bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Laboratory Study of the Effect of Installation of Reticulated Expandable Liners on Sand Production in Weakly Consolidated Sandstone Formations
Authors: Nouri A. , Vaziri H. , Kuru E. , Islam R. 
Published: December 2007

Abstract
Using novel physical model experiments involving large size sandstone specimens, an investigation was conducted on the effect of reticulated expandable liners with various perforation sizes on the rate of sand production.
A series of experiments were conducted using Hollow Cylinder Samples (HCS) completed with no internal support and with support using reticulated liners, or stiffener. The main objective of the investigation performed was to observe whether sanding could occur in wellbores supported by stiffeners and if so, what would be the role of the mesh opening size to the grain size on the onset and severity of sanding. Quantification of the effects of supporting the wellbore by the stiffener on wellbore productivity is another objective of the paper.
The experiments on weakly-consolidated sandstones showed that the stiffener is effective in preventing any shear failure around the wellbore. Under excessive drawdown / depletion, however, pore collapse was seen as a potential failure mechanism in the material. Despite this, much less sanding occurred compared to an openhole case and this improvement was attributed to (1) an enhanced grain-to-grain friction resistance due to higher effective stress state at the wellface, and (2) reduced loss of sand face integrity in a state where the material undergoes pore collapse.
Other useful findings include the role of the stiffener on increasing the mean effective stress around the wellbore which in turn reduces the porosity and permeability of the material in that region due to compaction. This is in spite of the fact that dilation due to shear failure can substantially increase the permeability and porosity of the material within the near vicinity of the well opening and perforation tunnels. As a result of material compaction, the overall porosity and permeability of the sample showed a declining trend during the experiments. However, this gradual decline of permeability can be compensated by applying a greater drawdown with little increase of the potential of sanding.
The findings of this study provide a deeper insight into the role of reticulated liners as a cost effective measure for sand control. Such potential applications will be discussed in this paper.
Novel CO2-Emulsified Viscoelastic Surfactant Fracturing Fluid System
Authors: Hall R. , Chen Y. , Pope T. L. , Lee J. C. , Lugibihl S. 
Published: December 2007

Abstract
The solid-free viscoelastic surfactant (VES) fluid has good proppant transport and excellent cleanup capabilities. Coupling the benefits of a VES fluid with a carbon dioxide (CO2)-emulsified system will further enhance cleanup in a depleted reservoir, extend the application to water-sensitive formations, and maintain reservoir gas saturation to prevent any potential water blocks. This paper reports on a new multisurfactant VES fluid system developed specifically to provide a robust surfactant-base fracturing fluid with supercritical CO2. The field test results indicate the new system is CO2 compatible and still possesses all the attributes normally associated with VES systems.
Effect of Fracture Width and Fluid Rheology on Proppant Settling and Retardation: An Experimental Study
Authors: Liu Y. , Sharma M. M. 
Published: December 2007

AbstractWater-fracs (using slick water instead of gel to transport proppant) have proved to be a successful fracturing technique in some tight gas reservoirs. Proppant placement is an essential factor that determines the effectiveness of such hydraulic fracturing treatments. This paper presents an experimental study conducted to investigate the impact of fracture width and fluid rheology on proppant transport (including particle settling and horizontal transport).Data is presented to show that the settling velocity is significantly reduced as the fracture width becomes comparable to the proppant diameter. Experimental results are presented for Newtonian fluids with different viscosity as well as shear thinning fluids such as guar gum and Xanthan. Experimental correlations are presented for the proppant settling velocity as a function of the dimensionless fracture width and fluid rheology. These correlations are compared with theoretical predictions based on slot flow models presented earlier. The effect of fracture wall roughness is studied by conducting slot flow experiments on cells with rough walls. Wall roughness is shown to impact the results substantially and a new correlation is presented to account for wall roughness.Data is presented to show that the proppant usually flows at a lower horizontal velocity than the fluid, particularly in narrow fractures. The proppant is either retarded or accelerated depending on the ratio of the proppant size to the fracture width. It has been found that for a single particle, when this ratio is small, the proppant travels faster than the average fluid velocity at that location because the proppant tends to be confined to the center of the flow channel where the fluid velocity is higher. As the proppant size increases, the effect of the fracture walls becomes more important and the proppant is retarded by the walls. The retardation of particle relative to the fluid is greater for larger particles and greater proximities to the fracture walls due to the hydrodynamic stress exerted on the sphere by the walls in the narrow gap. Data and correlations are presented that show this dependence. Proppant retardation is particularly important for shear thinning fluids and when the fracture width becomes comparable to the proppant diameter.
Improving the Petrophysical Assessment of Rock-Fluid Systems With Wide-Band Electromagnetic Measurements
Authors: Toumelin E. , Torres-Verdín C. , Bona N. 
Published: December 2007

Abstract
Due to their sensitivity to ionic content and surface distribution, wide-band electromagnetic (WBEM) measurements performed on porous rocks are influenced by petrophysical factors as diverse as fluid saturation, pore morphology, thin wetting films, and electrically charged clays. In general, all of these factors simultaneously coexist in fluid-saturated rocks, and therefore a comprehensive and accurate physical model is needed to correctly interpret WBEM measurements in terms of petrophysical properties. Traditional mixing laws fail to quantify the collective influence of various petrophysical parameters on WBEM measurements. As a result, no general method is currently available for the accurate petrophysical interpretation of dielectric measurements. The objective of this paper is to quantify the sensitivity of WBEM measurements to a large array of petrophysical properties, and to show that they naturally complement with NMR measurements. To this end, we develop a comprehensive numerical model that successfully reproduces the kHz-to-GHz dielectric dispersion measured on a variety of rock and fluid conditions, wettability, and clay content. Our model is based on the solution of Maxwell's equations at the pore scale and incorporates explicit geometrical distributions of grains, fluids, and wet clays, constructed from core pictures and measurements. Comparison of WBEM and NMR measurements emphasizes the complementary nature of the two techniques, especially in the assessment of wettability, fluid saturation, pore connectivity and morphology, hydraulic pore coupling, and pore size distributions. Because our approach integrates all of these petrophysical features, we can assess their relative influence on borehole kHz-GHz WBEM measurements acquired in hydrocarbon-bearing rocks.
World's First Coiled-Tubing Underbalanced Casing Exit Using Nitrogen Gas Mist as the Milling Fluid
Authors: Webster B. , Pitman M. , Pruitt R. 
Published: December 2007

Abstract
This paper describes the world's first true coiled tubing under balanced casing exit using a Nitrogen (N2) gas mist as the milling fluid, which allowed a well in Sharjah's Sajaa field to remain live throughout the casing exit, ensuring uninterrupted gas production. Previous attempts to mill a window using a N2 gas mist with conventional milling technology proved unsuccessful. This was largely due to the lack of cooling and lubricity of the milling fluid resulting in a rapid deterioration of the window mills. Subsequent windows were milled using water only which resulted in massive fluid losses to the formation, due to the low reservoir pressures within the field, and more importantly caused interruptions to existing gas production.
The technology described in this paper allowed gas production to be maintained throughout the window milling operation and resulted in a dramatic reduction in fluid losses to the formation and a reduction in overall casing exit time. Following the casing exit, the build and lateral drilling assemblies were deployed through the window at the first attempt, allowing uninterrupted progression to the under balanced drilling phase. This technology has helped to extend the life of the Sajaa field and secure the future of the Sharjah Coiled Tubing Drilling (CTD) project.
Measured and Predicted VIV Responses of Faired Drilling Riser Models
Authors: Lee L. , Allen D. W. , Henning D. L. 
Published: December 2007

Abstract
This paper discusses the measured vortex-induced vibration (VIV) responses of faired drilling riser models and predictions from computer codes. Experimental data indicated that tail fairings are very effective at suppressing VIV of drilling risers. Comparisons are made among the test results, predicted responses from the calibrated model, and the calculations from an un-calibrated model. Examples are given that clearly demonstrate the importance of testing and computational model calibration.
Magnus Field: Reservoir Management in a Mature Field combining Waterflood, EOR, and New Area Developments
Authors: Moulds T. P. , Trussell P. , Haseldonckx S. A. , Carruthers R. A. 
Published: December 2007

Abstract
Magnus is a high productivity oil field in the northern North Sea. First oil was produced in 1983 and the plateau of 150 mstbod ended in 1995. During the 10 years post-plateau a variety of reservoir management techniques have been employed to arrest decline rate. Now, through exploitation of a gas injection EOR opportunity the oil rate is again rising. And looking to the future a major project to increase reservoir access by adding drilling slots is being executed that will maintain significant oil production beyond the next decade.
The field remains opportunity-rich, prioritisation of drilling targets is complex: EOR wells vie with infill waterflood targets and extended reach wells to the field periphery. The non-uniqueness inherent in any reservoir simulation history match means that a conventional full field model cannot sufficiently reduce uncertainty on future drilling and facilities decisions. A particular challenge emerges when the reservoir process changes and future performance may be sensitive to aspects of reservoir description that have little influence on the history match. The gas injection project presents such a challenge.
A solution is found through the emergence of genetic algorithm techniques applied to reservoir simulation. A semi- automatic workflow is developed where input parameters are varied, each combination of parameters yielding a quantitative measure of history match quality. The methodology is notable for generating multiple, significantly different, reservoir descriptions, each with an acceptable history match but with potential for quite different performance during prediction. This approach better determines those parameters that control performance; it increases the exploration of uncertainties and allows development of robust mitigation strategies.
We present results of genetic algorithm techniques applied to dynamic and static full field model descriptions and to the development of pseudo relative permeability curves to provide effective flow functions for all phases in the full field model. We show how the development of a reservoir simulator that is able to address diverse development options against the uncertainty of reservoir description has impacted reservoir management.
Understanding the Effects of Reservoir Changes in Sand-Control Completion Performance
Authors: Norman W. D. , Pourciau R. D. , Dusterhoft R. , Schubarth S. 
Published: December 2007

Abstract
Sand-control completion performance has been a key point of discussion within our industry for several years. Widely varying values of skin and PI exist and arguments have been made to oppose or support different completion techniques currently available. In many cases, these arguments are made in attempts to promote certain completion techniques when more time should be spent understanding the probable sources of the condition.
This paper examines closely (1) how reservoir properties in the near-wellbore region can change significantly over time under production conditions, and (2) how these changes can affect well performance over time. It looks at the significance that reservoir compaction can have when reduction in permeability is accounted for and how detrimental this compaction can be to well productivity.
In reservoirs subject to compaction, the behaviors of radial completions are compared to frac-pack completions over the life of the well. The paper demonstrates that although the conductive fracture may not be a dominant factor in well productivity early in the life of the well, it can become very significant in maintaining well productivity and performance later in the life of the well. In effect, these completions can be designed to improve well performance over time, and in many cases can result in decreasing skin factors with time, thus minimizing the decline in productivity.
Reservoir modeling was performed that considered near-wellbore compaction and the presence of a high-conductivity fracture; this model agreed well with observations made from several deepwater developments.
A detailed case history is also presented wherein sufficient reservoir evaluation was conducted over time to validate the effects of compaction and the long-term performance improvements that can be achieved using frac-pack completions with these reservoir conditions.
Leak Sealing on a Water-Injection Line in the Foinaven Field, West of Shetland, using Platelet Technology
Authors: McEwan I. K. , Ryan N. J. , Chirnside I. B. , Meldrum A. G. , Shaw A. , Alexander P. D. , Stebbings T. F. 
Published: December 2007

Abstract
Platelet™ technology is a new and novel method of sealing and locating leaks in pressurised pipelines. It is based on the remote injection of small mechanical objects into the line. These are then conveyed to the leak site by fluid forces and once there act in such a way so as to form a seal, thereby stemming the flow through the leak. Platelets™ also have the capacity to enable leak location by the use of tracers added to the platelets™ prior to injection.
This paper describes the first ever deployment of platelet™ technology in the field. The application took place in a 10" water injection line in BP's Foinaven Field, West of Shetland during the autumn of 2004. The outstanding success of this operation rested on the detailed preparatory work which encompassed flow loop testing, hazard analysis, numerical and analytical modeling, materials analysis and pressure vessel testing. Crucially the number of platelets™ used was sufficiently small so that any threat to the reservoir was deemed to be negligible.
As this was the first use of platelet™ technology in field conditions, the deployment of the platelets™ was undertaken during dye injection so that progress could be monitored by ROV. Sudden and complete cessation of the dye stream from the leak confirmed that a seal had been effected. A pressure fall-off test immediately after the platelet™ operation showed a significant improvement over the previous test conducted before the operation. The seal allowed BP to increase water injection from 141,000 to 154,000 bbl/day with an immediate affect on reservoir production.
The outstanding success of the operation has introduced a new tool to provide a means of rapid top-side response to further failure in winter months when sub-sea intervention and DSV availability is less than certain.
Clair Field—Managing Uncertainty in the Development of a Waterflooded Fractured Reservoir
Authors: Clifford P. J. , O'Donovan A. R. , Savory K. E. , Smith G. , Barr D. 
Published: December 2007

Abstract
Clair field came on production in February 2005. Clair is a large oil reservoir (&gt;4 billion bbl STOIIP), 75 km west of Shetland. It is the largest naturally fractured reservoir developed in the UK, and is recovered by waterflood. Its 28 year appraisal period reflects the high reservoir complexity, relatively poor quality conventional seismic image, and uncertain impact of the conductive fractures.
This paper compares early Clair production with pre-drill expectations. Its primary focus is on reservoir uncertainty, and how the drilling sequence and data acquisition are managed to allow rapid and flexible response to learning, given an expectation of surprises. Clair is not pre-drilled, and the preferred well locations and design will change. A condition of responding rapidly is a hopper of well options, kept filled with diverse well types and locations, from which appropriate wells are selected using current knowledge. Key decision points in the sequence are identified in advance and options at each point evaluated against reservoir scenarios. This process allows planning for potential outcomes, generates the required hopper wells and identifies data requirements for future decisions.
Clair well-planning requires integration with reservoir surveillance and modelling. Early surveillance focuses on reservoir pressure response. All wells (including injectors) have a permanent down-hole pressure gauge, RFT data acquisition and a baseline production log. These data establish reservoir connectivity, injection response, and controls on productivity and injectivity. Also important is seismic data calibration against log and core information, to refine models of the natural fracture distribution. Water movement through fractures is expected and will become a surveillance focus.
Clair reservoir uncertainty is represented in sets of static and dynamic reservoir models which express the full uncertainty range consistent with data. At start-up, a wide range of fracture models, with diverse outcomes, can be consistent with the limited dynamic data. As new data arrive, the objective is to condense the range of models, which continue to be diverse, but must also be consistent with all historic data at the end of every month. These models inform drilling programme decisions, reflecting both the continuing uncertainty and rapid learning.
Quantitative History Match of 4D Seismic Response and Production Data in the Valhall Field
Authors: Kjelstadli R. M. , Lane H. S. , Johnson D. T. , Barkved O. I. , Buer K. , Kristiansen T. G. 
Published: December 2007

Abstract
Permanent ocean-bottom seismic cables have been installed in the Valhall Field, offshore Norway. Five seismic surveys were acquired from the permanent system between October 2003 and April 2005, in addition to two towed-streamer surveys acquired in 1992 and 2002. The various 3D seismic data sets show strong time-lapse or 4D effects resulting from primary production. During the same time period an extensive drilling program has provided high-quality data on reservoir pressure, pressure gradients, and reservoir fluid distribution in the field.
This paper outlines how changes in seismic attributes were generated synthetically from a reservoir simulation model and compared against observed 4D seismic data in one area of the field. An objective function describing the misfit between the simulated and measured data was defined using both seismic and conventional production data. BP's Top-Down Reservoir Modelling (TDRM) technology1 was used to generate multiple reservoir descriptions that would minimize the objective function. This involved computer-assisted history matching with a genetic algorithm that varied more than 60 parameters in the reservoir simulator to improve the overall history match.
Formation Pressure Testing While Drilling for Deepwater Field Development
Authors: Fletcher J. , Seymour G. , Flynn T. , Burchell M. 
Published: December 2007

Abstract
The Foinaven, Loyal and Schiehallion fields lie West of Shetland, some 170 Km west of Sullom Voe. These fields, operated by BP, consist of a number of channelised sandstone reservoir sequences of Paleocene age. They have been developed by high angle/horizontal production and injector wells, the placement of which is critical to the effective drainage of the reservoirs. The reservoirs have significant compartmentalisation due to a number of faults and facies boundaries which means that formation pressure data, coupled with other surveillance information, are critical in ensuring correct well placement. Additionally, formation pressures are required by completion engineers to determine completion string geometry. Until recently, the only available method for acquiring these formation pressures was to run a wireline tester on drillpipe, after the well had been drilled. As all other FE logs were generally acquired using LWD this was time consuming and expensive on the new generation rigs required to drill in this area. In 2004, the first pressure testing LWD tools were deployed in these fields, allowing formation pressure data to be acquired as part of the drilling process, thus allowing real-time decisions relating to wellbore trajectory to be taken, and eliminating additional pipe conveyed wireline runs. This paper discusses the process which was used to validate the measurements, quality control of the real time and memory data, and examines some of the advantages and disadvantages of acquiring formation pressure measurement as the well is drilled rather than after reaching TD.