus on energy integration with upstream operations.
Fishing Coiled Tubing From a Live Gas-Condensate Well With Coiled Tubing While Under Production
Authors: Kang B. I. , Murugappan B. S. , Kwon O. K. , Sinn G. J. , Foster I. , Robinson L. , Elliott J. B. , Hampson R. , McKinnon B. L. 
Published: July 2010

Abstract
This case study examines the techniques required to recover a coiled-tubing (CT) fish from a live condensate well (using CT) without actually killing the well.
These procedures were recently implemented offshore Vietnam, where an extremely fluid-sensitive formation prevented killing the well because the formation would not likely have recovered. Using the techniques described in this paper, a 1.50-in. (38.1-mm) CT fish 9,177 ft (2797 m) long was successfully recovered from a well while keeping the well on production throughout the operation. This was achieved using temperature-setting gel as an isolation barrier against wellbore pressure in the fish, which saved the customer the approximately USD 20 million in costs associated with the alternative solution of drilling a new well.
This paper outlines the equipment required and factors to consider while designing the job, as well as describing the surface handling procedures once the fish is brought to surface. Particular problems with operating in a live condensate well are also highlighted. Finally, safety methods will be discussed throughout the paper to maintain a dual barrier against wellbore pressure during all phases of the job, including the use of gel as an isolation barrier.
How EOR Can be Transformed by Nanotechnology
Authors: Fletcher A. J. , Davis J. P. 
Published: July 2010

Abstract
Nanotechnology has the potential to transform EOR mechanisms and processes. At present there are two major nanotechnology paradigms derived from mechanical engineering and the biological sciences perspectives. However, a new focus within nanotechnology is emerging which could be called geomimetics. We can define geomimetics as employing the principles of geosystems to create and develop new and novel processes and materials. In a wider sense this involves copying the principles of geosystems into technology to compliment the natural environment.
This geomimetic perspective of nanotechnology incorporates the long and distinguished history of colloid and surface science that has underpinned oil recovery and EOR. We give a concise definition of nanotechnology and demonstrate how it is applicable to EOR.
Through consideration of complexity and systems thinking, we develop a process based method of representing complicated phenomena to help identify the critical processes which control EOR. We construct a hierarchy from fundamental surface forces leading up to processes such as coalescence, phase swelling and film drainage. This hierarchy constitutes a mapping from fundamental molecular forces onto petroleum engineering concepts. In general this hierarchy is spatially-temporally ordered, although particular attention to the overall context and fluid / rock history is needed when mapping wetting and spreading phenomena. We identify critical processes and identify performance measurement criteria to monitor these processes.
We present a conceptual study and demonstrate how nanoscale processes can impact flow behaviour. We introduce the concept of Q analysis and highlight the importance of metaphorical discourse. Processes at the nanometre – micrometre scale including wettability, coalescence, Marangoni phenomena, mass transfer effects and transient phenomena are related to EOR. We argue it is at this scale, and with these phenomena, that an understanding of oil phase distribution, oil drop mobilisation, oil bank formation and oil bank migration is to be achieved for EOR processes.
We outline the potential of nanotechnology to transform the design and execution of chemical EOR. Through nanotechnology, we make explicit the connection between the disciplined study of fundamental molecular forces and the practical application of petroleum engineering.
Optimal Heavy Oil Waterflood Management May Differ From that of Light Oils
Authors: Vittoratos E. , West C. C. 
Published: July 2010

Abstract
Current paradigms and regulatory mandates implicitly assume that waterflood reservoir management practices successful in light oils can be extended unmodified to heavier oils. In particular, complete voidage replacement is considered optimal irrespective of oil chemistry; furthermore, it is assumed that the Buckley-Leverett multi-phase flow formulation, successful in light oils, is equally applicable with heavier crudes. Surprisingly, despite the paramount importance of these concepts to successful reservoir management, there is little public domain documentation on any empirical tests of these assumptions using field data. We here report that our ongoing empirical examination has accumulated observations that suggest that optimal heavy oil waterflood management may differ from that of light oils.
The literature has anecdotal accounts of the difficulty of maximizing oil recovery for heavy oil reservoirs while attempting to achieve complete voidage replacement. In the North Slope of Alaska, efforts to maximize oil production early in the waterflooding of isolated hydraulic blocks have led to a VRR &lt; 1. For heavy oils, we have previously identified a flow regime with WOR ∼ 1 for extended periods of time prevalent for reservoirs worldwide. In Alaska, where we possess detailed fluid, well and reservoir information, we have correlated this regime with hydraulic units with incomplete voidage replacement. The WOR ∼ 1 flow regime can be interpreted as a water-in-oil emulsion flow which is intrinsic to the water/oil system chemistry and not to the details of the reservoir stratification, explaining its widespread prevalence. Laboratory heavy oil waterfloods with a VRR = 0.7 recover more oil than those with VRR = 1, and provide evidence of in-situ water-in-oil emulsion formation. Furthermore, the laboratory floods suggest that the recovery prize for optimal voidage strategy may be estimated by a simple heuristic equation: optimal recovery process (VRRopt) ∼ recovery pure waterflood (VRR = 1) + recovery pure solution gas drive (VRR = 0).
Non-estrogenic Alkylphenol Derivatives for EOR
Authors: Berger Paul D. , Lee Christie H. 
Published: July 2010

Abstract
Alkylphenol ethoxylates and their derivatives have been used for many applications including Enhanced Oil Recovery in the past. The popularity and widespread use of these materials has decreased dramatically over the past 10 years because of the finding that these materials are estrogenic or precursors to estrogen mimics. It has now been found that a slight variation in the structure of these materials can render them non-estrogenic and also prevent their degradation products from being estrogenic without changing the surfactant properties. The resulting alkylphenol alkoxylates, alkylphenol ether sulfate and alkylphenol ether sulfonates have been shown to give low interfacial tensions over a wide range of salinities, temperatures and crude oil compositions making them a low-costs, effective, easily manufactured and safe materials to be used alone or in combination with other surfactants for Alkaline Surfactant Polymer and Surfactant Polymer Flooding. Although the application of these materials is not restricted to IOR, specific examples directed to these applications will be discussed along with the structures and properties of these surfactants.
New Method for Fluid Level Depression Test Interpretation Based on Modern Multiphase Flow Calculation Techniques
Authors: Khasanov M. M. , Krasnov V. A. , Khabibullin R. A , Pashali A. A , Semenov A. A. 
Published: July 2010

Abstract
Acoustic measurement of annulus liquid level is one of the simplest measurement techniques that are used to monitor and analyze well performance without stopping the production.
However, the free gas at pump intake, and more important – the gas flowing up the annulus head reduce the accuracy of bottom hole flowing pressure estimation. One of the important reasons for this is the high uncertainty of gas/liquid gradient calculation in the annulus. Practically, the technique that is widely used to reduce this error is the fluid level depression test (FLDT) – using an acoustic measurement device while recording the annulus head pressure buildup rate having the annulus head valve closed.
To increase the estimation accuracy of the bottom hole flowing pressure, new method of depression test interpretation is introduced. The method implements modern techniques of multiphase flow calculation and inverse problem regularization algorithm. Well performance additional data could also be obtained from this method of interpretation (GOR, annular gas rate, and in many cases separation efficiency at the ESP intake).
Comparing the results obtained using this method to actual measurements using multiphase flow meter and pump intake gauges has verified the confidence level of the method and our understanding of well processes during the FLDT.
The fluid level depression test and the new interpretation method enable us to improve calculations accuracy of well potential production rate, resize ESP more efficiently and increase well production. The fluid level depression test is widely used in Rosneft oilfields. Considering results of about 4000 tests we concluded that the reliability of well data after proposed interpretation technique is 97,5%. This caused in 15% increase of oil production potential achievement.
Low Salinity Water Flooding: Proof Of Wettability Alteration On A Field Wide Scale
Authors: Vledder Paul , Fonseca Julio Carrera , Wells Terence , Gonzalez Ivan , Ligthelm Dick 
Published: July 2010

Summary
Low salinity water injection is an emerging EOR technology, applicable to mixed-to-oil-wet sandstone reservoirs. Flooding with low salinity water causes desorption of petroleum heavy ends from the clays present on the pore wall, resulting in a more waterwet rock surface, a lower remaining oil saturation and higher oil recovery.
A secondary flood application is discussed in the Omar field in Syria showing a change of wettability from oil wet to a water-wet system. This change in wettability is supported by the observation of dual steps in watercut development. In between the two steps the watercut was constant. This behaviour is a known indicator of changing wettability. Moreover, direct connate water banking measurements confirm the change. The field observations are supported by spontaneous imbibition experiments in core material and a single well Log-Inject-Log test in an analogue field.
From the field observations, the change in wettability is estimated to be nearly complete, leading to an associated incremental recovery of 10–15% of the Stock Tank Oil Initialy In Place (STOIIP).
The significance of this work is that this is one of the very few documented proofs of concept on a reservoir scale. Work is ongoing to prove this concept in a tertiary flood as well.
Gas Injection Project in the Kharaib B Reservoir of the Giant Al Shaheen Field
Authors: Mogensen Kristian , Hood Paul , Jones Robert , Noman Rashed 
Published: July 2010

Abstract
This paper describes the successful implementation of a lean gas injection trial in a long horizontal well and the subsequent expansion of hydrocarbon gas injection in the low-permeability Kharaib B carbonate reservoir of the Al Shaheen field, offshore Qatar.
The main objectives of the injection trial were to determine whether premature gas breakthrough would occur in the neighbouring production wells and whether water injectivity after the gas flood would be reduced as a result of the presence of high gas saturation around the injection well. During a 6-month trial period, some 1.7 Bscf of produced gas was reinjected into a trial well. The neighbouring production wells, located some 1,000 ft away, have seen increased production due to pressure support, without suffering from premature gas breakthrough. Data suggest that the reinjected gas may have redissolved into the reservoir oil and that the pressure response is linked entirely to water injection. Furthermore, water injectivity was comparable to the nearby water injection wells; hence, gas injection did not seem to have a negative impact on the subsequent water flooding efficiency.
Encouraged by the positive results of the trial, gas injection is being expanded to a larger number of wells belonging to five different platform locations and encompassing three carbonate reservoirs of the Al Shaheen field. Prediction of gas injection performance has been carried out with compositional reservoir simulation models, which required non-equilibrium initialisation to account for lateral reservoir fluid property variation, a tilted free water level, and a large transition zone. The project started early 2010 using the currently available lift gas pressure. High-pressure gas injection, implemented as a water-alternating-gas (WAG) scheme, will take over once the required surface modifications have been made.