bluuebunny/crossref_metadata_2025_split huggingface dataset:
Water Hammer in Off-Loading Systems: Contribution of Detailed Modelling to Design and Safety
Authors: Pierre B. , Gudmundsson J. S. 
Published: February 2011

Abstract
The second largest oil spillage in Norwegian petroleum history occurred on December 12, 2007, when the Statfjord A offloading system ruptured. Results of numerical simulations of pressure transients in the off-loading system are presented. Of particular interest is the influence of acoustic properties of pipeline sections on propagation of pressure transients. The damaged off-loading system geometry and characteristics as well as the acoustic properties are described. The paper describes numerical simulations of pressure transients in the off-loading pipeline. The paper shows particularly how detailed modelling and accurate estimation of acoustic velocities influence local maximum increases in pressure in an off-loading system.
A Fully Compositional Integrated Asset Model for a Gas-Condensate Field
Authors: Gonzalez F. , Bertoldi L. , Lucas A. , Paterson G. , Shah K. , Grewal B. , Okafor C. , Rodriguez N. 
Published: February 2011

Abstract
A fully compositional Integrated Asset Model (IAM) has been built for a giant gas-condensate field. The field is a complex retrograde gas-condensate reservoir with a hydrocarbon column up to 1750m in height. The fluid composition varies significantly with depth, ranging from a gas condensate to under-saturated oil.
Production is centred on three processing facilities which are variously constrained by gas processing, gas compression & oil stabilisation capacities and overall export levels. There are some 100 producers and 15 gas injectors presently active in the field, with new wells and facilities planned as part of future development.
IAM's for the total production system have been gaining in popularity for applications such as FEED studies, field development planning and optimisation. Their complexity has grown with the need to have fully compositional models, which are particularly important for gas condensate fields, where accurate fluid description is required for predicting condensate recovery and injection gas composition.
Development of this IAM has required close cooperation between reservoir, production and process engineers since each of the component models - a 3D reservoir simulation model, production & injection surface network models and a process model for the three production units – are complex in their own right. The IAM model honours the well, network, and facilities constraints, taking into account interdependence between the different elements of the system.
The IAM provides the capability to manage scheduled field events (well re-routing, plant maintenance, field uptime, etc) and optimizing field liquid production.
This work offers valuable insights for more accurate assessments while evaluating different field exploitation strategies.
Kinetic Simulation of CO2 Flooding of Methane Hydrates
Authors: Phirani Jyoti , Mohanty Kishore K. 
Published: February 2011

Abstract
Finding new sources of energy and curbing global warming are two of the most important current problems. CO2 can be injected into methane-hydrate reservoirs to produce methane and sequester CO2 simultaneously. CO2 replaces methane in the clathrate cages producing methane. The goal of this work is to develop a compositional, thermal, and kinetic simulator to design and interpret lab and field scale CO2 flooding experiments of methane-hydrate in porous media. Five components (water, methane, CO2, CH4-hydrate, CO2-hydrate) and six phases (aqueous, gas, liquid CO2-rich phase, CO2-hydrate, CH4-hydrate and ice) are considered. The equations are spatially discretized with a finite volume difference method and are solved with a Newton-Raphson method in a fully implicit manner. Primary variable switch method (PVSM) is used to track the phase transitions. 1-D core scale simulations shows that the energy produced from CO2-hydrate formation is utilized for methane-hydrate dissociation. The methane-hydrate dissociation front moves at a slow rate of approximately 1/40 cm/hr for the kinetics assumed in the base case. High mole fractions of CO2 lead to CO2-hydrate formation and methane-hydrate dissociation. To dissociate methane-hydrate by CO2 injection, either we need to keep the CO2 mole fraction very high in the fluid phase or operate at a relatively lower pressure (shallower reservoirs of methane-hydrates).
Stand Investigations of ESP's and Gas Separator's Characteristics on GasLiquid Mixtures with Different Values of Free-Gas Volume, Intake Pressure, Foaminess and Viscosity of Liquid
Authors: Drozdov A. N. 
Published: February 2011

Abstract
The investigations of different factors influence on ESP's and gas separator's characteristics have been developed on the special laboratory stand while gas-liquid mixtures delivering. Used model mixtures ("water-gas", "water-surfactant-gas", "industrial oil-gas") good corresponded to real well's mixtures according to the gas influence on ESP operation.
The tests showed that the free-gas content, intake pressure, gas phase degree of dispersion, foaminess, viscosity of the fluid and operation regimes are the main factors which define the degree of free-gas influence on centrifugal pump characteristic. The increase of foaminess and intake pressure leads to significant lowering of negative free-gas influence on ESP operation because of the mixture's stability rise and the difficulty of gas bubbles coalescence in large cavities.
The different principle fundamentals of multistage ESP's operation are estimated for low and high foaminess gas-liquid mixtures in the artificial gas cavitations regimes. The dimensionless parameter - superficial pumping capacity factor is suggested. It permits to generalize ESP's operation cases on high foaming model and real oil-gas-water well's mixtures. These results essentially supplement and define more precisely correlations of J.L. Turpin.
The early unknown fact of lowering efficiency of centrifugal gas separator for ESP was revealed by experiments on high foaming fine dispersed gas-liquid mixtures while intake pressure increase and invariable values of free-gas intake content and liquid flow rate.
The obtained results have significant practical importance not only for increasing efficiency of well's operation by ESP, but for creating pumping oil-gas-water mixtures devices in field pipelines, and also for developing pump-ejecting systems for delivering water-gas mixtures into the reservoir in order to enhance oil recovery by SWAG process too.
Foam Assisted Gas Oil Gravity Drainage in Naturally-Fractured Reservoirs
Authors: Farajzadeh R. , Wassing B. , Boerrigter P. 
Published: February 2011

Abstract
This paper introduces a novel enhanced-oil-recovery concept for naturally-fractured reservoirs. We use foam to create a viscous pressure drop along the fracture that is directly transferred to the oil-bearing matrix and accelerates the oil production. We developed an expression that predicts the maximum oil rate depending on the injected gas rate and properties of the foam generated in the fracture. The results of the numerical simulation are in good agreement with the developed model.
Running Casing Drilling Bit in Extreme-Lean-Profile Wells: A Possibility that Becomes Reality
Authors: Brancato Calogero , Etorki Zuhir , Monaci Ezio , Aliko Enis , Fabre Jason 
Published: February 2011

Abstract
A major oil company drilled an offshore well in Libya where extreme-lean-profile (X-LP) casing was programmed. The X- LP well, a further development of the lean-profile, requires casing strings to be run in openhole sections with very little clearance between the borehole wall and the casing or liner. These include 16-in. casing through 17 1/2-in. open hole, 13 3/8- in. casing through 14 3/4-in. open hole, 11 3/4-in. casing through 12 7/8-in. open hole, and finally, 9 5/8-in. liner through 10 5/8-in. open hole.
This well was programmed and drilled using the X-LP concept with vertical sections to solve particular drilling problems while minimizing drilling costs. It was also drilled using an automated vertical drilling system and managed pressure drilling (MPD) technique in some sections because of the difficulty to drill these formations. The major difficulty consisted in drilling a very thick shale section, where formation is highly unstable with a high tendency to swell and slough and with several fractures that worsen the scenario. This formation also contains some gas that can produce a kick if not controlled with MPD techniques while drilling. Other drilling hazards included thief zones where mud losses occurred.
Because of these difficulties and because of the very tight clearance between liner and borehole wall, running the liner to bottom and properly isolating these formations was a real challenge and could determine that fine line between the success or the failure of the well. For this reason, the operator and the bit manufacturer selected to run the liner with a casing drilling bit (CDB) instead of a reamer shoe. The operator believed a standard aluminum reamer shoe would have failed to reach the bottom. Two liner strings were run with the specially designed CDB, which is made of real PDC cutters and a special steel alloy body very similar to that of a PDC bit, is more robust, and drills more effectively than a reamer shoe. These runs enabled the operator to run and set the liner strings through sections of unstable swelling shales, using the CDB to do hard reaming of long sections. The 9 5/8-in. liner string was set higher than openhole total depth (TD) because the hole was filled with cavings and the liner reached its torque limit. The 7-in. liner string was reamed down to setting depth.
This paper describes the application of these specially designed CDBs in the X-LP well, using MPD techniques, which enabled the operator to run and set liners through very difficult formations with very tight borehole/casing clearances.
Public Perception of the Oil and Gas Industry: The Good, the Bad, and the Ugly
Authors: Theodori Gene L. , Jackson-Smith Douglas 
Published: February 2011

Abstract
Data collected in a general population survey from a random sample of individuals in Tarrant County, Texas, were used to empirically explore issues associated with public perception of the natural gas industry. In addition, the association of public perception of the energy industry with dependent measures such as individual-level actions that (a) may or may not have been taken and/or (b) may or may not be taken in response to the exploration and production of natural gas was investigated. Echoing findings from research in two neighboring Barnett Shale counties (Theodori 2009), it appears that members of the general public in Tarrant County distrust the intrusion of the gas industry and dislike certain potentially problematic social and/or environmental issues perceived to accompany development. Conversely, these same Tarrant County residents appreciate and view less negatively the economic and/or service-related benefits that tend to result from such development. Furthermore, the results of this study suggest that the social/environmental perceptual variable is a key factor to explaining past behaviors and predicting future behaviors taken in response to the exploration and production of natural gas. Possible implications of these findings for the energy industry are proposed.
The Recommended Practice for Surface Casing Vent Flow and Gas Migration Intervention
Authors: Slater Harold J. 
Published: February 2011

Abstract
The migration of gas to surface by means of the production casing/openhole and the production/surface casing annulus is a common occurrence in the petroleum industry. There are also situations wherein migrating gases will negotiate a route to surface outside the surface casing.
The repair of these situations is a non-revenue generating exercise with the potential to reach significant expenditures. The recommended strategy will efficiently initiate and direct this process consequently minimizing the total cost of this intervention. The process commences with a logical technical approach to identify the gas source or sources that are responsible for the problem. The next step is to communicate with this gas source in a manner that enhances a remedial cementing activity. It concludes with the task of cement squeezing the source using a low rate cement squeeze technique to permanently seal the gas source thus preventing gas flow. This methodology has proven to be extremely successful and the subject paper describes in detail the recommended methods for identification, access to and sealing of the gas source responsible for these issues. Case histories will also be presented to illustrate strategies within the intervention.
Performance of Borate-Crosslinked Fracturing Fluid Compromised by Shear-Induced Phase Separation
Authors: Hodge Richard M. , Cawiezel Kay E. 
Published: February 2011

Abstract
Shear history simulation has been a useful laboratory tool to determine the effect of tubing/casing shear on the rheology of fracturing fluids. High shear rates experienced in the wellbore can significantly impair the viscosity development of metallic crosslinked fluids. The effect of shear history on the performance of metallic crosslinked fluids has been demonstrated in past studies and led to the development of many of the delayed crosslinking fluids used today. Recently, more fracturing treatments are being performed at higher wellbore shear rates and more treatments are being conducted with delayed-crosslinking borate fluids. The borate-crosslinked fluids are generally thought to be more tolerant to shear history with the crosslinking able to "re-heal" following exposure to high shear rates. Therefore, shear history simulation is rarely, if ever, conducted during rheological evaluation of borate-crosslinked fluids.
This paper examines the effect of shear history on the viscosity development of a borate-crosslinked fracturing fluid. The testing was initiated due to a series of "screen-outs" experienced with a common, delayed-crosslinking borate fluid. Testing indicated that the fluid formulation used in these treatments was not stable after exposure to the high shear experienced in the wellbore. The fluid exhibited characteristics of shear-induced phase separation resulting in significant viscosity degradation and excessive "rehealing" time. To address this problem, the fluid composition was carefully optimized to eliminate the shear-induced phase separation and accelerate viscosity development after the shear history simulation. The recommended fluid changes were implemented and resulted in successful treatments with no screen-out issues.
This paper details the testing used to observe the shear-induced phase separation and recommendations for optimizing borate crosslinked fluids used in high shear environments.
Improve Heavy Oil Recovery by Separated-Zones Horizontal Well Steam Stimulation
Authors: Zhong Liguo , Zhang Shoujun , Wu Fei , Lang Baoshan , Liu Heng , Liu Tao , Liu ShuXia , Gao Wenlong 
Published: February 2011

Abstract
Horizontal well steam injection is effective to recover heavy oil for its large reservoir contact. To date, more than 150 horizontal wells have been drilled in Shuguang oil region, most of them are operated in steam stimulation and SAGD processes, and completed with slotted liner at length from 100 m to 500 m. But it is much challenging to recover oil from reservoir along horizontal well proportionally because of steam characteristics, large well length and reservoir heterogeneity. Results of simulation and field temperature testing show that only about half of reservoir along horizontal wellbore is recovered well, and average OSR (defined as ratio of oil production to steam injection) is less than 0.28, and it is not satisfying for the large cost of horizontal well drilling and completion. Furthermore, steam crossflow between wells and pressure depletion in local reservoir well steamed could also result in reduction in oil production and OSR.
To improve horizontal well steam injection, separated-zones horizontal well steam stimulation technology is developed, in which temperature sensitive packers, outlets, pressure sensitive valves and ball sealers are involved. The steam injection of different zones separated by packer(s) could be regulated or controlled according to engineering design. There are four techniques developed including dual-zones steam injection in sequence or at one time, selected zone steam injection, and simultaneous multizones steam injection. In order to investigate temperature and steam injection of different reservoir zones along horizontal well in different steam stimulation process, experiment, numerical simulation and field testing are carried out in past three years. In this work, laboratory experiments are carried out with large simulation apparatus packed with sampled oil sand and equipped with temperature sensors and pressure sensors at first. Secondly, structure of steam injection pipes and steam injection scheme are optimized based on numerical simulation, and primarily reservoir selection requirements are also provided. Thirdly, result of application of separated-zones steam injection to 76 wells and monitoring of temperature and pressure is presented, and considerable improvement of steam injection and heavy oil recovery obtained. At last, the future of intelligent separated-zones horizontal well steam injection is prospected.
A New Cost Effective Well Testing Methodology for Tight Gas Reservoirs
Authors: Jacques Antoine , Brouard Benoît , Bérest Pierre , Boutaud de la Combe Jean-Luc 
Published: February 2011

Abstract
Obtaining formation characteristics in a tight-gas environment is highly challenging: formation tester tools run during open-hole logging are often unsuccessful, and conventional well tests are not appropriate as no gas flow is commonly observed before hydraulic fracturing. This paper presents a new well testing methodology adapted from techniques used in the salt industry and successfully applied to Tight Gas Reservoirs, using only wellhead pressure gauges and surface flow meters without downhole tools. It delivers an injectivity index profile along the open hole, allowing better identification of the zones with the best potential and optimization of the hydraulic fracturing strategy. The test typically consists, after having run a tubing string, in continuously displacing the annulus mud by a heavier and less viscous fluid such as brine. During the test, the mud/brine interface rises up along the borehole as a result of pumping brine down the tubing at constant pressure and circulating out mud from the annulus. As viscosities and densities are contrasted, brine and mud injection rates in a given layer are also expected to be contrasted. The differences between brine and mud flow rates provide a continuous injectivity indicator along the wellbore. A different procedure, involving stationary step-by-step measurements, can also be performed. The fluid interface is displaced to a predetermined depth, at which step the entire wellbore is pressurized and a fall-off resulting from fluid leak-off across the open hole is recorded and analyzed to derive a layer productivity index.
To date, three well tests have been carried out in various types of wells, showing good correlations with conventional logs. To go a step further than a qualitative tool, a deconvolution of the time-dependent and interface-depth-dependent permeation flows is necessary. An inversion process accounting for the injection history in the various layers is being developed with the objective of deriving a continuous kh and skin profile. This new method still needs to be qualified against conventional kh data. In particular, it must be demonstrated that the test provides access to the kh of the undamaged zone of the wellbore.
A Coreflood Investigation of Low-Salinity Enhanced Oil Recovery
Authors: Rivet Scott M , Lake Larry W. , Pope Gary A 
Published: February 2011

Abstract
Many researchers have observed an increase in ultimate oil recovery by injecting low salinity brine in laboratory and field experiments.
In this work, linear laboratory corefloods were conducted to study the effect of low salinity waterflooding on oil recovery rate, residual oil saturation and relative permeability. We conducted 21 different waterfloods using nine brines, three crude oils, six outcrop Berea cores and two oil reservoir cores. Every core used was at least 11 long and pressure taps were use to measure pressure drop across sub-sections of the core.
Increase in ultimate recovery of crude oil with decrease in salinity of injected brine was observed in several, but not all, cases. These results suggest that that injecting low salinity brine changes the wetting state of some cores from mixed to water-wet and that this change improves the ultimate oil recovery. This hypothesis of a changing wettability is supported by the following observations: (1) When low salinity injection produced higher oil recovery, the end-point water relative permeability kw° decreased and post-waterflood end-point relative permeability to oil kro° increased. (2) Injecting low salinity brine produced a persistent wettability alteration (toward water-wet) that eliminated oil recovery salinity dependence in subsequent floods. (3) The oil recovery salinity dependence noted in (2) could be restored by extended aging (thus restoring mixed-wetness). (4) Injecting low salinity brine improved recovery by delaying breakthrough, suggesting an improvement in displacement stability.
Chestnut: A Successful, Innovative Development of a Small, Marginal North Sea Oil Field
Authors: Yale David P. , Meier Steven W. , Leonardi Sergio A. , Joyce Gina M. , Kushnick Arnold P. , Wang Jianlin 
Published: February 2011

Abstract
A large-scale laboratory for testing a wide range of petroleum recovery processes has been designed and built to provide a test bed for understanding the detailed physics of processes and calibrating numerical models. The system, dubbed LARGE for Large-scale Apparatus for Reservoir and Geomechanical Experimentation, is centered around a 50 ton, 2100 psi rated pressure vessel that allows testing of processes on a "physical model" of the reservoir that is 2.1 m in diameter and up to 50 cm thick. Key specifications for the system include an "overburden" spacer to mimic the deformation and stresses applied by the real overburden on the reservoir, pumps and "feed" vessels to simulate injection and production in up to 10 wells, over 450 sensors to measure and image real-time the progress of processes occurring in the vessel. The main rationales for the system are to test flow processes in three-dimensions and with sufficient instrumentation to fully understand the physics and chemistry processes and the ability to test at a large enough scale so that reasonable geologic heterogeneity can be incorporated in the "physical model" of the reservoir. The system can be used for a wide range of processes but early work will focus on reservoir processes in shallow, heavy oil reservoirs and overpressured unconsolidated sand reservoirs.