bluuebunny/crossref_metadata_2025_split huggingface dataset:
Performance Step Change: 3 Years of Advances in CNS Britannia Field, UK
Authors: Matheson Elizabeth , Phillips Alan , Bradley Scott , Wallace Graeme 
Published: December 2007

Abstract
This paper describes advanced PDC technologies applied to the challenging 12-1/4 inch section in the Britannia field in UK Central North Sea (CNS) that significantly reduced the number of bit trips and associated drilling costs. The 12-1/4" section is generally drilled in three main intervals with RSS/PDM.
New PDC bit technology was developed to efficiently drill two of these sections with controllable torque response and consistent directional behavior while achieving maximum ROP and durability. Several new bit designs were implemented and tested at the manufacturer's surface simulator with good results.
The upper interval from the 13-3/8" shoe originally used 8- bladed 13mm cutter PDC down to the Maureen limestone (USC c.15,000psi). A 19mm 7-bladed PDC featuring reduced exposure and advanced cutter technology was introduced. This design achieved a drilling record from the 13-3/8" shoe to the top Tor in one run where previously two bits had been required. In addition there was improved steerability on a motor through the Lista Formation; previously this had been considered directionally challenging. The same section on the next well with this bit design achieved a field footage record of 9,534ft.
The lower Cretaceous chalk section from the top Tor was originally drilled with 6-bladed PDC with 16mm/13mm cutters. Historically PDC bits slowed to unacceptable ROP with only minimal wear due to the rounded diamond lip proving unable to penetrate the Chalks. An application specific 7 bladed 16mm cutter design was introduced featuring latest technology cutters, and a customized back up cutter layout. This design drilled 4,500ft from the top Tor Formation with no visible wear. This section had previously required 2-3 PDC bits. During this same time, the service company was also matching the closed-loop RSS system with the ever changing PDC bit technology. The development of the RSS in combination with the advancing PDC technology played a large role in the performance improvement. The authors will describe field results and developments leading to this performance step-change.
A Triple-Continuum Pressure-Transient Model for a Naturally Fractured Vuggy Reservoir
Authors: Wu Yu-Shu , Ehlig-Economides Christine , Qin Guan , Kang Zhijiang , Zhang Wangming , Ajayi Babatunde , Tao Qingfeng 
Published: December 2007

Abstract
We present an analytical approach for pressure transient test analysis in naturally fractured vuggy reservoirs. This analysis approach relies on a triple-continuum concept, using observed geological data from carbonate oil formations in western China, to describe transient flow behavior in fracture-vug-matrix reservoirs. In the conceptual mathematical model, fractured vuggy rock is considered as a triple-continuum medium, consisting of fractures, rock matrix, and vugs (or cavities). Similar to the classical double-porosity model, the fracture continuum is assumed to be responsible for the occurrence of global flow, while vuggy and matrix continua (providing primary storage space) interact locally with each other as well as with globally connected fractures. Furthermore, the triple continua of fractures, matrix, and vugs are assumed to have uniform and homogeneous properties throughout, and intercontinuum flows between them are at pseudosteady state. With these assumptions, we derive analytical solutions in Laplace space for transient flow toward a well in an infinite and finite reservoir with wellbore storage and skin effects. The analytical solutions reveal typical pressure responses in a fracture-vug-matrix reservoir and can be used for estimating vug properties, in addition to fracture and matrix parameters, through properly designed and conducted well tests. As application examples, actual well test data from a fractured-vuggy reservoir in Western China are analyzed using the triple continuum model.
A Two-and-Half-Dimensional Model-Based Inversion Algorithm for the Controlled- Source Electromagnetic Data
Authors: Abubakar Aria , Habashy Tarek M. , Zhang Yan 
Published: December 2007

Abstract
The model-based inversion method for the reconstruction of geometry and conductivity of unknown regions or bodies using marine controlled-source electromagnetic (CSEM) data is presented. The method has the advantage of using a priori information such as the background conductivity distribution, structural information extracted from seismic and/or gravity measurements, and/or inversion results a priorily derived from a pixel-based inversion method. By incorporating this a priori information, the number of unknown parameters to be retrieved becomes significantly reduced. In this paper, we develop the model-based inversion method by adopting the regularized Gauss-Newton minimization scheme. The robustness of the inversion is enhanced by adopting nonlinear constraints and applying a quadratic line search algorithm to the optimization process. We also introduce the adjoint formulation to calculate the Jacobian matrix with respect to the geometrical parameters. We compare the inversion results obtained by the model-based inversion method with those obtained from the pixel-based inversion method.
Monitoring Production from Gravel-Packed Sand-Screen Completions on BP's Azeri Field Wells Using Permanently Installed Distributed Temperature Sensors
Authors: Pinzon I. D. , Davies J. E. , Mammadkhan F. , Brown G. A. 
Published: December 2007

Abstract
BP is developing its Azeri field using deviated gravel-packed sand-screen completions producing from the multilayered Pereriv B, C, and D reservoirs. Restricted wellhead access, high rates, and differential depletion of the different reservoir intervals limit conventional production logging possibilities, so BP has chosen to install permanent fiber-optic distributed temperature monitoring systems with its sand screens and to use these systems to monitor production rates and changes over time.
The optic fiber has been installed on the periphery of the sand-screen shroud, effectively installing it in the gravel-packed annulus. When the gravel pack is completed, the fiber responds to the reservoir temperature plus the effect of Joule-Thomson warming of the flowing oil caused by the pressure drop (drawdown) in the near-wellbore region. Thermal mixing of the oil with flow from below only occurs once the flow has passed through the sand-screen wire-wrap. Thus a direct measure of each individual reservoir drawdown is obtained from the difference between the fiber-measured temperature and the geothermal temperature in the flowing reservoir intervals. Given the reservoir drawdown, the flow rate can then be calculated.
Thus installing the fiber outside the sand-screens gives a unique, direct measurement of individual reservoir layer drawdowns, enabling the effects of differential depletion to be monitored over time.
This paper outlines the completion technology used to install the fibers along the sand screens and shows the data and results obtained where reservoirs with different pressures are commingled through gravel-packed sand-screens. Thermal models of the near-well environment are described and used to analyze the data and to obtain the flow profile and reservoir layer pressures.
The use of permanently installed fiber-optic distributed temperature monitoring systems on its Azeri reservoir has allowed BP to acquire early time-surveillance data, adding significant value by reducing the voidage risk to the secondary reserves.
Calibrating the Mechanical Properties and In-Situ Stresses Using Acoustic Radial Profiles
Authors: Sayers Colin M. , Kisra Saad , Tagbor Kwasi , Taleghani Arash Dahi , Adachi José 
Published: December 2007

Abstract
Estimating the in-situ stresses and geomechanical properties in the exploration phase is key to the success of drilling, completion, and production operations. A methodology for building a Mechanical Earth Model (MEM) along a well trajectory based on logs and drilling data is presented. The constructed MEM uses the acoustic radial profiles obtained from a multi-pole sonic tool. The variation in the velocity of polarized shear waves as functions of the distance from the borehole are used to provide estimates of the magnitude and orientation of the in-situ stress state as well as to calibrate the stresses obtained using other methods. Furthermore, a plane strain computational model accounting for rock deformation and plastic strain in the near-wellbore region resulting from the stress changes induced by drilling is used. This model allows us to provide calibrated estimates of the unconfined compressive strength of the sand bodies crossed by the well.
Is Accurate Gas/Steam Determination Behind Pipe Feasible with Pulsed Neutron Measurements?
Authors: Badruzzaman A. , Logan J. P. , Bean C. , Adeyemo A. O. , Zalan T. A. , Barnes D. , Platt C. 
Published: December 2007

Abstract
Pulsed neutron measurements are commonly used to locate gas behind casing and quantify steam saturation, but do not always yield desired results. Several parameters are utilized to identify gas and one parameter, the thermal neutron capture cross section, Sigma, is used to compute steam saturation. In the paper we report a mixed experience in identifying gas with these techniques, across fields, tools and vendors. Some parameters have worked well in some cases but have performed poorly in others. The uncertainty in steam saturation, computed using Sigma, is greater than those previously reported elsewhere. Modeling offers insight into the mixed results. It appears that in some cases the PNC-derived Sigma may yield erroneous steam saturation for a variety of reasons, including uncertainties in the input parameters and possibly an inherent nonlinear transport effect that increases as steam saturation increases. An alternative approach based on PNC pseudo-porosity is explored. Calibration of cased-hole tools in gas reservoirs, generic and local, open-hole baseline data and core analysis of complex rocks are essential. Currently, these are either nonexistent or infrequent.
Fracture Characterization and Modeling Various Oil-Recovery Mechanisms for a Highly Fractured Giant Light-Oil Carbonate Reservoir
Authors: Ayyalasomayajula Padmakar , Hui Mun-Hong , Narr Wayne , Fitzmorris Robert , Kamath Jairam 
Published: December 2007

Abstract
Proper fracture characterization and a good understanding of the fracture-matrix system are critical to properly predict oil recovery from naturally fractured reservoirs. In this work, we use an integrated analysis of image logs, production logs, and production history to help constrain matrix and fracture properties. This is done by extracting a sector from the history-matched full field model of a naturally fractured giant light oil carbonate reservoir and explicitly studying matrix fracture flows.
Even with constraints provided by the above analysis, there is still significant uncertainty regarding matrix permeability in our reservoir. We built simple mechanistic models to study the impact of this uncertainty on various oil recovery mechanisms such as miscible gas injection and primary depletion. We also quantified the impact of capillarity, diffusion and gravity on recovery mechanisms.
Optimized Formation Evaluation: A New Technique to Enhance Openhole Log Assessment of Pay and Producibility
Authors: Eyvazzadeh Ramsin Y. , Bradford Charles , Kersey David G. , Al-Waheed Hilal H. 
Published: December 2007

Abstract
Improving the accuracy of petrophysical analyses is critical in optimizing formation evaluation. Petrophysical accuracy is affected by errors inherent in log and core measurements and reservoir heterogeneity. These errors can lead to imprecise differentiation of pay and non-pay resulting in either overlooked pay or additional testing costs. Error reduction will improve the differentiation of pay/non-pay but, due to remaining errors, the distinction will still be imprecise. Thus to optimize formation evaluation, it is imperative to quantify remaining errors.
This paper presents a newly developed technology that quantifies petrophysical uncertainty to maximize the utility of petrophysics in formation evaluation by incorporating Monte Carlo numerical analysis to account for uncertainties in log, reservoir and petrophysical parameters. In comparison to traditional petrophysics, this technique does not assume unique values for the input parameters used in calculation of hydrocarbon pore volumes and deliverability. This technique incorporates random errors in logging tool responses and core measurements as well as reservoir heterogeneity in a Monte Carlo simulation. Output from the Monte Carlo simulation is then used in appropriate petrophysical models (e.g. Archie, Dual Water, etc.) to calculate statistical distributions for saturation and permeability to define productive and nonproductive zones.
The novel aspect of this methodology is that it also identifies zones where the random measurement and model errors are too large to determine accurate saturation and permeability. In these zones of high uncertainty, saturation and permeability are "undetermined". Based on the amount of uncertainty, this technique can determine whether additional logging, coring or well test data are needed to reclassify "undetermined" zones as either productive or non-productive. This paper will outline the procedures used in developing the technique and will show its utility in several examples from Middle Eastern reservoirs.
Pushing the Boundaries of Artificial Lift Applications: SAGD ESP Installations in Canada
Authors: Gaviria F. , Santos R. , Rivas O. , Luy Y. 
Published: December 2007

Abstract
The need for high-temperature electric submersible pump (ESP) systems is growing as the oil industry matures. Canada's nonconventional oil reserves are estimated at just over 1 trillion barrels and Suncor's heavy oil reserves in northern Alberta, Canada, are estimated to have a potential production of 14 billion barrels of crude oil, but traditional mining methods of recovery do not make them all economically reachable. It is estimated that less than one-fifth of the oil sands resource is mineable. To deal with this, Suncor has turned to in-situ steam-assisted gravity drainage (SAGD) operations as a key part of its plans to increase bitumen supply to its upgraders.
The SAGD approach uses a pair of horizontal wells drilled parallel to each other and separated vertically by a distance of approximately 5 m. Steam injected through the uppermost well penetrates the surrounding formation, heats the heavy-oil sands, and creates a high-temperature region above the injector known as the steam chamber. Heat transferred to the oil sands reduces oil and bitumen viscosity. Gravity forces the oil, bitumen, and condensed steam downward, where these fluids, consisting of about 25–80% water, are produced into the lower well.
Suncor uses SAGD technology to recover 8 to 9 degree API bitumen and heavy oil from unconsolidated sands in the Firebag field. Wells in these fields experience bottomhole pressures of 2000 to 3000 kPa and bottomhole producing temperatures of 180°C to 209°C. Whereas standard ESP strings are rated to 149 °C, bottomhole operating conditions (BOC), key components of the SAGD system featured in this paper, especially its motor, power cables, pump, and advanced protector, are built to withstand bottomhole temperatures up to 218 °C.
Suncor has installed 21 of these ESP systems, which have enabled a reduction in downhole pressures to improve the steam/oil ratio (SOR). This is a direct reduction in operating and lifting costs, which provides several million dollars in savings by reducing the amount of water that needs to be treated and the amount of fuel burned to generate the steam. Suncor's line of ESP systems has achieved a runlife of more than 500 days.
Multiphase Flow Modeling Based on Experimental Testing: A Comprehensive Overview of Research Facilities Worldwide and the Need for Future Developments
Authors: Falcone G. , Teodoriu C. , Reinicke K. M. , Bello O. O. 
Published: December 2007

Abstract
Multiphase flow models for the oil and gas industry are required to investigate and understand the co-current or counter-current flow of different fluid phases under a wide range of pressure and temperature conditions and in several different flow configurations.
To compliment this theoretical effort, experimental measurements are required to verify multiphase flow models under controlled conditions and assess their range of applicability. This is why there exists a large number of multiphase flow loops around the world.
However, there are numerous varieties of multiphase flow occurrences due to differences in pressure and temperature, fluid types, flow regimes, pipe geometry, inclination and diameter, and whether the flow is steady-state or transient.
Consider the example of hydrocarbon producing fields in the North Sea. Typical parameters for an oil well in the northern basins are as follows: production rate of 800–1600 cubic meters per day, tubing diameter of 0.102–0.130 meters, reservoir depth of 3000–3500 meters, oil density of 825–930 kilograms per cubic meters, gas-oil-ratio of 100 standard cubic meters per standard cubic meters and water cut up to 90%. For a gas well in the southern gas basin, the typical parameters become: initial production rate of 0.7 to over 2.8 million standard cubic meters per day, tubing diameter of 0.114–0.140 meters, reservoir depth of 2500–3500 meters and initial liquid-gas-ratio of less than 1 to over 30 standard cubic meters per million standard cubic meters. The operational pressure at the wellhead may reach up to 10 MPa and reservoir pressures can be as high as 30 MPa. Furthermore, not only do well performance values vary considerably across the world and, they also vary with time for the same field.
Building a flow loop that reproduces real hydrocarbon wells, including the reservoir inertia and the complex heat transfer process taking place between the wellbore and the reservoir, is not feasible. Thus, downscaling of typical field parameters is necessary for the study of multiphase flows at laboratory conditions.
This paper presents a critical review of multiphase flow loops around the world, highlighting the pros and cons of each facility with regard to reproducing and monitoring different multiphase flow situations.
The authors suggest a way forward for new developments in this area.
Geomechanics Field and Laboratory Characterization of Woodford Shale: The Next Gas Play
Authors: Abousleiman Younane , Tran Minh , Hoang Son , Bobko Christopher , Ortega Alberto , Ulm Franz-Josef 
Published: December 2007

Abstract
Woodford shale is emerging as one of the major gas formations in the US Midwest. Despite its tremendous potential, existing data on the Woodford shale geomechanics characterization are limited at best. In this work, a well in the Woodford shale formation, 200 feet deep, was cored and logged in Oklahoma, USA. The resulting retrieved preserved cores were lab tested using standard acoustic techniques and triaxial testing for shale mechanical and poromechanical characterization in terms of compressibility, strength, pore pressure coefficient, Young's modulus, Poisson's ratio, etc. In addition, shale mechanical parameters alteration when in contact with drilling muds and fracturing fluids were measured using Brazilian tests and the innovative Inclined Direct Shear Testing Device (IDSTD™). Finally, mechanical Woodford shale parameters were also measured and correlated with field log results, using samples a tiny as drill cuttings (a few millimeters in size) with the newly emerging nano-indentation rock characterization techniques developed in the GeoGenome™ Industry Consortium. This newly developed methodology for rock testing and shale chracterization, part of the nanotechnology wave, showed excellent results when compared with shale acoustic laboratory measurements and log data and results.
Despite a relatively high quartz content as shown by XRD and Elemental Capture Spectroscopy (ECS) log results, the Woodford shale does exhibit clear transversely isotropic mechanical characteristics, from Young's moduli to Poisson's ratios and other mechanical parameters. Moreover, IDSTD™ and Brazilian tensile tests on the preserved Woodford samples exposed to different drilling and hydraulic fracturing fluids showed that fluid effects play an important role on both compressive strength and tensile strength of the shale despite the fact that the Woodford clay content mainly composes of illite and chlorite.
The mechanical and poromechanical properties of Woodford shale were measured at four different scales, from field well logs to standard rock testing to the penny-size samples of IDSTD™ and down to drill cuttings scales using the nano-indentation. Furthermore, the innovative nano-indentation techniques for rock testing have allowed the construction of a GeoGenome™ simulation model which can estimate and determine macroscopic rock properties based on porosity, packing density, and mineralogy. The simulated moduli and parameters using this model showed excellent agreement when compared to both lab and field log results.
Experimental and Numerical Investigations of Borehole Ballooning in Rough Fractures
Authors: Ozdemirtas M. , Babadagli T. , Kuru E. 
Published: December 2007

Abstract
Borehole ballooning/breathing is a combined mud loss/gain event observed during drilling operations in naturally fractured formations. Factors controlling this phenomenon must be well understood to correctly interpret its symptoms observed during drilling to avoid mixing ballooning with other formation flow incidents which might lead to unwarranted well control procedures.
A mathematical model defining the ballooning process was developed and solved numerically using finite difference approximation. It was shown that fracture roughness and fracture deformation play a significant role on the flow of drilling fluid in and out of a single fracture. In this study, the focus was mainly on the effect of fracture roughness (characterized by the fractal dimension of the fracture surface) and fracture aperture.
The main goal of this work was to compare the numerical model results with the laboratory scale experimental observations. Therefore, experiments were performed to study the mud loss and gain events in artificially fractured rock samples. One-inch diameter and 3-inches long cylindirical samples of Berea sandstone, Indiana limestone and granite were used for the experiments. Two different fracture types were used to analyze the effect of fracture surface roughness on the flow of drilling fluid in and out of the fracture. In order to create smooth fracture surfaces, cores were cut precisely into two equal pieces using a blade. Alternatively, axial load was applied on the cylindrical rock samples until a longitudinal fracture with rough surface was generated.
The results of experimental observations and numerical model study on the importance of fracture roughness were provided. Situations where the degree of roughness becomes critical were identified.