bluuebunny/crossref_metadata_2025_split huggingface dataset:
Study of the Effect of ASP Solution Viscoelasticity on Displacement Efficiency
Authors: Jirui Hou , Zhongchun Liu , Xiang’a Yue , Huifen Xia 
Published: December 2007

Abstract
In application of Alkali-surfactant-polymer flooding, people always follow after ultra low IFT and negate the effect of ASP solution viscoelasticity on displacement efficiency. For getting the ultra low IFT, ASP solutions need the high concentration of alkali, for example, the ASP flooding needs 1.2%wt NaOH in Daqing oilfield. It brings not only many new technological problems such as scale production in well bore, sticking of pump, reduction of injectivity etc, but also decrease of polymer viscoelasticity. In addition, the selectable range of surfactant for ASP flooding falls a definite limitation due to the restriction of ultra low IFT.
As to ASP flooding in the pilot area of Daqing oilfield, the analysis of ASP solution's rheology and physical simulation experiments have been carried out for studying the effect of alkali on viscoelasticity of displacing phase and the effect of viscoelasticities of ASP solution on displacement efficiency in this paper. Experiments include two types, macrodisplacements and micro-displacements. Cores have artificial heterogeneous models, natural cores and micro-models. The results show that decreasing alkali concentration increases the viscoelasticity of ASP solution, and the displacement efficiencies of ASP solution with low alkali concentration aren't less than that with high alkali concentration and ultra low IFT. At same time, the effect of ASP solution's viscoelasticity on displacement of residual oil in different diameter pores of parallel connection has been analyzed theoretically. The limit of capillary number theory has been discussed in ASP flooding. The mechanism of ASP flooding has been recognized again. The mechanism that viscoelasticity is more important than ultra low IFT as a factor of affecting displacement efficiency has been confirmed. Therefore, Decreasing the amount of alkali and weakening the demand of low IFT not only enlarges the selectable range of surfactant and decreases the costs of ASP flooding, but also solves the problem of alkali scale, and are of great importance to the further development of ASP flooding and its application.
Heat Transfer Ahead of a SAGD Steam Chamber, a Study of Thermocouple Data From Phase B of the Underground Test Facility (Dover Project)
Authors: Birrell G. E. 
Published: December 2007

Abstract
Phase B at the Underground Test Facility (Dover Project) is the longest running and most instrumented SAGD pattern in the world and is operated by Northstar Energy. Techniques are presented which allow for the interpretation of temperature data from the pilot to better understand the growth of a SAGD steam chamber over time. Calculating the rate and direction of steam chamber movement, the in situ thermal diffusivity and the role of conduction and convection in heat transfer provide a foundation for understanding the interaction between the SAGD recovery process and the reservoir.
Effects of Asphaltenes and Resins on Foamability of Heavy Oil
Authors: Bauget F. , Langevin D. , Lenormand R. 
Published: December 2007

AbstractBecause of the existence of large reserves, the production of heavy-oils is the object of increasing interest. Some heavy oil reservoirs show anomalous behavior in primary production, with rates of production better than predicted. Interpretations based on the formation of foam (or bubbles dispersion) have been proposed. However there is no evidence for foam production in reservoirs and a mechanism based only on high viscosity has also been proposed. In order to determine the real mechanism, we have studied the "foamability" of heavy oil from South America.The experiments consist of standard measurements in foam studies: qualitative measurements (foam volume, thin film lifetime), and physical properties (volume viscosity, dynamic and static surface tension, elastic modulus). Due to the high viscosity of the crude oil, measurements were performed on solutions of resins and/or asphaltenes in toluene. Asphaltenes were extracted by the HPLC method, and resins by adsorption on silica gel. First, solutions with only asphaltenes were used with concentrations in weight from 1% to 20%. The effect of resins was then investigated using solutions with various resin and asphaltene concentrations.The main results are:The presence of asphaltenes enhances foamability and film lifetime, with a large variation in all measurements at around 10% asphaltene concentration. A very long characteristic time of dynamic tension and a large increase of elastic modulus were observed. Added resins have no effect on foam volume. However, the threshold in properties around 10% asphaltene concentration is no longer observed with resins.The results can be interpreted with existing models for polymer clustering and interfacial behavior of proteins. As proteins, asphaltene molecules can reorganize themselves at the interface, leading to a long time of tension decrease and a high increase of elastic modulus. The effect of resins is analyzed by comparison with crude-water emulsion. In conclusion, with the systems we have studied, asphaltene fraction enhances significantly foam properties (foamability, single film lifetime, surface rheology) above 10% in weight. Because problematic is flow of heavy oil in porous media. Then we have also performed experiments in glass micromodel with the same fluids, but no proofs of interfacial effects were observed.
Optimization of Displacements in Porous Media Using Rate Control
Authors: Sudaryanto Bagus , Yortsos Yanis C. 
Published: December 2007

Abstract
In many applications involving the injection of a fluid in a porous medium to displace another, a main objective is the maximization of the displacement efficiency. For a fixed arrangement of injection and production wells, such optimization is possible by controlling the injection rate policy. This paper is an abbreviated version of Ref. [1], where we described a fundamental approach based on optimal control theory, for the simplified case when the fluids are miscible, of equal viscosity and in the absence of dispersion and gravity effects. Both homogeneous and heterogeneous porous media are considered. The optimal injection policy that maximizes the displacement efficiency at the time of arrival of the injected fluid, is of the "bang-bang" type, namely where the rates take their extreme values in the range allowed. This result applies to both homogeneous and heterogeneous media. Examples in simple geometries and for various constraints are shown. In the heterogeneous case, the effect of the permeability heterogeneity, particularly its spatial correlation structure, on diverting the flow paths, is analysed. "Bang-bang" injection remains the optimal approach, compared to constant rate, if they were both designed under the assumption that the medium was homogeneous.
Novel Well Testing Procedures Prove Successful in Dakota Formation Infill Program, San Juan Basin
Authors: Frantz J. H. , Shannon P. M. , Moody C. E. , Glaser T. , Sawyer W. K. , Williamson J. R. 
Published: December 2007

Abstract
Conoco implemented a novel well testing program in six infill wells to evaluate the differential pressure depletion in the Dakota formation in a portion of the San Juan Basin in Rio Arriba County, New Mexico. The field program consisted of performing pre-fracture nitrogen slug tests or pressure buildup tests. Each of the three Dakota sands were evaluated separately, and in four wells, simultaneously to estimate permeability-thickness product, skin factor, reservoir pressure, and gas in place. The novel approach allowed for all sands to be tested quickly. The infill wells were drilled on 80-acre spacing among existing 160-acre spaced Dakota wells.
The Dakota formation is a series of tight, normal-pressured sands and is one of the main productive units in the San Juan Basin. The average reservoir pressure, as indicated by these tests, ranges from 2,500 psi to 2,900 psi. The original reservoir pressure was 3,200 psi. The post-fracture in-line production rates were excellent averaging between 350 to 900 Mscf/D after two months in-line. Single- and multi-well reservoir models were developed to predict the expected longterm performance from the infill wells.
This paper highlights the novel pre-fracture well testing program including the methodology utilized by Conoco to meet the challenging testing needs present in the Dakota formation in San Juan Basin. The testing approach of using either nitrogen slug tests or simultaneous, individual zone, buildup tests can be used in most tight gas sands consisting of multiple sands.
A Successful Polymer Treatment For Water Coning Abatement in Gas Storage Reservoir
Authors: Zaitoun A. , Pichery T. 
Published: December 2007

Abstract
A polymer treatment has been successfully applied in a Gaz-de-France gas storage well facing excessive water production problems limiting its maximum gas flow rate. The well was located in a limestone reservoir submitted to an active bottom aquifer. To reduce the risk of well impairment while enhancing the efficiency to fight water coning, the polymer slug was injected into the half of the open interval located at the bottom of the reservoir. A study consisting of laboratory core tests and numerical simulations aimed at sizing polymer slug and concentration before performing the treatment. The level of water permeability reduction to reach was fulfilled with single polymer adsorption without the need of adding cross-linker.
After a period of two years where no significant effect on water production occurred, the well progressively improved its performances while water production remained at the same level in neighbour wells. After ten years of survey, the well, which was one of the worse of the storage, became one of the best, capable to sustain high levels of gas production with low water. The delay in well response is probably due to the high water saturation level of the reservoir surrounding the wellbore consecutive to the injection of the polymer slug. The results show that the technique, while easy to handle, gives remarkably efficient long-lasting effect.
Oil-Water Separation in Liquid-Liquid Hydrocyclones (LLHC)–Experiment and Modeling
Authors: Gomez Carlos , Caldentey Juan , Wang Shoubo , Gomez Luis , Mohan Ram , Shoham Ovadia 
Published: December 2007

Abstract
The liquid-liquid Hydrocyclone (LLHC) has been widely used by the Petroleum Industry for the past several decades. A large quantity of information on the LLHC available in the literature includes experimental data, computational fluid dynamic simulations and field applications. The design of LLHCs has been based in the past mainly on empirical experience. However, no simple and overall design mechanistic model has been developed to date for the LLHC. The objective of this study is to develop a mechanistic model for the de-oiling LLHCs, and test it against available and new experimental data. This model will enable the prediction of the hydrodynamic flow behavior in the LLHC, providing a design tool for LLHC field applications.
A simple mechanistic model is developed for the LLHC. The required input for the model is: LLHC geometry, fluid properties, inlet droplet size distribution and operational conditions. The model is capable of predicting the LLHC hydrodynamic flow field, namely, the axial, tangential and radial velocity distributions of the continuous-phase. The separation efficiency and migration probability are determined based on swirl intensity prediction and droplet trajectory analysis. The flow capacity, namely, the inlet-to-underflow pressure drop is predicted utilizing an energy balance analysis.
An extensive experimental program has been conducted during this study, utilizing a 2″ MQ Hydroswirl hydrocyclone. The inlet flow conditions are: total flow rates between 27 to 18 gpm, oil-cut up to 10%, median droplet size distributions from 50 to 500 ìm, and inlet pressures between 60 to 90 psia. The acquired data include the flow rate, oil-cut and droplet size distribution in the inlet and in the underflow, the reject flow rate and oil concentration in the overflow and the separation efficiency. Additional data for velocity profiles were taken from the literature, especially from the Colman and Thew (1980) study. Excellent agreement is observed between the model prediction and the experimental data with respect to both separation efficiency (average absolute relative error of 3%) and pressure drop (average absolute relative error of 1.6%).
The Development of Low-Sour Gas Reserves Utilizing Direct-Injection Liquid Hydrogen Sulphide Scavengers
Authors: Eylander J. G. R. , Holtman H. A. , Salma T. , Yuan M. , Callaway M. , Johnstone J. R. 
Published: December 2007

AbstractThe toxicity of hydrogen sulphide in hydrocarbon streams is well known in the industry and considerable expense and efforts are expended annually to remove hydrogen sulphide to a safe level. In large production facilities, it is generally economical to install a regenerative system for treating sour gas streams. However, during the development stages of relatively small low-sour gas fields at remote and normally unmanned locations where regenerative systems are not practical nor economical, it is necessary to treat the sour gas production with non-regenerable scavenging processes. In the development of its low-sour Zechstein gas reserves in the Coevorden field in the North-East The Netherlands, the Nederlandse Aardolie Maatschappij (a Shell operating unit, hereafter referred to as NAM) decided to adopt continuous direct-injection of liquid scavenging agents as the lowest overall cost process having the least environmental impact and the highest energy efficiency. At the inception of the project, the operating parameters controlling the scavenging efficiency using direct injection of liquid scavengers in this system were largely unknown. Consequently, numerous field trials using different chemistries and different injection mechanics had to be carried out.In this paper we present the results of these field trials, which ultimately led to a very successful and profitable field development strategy. A variety of very challenging operational problems were encountered, and solved. Reference is made to injection nozzle blockages, fouling of glycol gas dehydration systems, severe scaling problems in production and downstream water treatment/injection facilities, inadequate hydrogen sulphide removal efficiencies and HS&E related issues. A better understanding of the fundamental relationships between operating parameters governing direct-injection processes and associated chemical development and application methods has been gained. Communication and integration of experience and knowledge between the operating unit and its chemical supplier were key success factors in this achievement, as was the endurance and continuing support of field operations staff in facilitating the resolution of difficult problems.
Survey of Successful World-Wide Asphaltene Inhibitor Treatments in Oil Production Fields
Authors: Cenegy Lawrence M. 
Published: December 2007

Abstract
Asphaltene deposition problems have been known to occur world wide, with serious asphaltene deposition problems being associated with oil fields in Venezuela, the Persian Gulf, the Adriatic Sea and the U.S. Gulf of Mexico. Until recently, these problems were resolved in producing fields by the use of chemical solvents, or by pigging, scraping or other mechanical means of asphaltene removal. Recent advances in asphaltene inhibitor technology have provided cost-effective methods of preventing deposition and, in many cases, increasing the production of the wells being treated.
This paper will provide field data relating to the on-going successful asphaltene treatment programs being conducted in above-mentioned oil producing regions around the world. In these cases, large revenue increases were noted by the producers due either to an increase in production or reduced maintenance costs. The paper will detail the specific field parameters as well as the process employed for treating the systems. A cost, and return-on-investment will also be calculated for the treatments, where possible.
A New Method to Locate Partial Blockages in Subsea Flowlines
Authors: Liu Liang J. , Scott Stuart L. 
Published: December 2007

Abstract
As exploration and production operations move into deeper waters, producers are faced with new flow assurance challenges. One problem associated with deepwater production is the deposition of paraffins, asphaltenes, hydrates, and scale within the pipeline. These depositions form partial pipeline blockages that reduce flow capacity and may ultimately put the subsea flowline at risk. Pigging and other intervention techniques can be used to deal with this problem. This paper develops a method for locating partial gas pipeline blockages and estimating their size. This method can be used to provide important information for monitoring chemical inhibition programs, scheduling pigging, assessing risk for pigging and planning other intervention procedures.
This paper considers the application of the average pressure method as a new means of locating partial blockages in subsea flowlines. When a blockage occurs in a flowline, it will change the steady-state pressure profile and reduce the average pressure in the flowline. The average pressure is determined through a simultaneously shut-in test (SSIT). Calculation examples show the procedures and range of application of this new technique.
Deepwater Separation: What Could Be the Use of it?
Authors: Johansen O. , Leporcher E. 
Published: December 2007

Abstract
A few years ago, sub-sea gas/liquid separation was sometimes contemplated as an alternative to multiphase boosting to extend the distances of multiphase transportation. In deepwater environment, and mainly in case of a sub-sea scheme, the down-hole fluids follow quite a different route. This difference takes place in the topography of the system (smaller depth of the well, sub-sea flow-line, longer length of the riser system) and in the thermodynamics (temperature and pressure profiles). TOTALFINAELF is involved in several sub-sea and deepwater operations. A preliminary analysis of fluid flow conditions in a sub-sea deepwater export system allows differentiating the impact of the water in the seabed pipeline network from the impact of the water in the riser system. This paper will present the water impact along the transportation system, it will make a review of existing and possible technology able to handle the fluids through separation process (Water/hydrocarbon and gas/liquid separation) to ease the fluid transfer from the sub-sea wellhead to topsides facilities, at the end it will discuss the most likely cases of application, its ability to face unexpected operating conditions (and subsequent cost consequences). An analysis of implementation strategy will be described: Where would subsea separation stand in competition to other technologies?
Conversion of Water to Hydrate Particles
Authors: Larsen R. , Lund A. , Andersson V. , Hjarbo K. W. 
Published: December 2007

Abstract
A concept, CONWHYP (CONversion of Water to HYdrate Particles), has been developed in which a recirculation stream containing hydrate particles seeds hydrate growth in a cooled water-containing well stream. The hydrate particles then grow quickly and in a controlled manner. The hydrate particles are dry, non-depositing and non-agglomerating, and will eliminate free water from the rest of the transport system. The concept has been tested and verified in a prototype laboratory setup. The results include general observations of dry hydrate behavior, experiments on water content, hydrate particle morphology, and salt and "black oil" effects. Some possible designs for industrial application of the concept as a subseaprocessing unit for multiphase flow solutions in harsh environments are outlined.
Statistical Assessment and Management of Uncertainty in the Number of Electric-Submersible Pump Failures in a Field
Authors: Sawaryn S. J. , Ziegel E. 
Published: December 2007

Abstract
Successful management of a population of Electric Submersible Pumps (ESPs) requires an accurate estimate of the expected number of failures as a function of time plus a determination of the associated uncertainty. Knowledge of the uncertainty is required for an effective risk assessment to be made of workover strategies and the impact of these strategies on the production economics. Though the oilfield literature contains discussions of the models and methods for estimating the expected number of ESP failures, little discussion has been presented on the confidence of such estimates.
This paper contains details of how the choice of model, parameter estimates and variation in a well's economic criteria affect the confidence limits. It shows that the uncertainties inherent in the continuous replacement of ESPs and the estimation of their run lives may make the estimates of the number of failures across an entire field to be numbers with considerable uncertainty. This effect is particularly pronounced during the first few years after field start-up. Under these circumstances the distribution of the number of failures is skewed and a 60% difference between the estimated and recorded number of failures is possible. Statistical models also enable differentiation in performance between manufacturers and technologies. It is shown that even large differences in measured run life may not be conclusive evidence of technical or manufacturing superiority. Based on these results, actions are suggested to reduce the uncertainty and improve the management of a field.
Experimental Investigation of Two-Phase Flow Performance of Electrical Submersible Pump Stages
Authors: Pessoa Rui , Prado Mauricio 
Published: December 2007

Abstract
Two-phase flow behavior prediction of centrifugal pumps is a hard task due to the complexity involved in modeling multiphase flow inside turbo machines. No models are currently available for this purpose. Some empirical correlations are available in the literature, but they are valid only for the tested pumps in the experimental range used to develop them. An experimental study has been conducted at The University of Tulsa Artificial Lift Projects - TUALP with a 22-stages GC6100 pump to gather data for pump performance under two-phase flow conditions. Air and water were used as working fluids. This study differs from other experimental works because the pressure changes were recorded stage-by-stage. The results of previous works have been reported as an average of the intake and discharge conditions, and depend on the number of stages used.
Phenomena like surging and gas locking were observed during these tests and their boundaries have been mapped. It will provide some insight regarding when they appear, and the way they are revealed.
The pressure increment and total hydraulic horsepower for the average pump and per stage as a function of the liquid flow rate, and each gas flow rate considered are presented. The average brake horsepower and efficiency for the pump are also plotted for the variables mentioned.
The results indicate that the average behavior for the pump is significantly different from that observed per stage.