bluuebunny/crossref_metadata_2025_split huggingface dataset:
Propagating Interval Uncertainties In Supervised Pattern Recognition For Reservoir Characterization
Authors: Nivlet P. , Fournier F. , Royer J. J. 
Published: December 2007

Abstract
In the petroleum exploration/production context, characterizing the reservoir quality, identifying the main rock types, or predicting their spatial variations is a challenge for the industry. To achieve this purpose, supervised pattern recognition methods, as discriminant analysis are widely used. These methods aim at calibrating, when possible, a relationship between field features -for example a set of borehole measurements, or a set of seismic attributes- and a predefined set of classes -for example, different rock types-. It has yet the major drawback not to take into account the uncertainties on the measurement arrays, which may cause drastic misinterpretations of reservoir characteristics. The methodology developed is an extension of the standard parametric approach to discriminant analysis. The calibration phase follows the same main steps as the standard algorithm, except that all the processed quantities are intervals. The different interval computations are based on interval arithmetic. Eventually, any imprecise object is assigned to a subset of classes, consistent with the measurements and their uncertainties. As a result, the computed reservoir quality model is less precise, but more realistic, taking into account data and its uncertainties.
Well Planning Quality Improved Using Cooperation between Drilling and Geosciences
Authors: Cayeux Eric , Genevois Jean-Michel , Crepin Stephan , Thibeau Sylvain 
Published: December 2007

Abstract
To improve the quality of well planning and decrease the risks involved in drilling complex wells, E&P companies have been focusing during the last decade on collaborative work of asset team. A new workflow consisting in separating multidisciplinary feasibility evaluation from detailed engineering has now been used on several projects. This workflow decreases dramatically the necessary cycle time to plan a well since only those alternatives that are viable for all disciplines are going through detailed analysis.
The angle block of this method is the combination of a shared earth model with advanced three-dimensional visualisation techniques and quick, but precise evaluation tools. The use of constraints to define default values makes it simple to plan targets and wellbores only with 3D interactive graphic editing. Those constraints can themselves be relative to the structural geological model. Therefore the generated design is accurate enough to be trusted when used by the various evaluation functions. To assess the value and feasibility of a target/well solution, the asset team can use interactively drainable volume, wellbore position uncertainty, driller's target, wellbore collision and drillstring mechanical calculations.
This approach has been used in different contexts for planning wells in an oil field in deep water western Africa and a gas field in Norway. For the field in the golf of Guinea, reservoir simulation has been used to define the location of horizontal drains. In Norway, an extended reach well has been planned using a 3D-reservoir model. The methodology has helped improve the overall understanding of the problem by sharing and explaining each other's constraints, thus improving the well planning quality and reducing the design cycle time.
Optimization of Volumes, Costs, and Reserves through Integrated "Best Practice" Methodologies
Authors: McMurray Mark G. 
Published: December 2007

Abstract
In the E & P business, human resources and technical capability tends to follow growth related capital activities. As a result, "Practice Gaps" form over time in mature fields, compromising value. Cross-disciplinary and collaborative Best Practices ensure producing assets are periodically recalibrated to current technologies, system capacities, and dynamic data. Examples of Best Practices that address asset performance optimization (volumes, costs, and reserves) and portfolio management strategies include Opportunity Assessment and Integrated Well/Field Review processes.
Improved portfolio value can be realized by implementing Best Practice applications to unlock previously unrealized potential. This renewed understanding drives better business decisions affecting such areas as asset retention, asset acquisition, asset divestment, and the appropriate allocation of capital and human resources across the producing portfolio.
Compaction-induced porosity/permeability reduction in sandstone reservoirs:Data and model for elasticity-dominated deformation
Authors: Schutjens P. M. T. M. , Hanssen T. H. , Hettema M. H. H. , Merour J. , de Bree J. Ph. , Coremans J. W. A. , Helliesen G. 
Published: December 2007

AbstractOpen-literature and new experimental compaction data of five reservoir and 16 outcrop sandstones are used to delineate the near-elastic, inelastic and failure domain in 3D-stress space for porosity classes 5 to 15%, 15 to 25% and 25 to 35%. Applications of this compaction-domain model include the analysis of the extent of the near-elastic domain (where elasticity theory can be used to describe and predict rock deformation), the pore volume compressibility (Cpp), and the permeability reduction as a function of reservoir stress path. This is illustrated for a well-consolidated sandstone reservoir with an average porosity of about 18%. Two aspects of dynamic reservoir modeling in the near-elastic domain are addressed: Calculation of Cpp from raw data of volumetric compaction as a function of isotropic total stress change, and the correction of Cpp for a non-hydrostatic reservoir stress path. Open-literature work combined with our experimental data indicates that the compaction-induced permeability reduction of 15-25% porosity sandstone in the near-elastic domain depends predominantly on the increase of the effective mean stress, and not on the reservoir stress path.
A Case History on Integrated Fracture Modeling in a Giant Field
Authors: Al-Ali Z. A. , Stenger B. A. 
Published: December 2007

Abstract
In this paper, a case study is used to demonstrate a straightforward methodology of faults, fractures and high-permeability layers integration in a single porosity single permeability (SPSP) reservoir simulation model. The application of this method in the Ghawar Arab-D reservoir indicated an adequate modeling of the water encroachment pattern.
The described methodology starts with the identification of structural lineaments from 3D seismic data analysis (radius of curvature, coherency analysis), the availability of image logs being critical to validate this early step. Further engineering data such as mud losses during drilling, flowmeter surveys, transient well test interpretations, geochemical analysis and water encroachment patterns are integrated to further describe sealed or conductive fractured areas among the initially picked set of lineaments. Stratiform very high permeability streaks (Super-K) are also described at this stage, resulting in a fine-scale geological model conditioned by engineering data.
Both conductive fractures and stratiform Super-K features are being assigned adequate transmissibility and relative permeability functions in the upscaled reservoir simulation model. Transmissibility values are subject to further adjustments during the history matching process.
Comparison with dual porosity dual permeability (DPDP) modeling is briefly discussed. Cost (CPU time) and benefits of SPSP and DPDP modeling techniques are addressed to conclude that in the present case, the trade-off of implicit fracture/Super-K modeling (SPSP) is compensated by a sufficiently-accurate modeling of the water encroachment pattern and shorter simulation turnover times.
A New Approach to Fluid-Flow Modeling of Directional Permeability in a Faulted Anticline, Little Sand Draw Field, Big Horn Basin, Wyoming.
Authors: Rabaa A. S. , Van Kirk C. W. , Hurley N. F. 
Published: December 2007

Abstract
Little Sand Draw field, Hot Springs County, Wyoming, is a fractured and faulted asymmetric anticlinal oil reservoir. The main producing formation is the Permian Phosphoria Formation. The goal of this project1 was to apply a new geological and engineering approach to simulate directional permeability in a faulted and fractured oil reservoir. The hypothesis to be tested in this study was whether reservoir models with or without tear faults provide a good history match.
Tear faults, which have apparent strike slip offset and occur at high angles to the fold axis, have been quantified at Thermopolis anticline, an analogous structure 6 mi (10 km) to the south. Tear faults are largely unrecognized in subsurface reservoirs and are commonly overlooked in simulations. However, they may have important effects on directional permeability. Anisotropic directional permeabilities, roughly perpendicular to fold axes, are known from pressure-interference tests in the Little Sand Draw field. The spacing of faults in outcrop was used as input for faults in the reservoir model.
A 3-D geological model that correctly honors the structural geology was built using EarthVision (Dynamic Graphics) software. Using the ECLIPSE black-oil simulator (Geoquest, Schlumberger), three fluid-flow models were generated: (1) an unfaulted-unfractured model, (2) a faulted-unfractured model, and (3) a faulted-fractured model which simulated high permeability conduits along the tear faults. Fractures were simulated by assigning permeability anisotropy to the matrix blocks. History matching performed on these models tested which one of them best resembles actual field performance. The unfaulted-unfractured model could not produce enough total fluids to match historical data, and reservoir pressures were too low. The faulted-unfractured model improved the history match, but could not match production data. The faulted-fractured model does the best job of matching the observed past performance at Little Sand Draw.
SubSea MudLift Drilling: Design and Implementation of a Dual Gradient Drilling System
Authors: Eggemeyer J. C. , Akins M. E. , Brainard R. R. , Judge R. A. , Peterman C. P. , Scavone L. J. , Thethi K. S. 
Published: December 2007

Abstract
The subSea MudLift Drilling Joint Industry Project (SMD JIP) completed Phase II of the design and development of a dual gradient subsea pumping system in June 2000. This paper is the last of a series of three discussing the SMD JIP's evolution of dual gradient drilling (see SPE 71357, "subSea MudLift Drilling Joint Industry Project: Delivering Dual Gradient Drilling Technology to Industry"; and SPE 71358, "subSea MudLift Drilling: Planning and Preparation for the First subsea Field Test of a Full-Scale Dual Gradient Drilling System at Green Canyon 136, Gulf of Mexico").1,2
The mudlift pumps (MLPs) and other SMD system components were thoroughly tested in the flow loop at the Hydril Technology Center (HTC), but the components were not yet integrated into a system which could be deployed on an offshore well. The next step was specifying which rig would be used for drilling a selected test well; the rig's specifications would determine how the SMD system integration design progressed. Modifications to the rig would also be necessary to ensure that the SMD system could be safely installed.
The Ocean New Era (Diamond Offshore) was identified as the test rig. This is a 2nd generation 2449 ST VDL rig with 1500ft water depth capability. Once the New Era was selected, both SMD and rig personnel began the parallel tasks of fitting the system to the rig, and modifying the rig to accommodate the additional weight, power requirements and ancillary equipment that the SMD system installation would entail. The dimensions and design of the SMD package were dictated by the size of the rig's moonpool, its BOP handling equipment and the LMRP height.
Based on coordination with rig personnel, the SMD system was assembled in its "rig-adapted" form at HTC, including all manifolding, the seawater power system, the MLPs, and the electronic controls. In compliance with the JIP Basis of Design (BOD), a full-scale factory acceptance test (FAT) of the system was initiated on April 30, 2001 and completed on May 16, 2001. Prior to the FAT, separate testing was performed on certain SMD components not specifically associated with pumping, including the solids processing unit (SPU) and the drillstring valve (DSV). The hydraulic power system along with hydraulic lines, control pod, control cabling and connectors, were all tested in a hyperbaric chamber to simulate deep ocean conditions. A final "endurance" test of the system was conducted before transporting it to the rig at dockside in Galveston. This paper will discuss the parallel efforts of the rig and SMD teams to design, test and integrate the SMD system on the rig. In addition, the results of the FAT and component testing carried out in Phase III, and the lessons learned will be examined.
Drilling Fluid Losses and Gains: Case Histories and Practical Solutions
Authors: Tare Uday A. , Whitfill Donald L. , Mody Fersheed K. 
Published: December 2007

Abstract
Identification and resolution of drilling fluid losses and gains while drilling have gained in importance due to the high cost of deepwater drilling focusing concern on any delays. Drilling fluid losses and gains, or wellbore breathing, can be attributed to several factors. These include the local geological setting, inherent natural fractures in the formation, well trajectory, drilling operations, equivalent mud weight, mud rheology and chemistry, etc. Recurring observations of formation influx while drilling or during connections oftentimes are interpreted as a potential well control situation. Therefore significant rig time can be lost to insure this is not the case. There have been recent developments in the area of monitoring drilling fluid losses and gains. A fundamental understanding of the reasons for mud losses and gains, along with the implementation of these recent monitoring techniques, would greatly improve managing this problem.
In this work, mechanisms are provided to explain drilling fluid losses and gains. Loss and gain situations can occur in a variety of drilling scenarios: examples would be while drilling in deeper waters, where the operating window between the pore pressure and fracture gradient is narrow; drilling extended reach wells where the problem may be encountered at higher hole inclination angles; drilling though formations with abnormally high geothermal gradients, etc. In addition, case histories are provided where drilling fluid losses and gains were diagnosed during a borehole stability analysis, followed by implementation of recommended remedial measures that resulted in better management of the problem on later wells. Sometimes potential for mud losses and gains are interpreted from formation leak-off tests. New solutions, which include alterations to the drilling fluid composition and lost circulation sweeps, are proposed to help mitigate the occurrence of drilling fluid losses and gains.
Successful Well Control in the Cantarell Field Applying the Dynamic Method
Authors: Carlos Osornio V. , Humberto Castro Mtz. , Victor Vallejo A. , Enrique Ayala V. 
Published: December 2007

Abstract
While drilling the gas cap zone of the offshore Cantarell 69-I well, a gas kick was taken, becoming a blowout. The gas ignited, causing a large fire situation, and as a consequence the drilling rig was severely damaged.
Due to the flowing conditions of the well, it was not possible to achieve well control through the tubing string. Therefore, two different alternatives were analyzed to solve the problem: momentum and dynamic kill. This paper presents the results obtained applying both techniques, as well as the well control analysis and procedure.
First, the pressure profile in the well was calculated, as well as the gas flow rate (230 MMscfd) in blowout conditions. Then the kill flow rate (considering seawater) was calculated for both methods. The dynamic method yielded a kill flow rate of 19 bbl/min. Once the flow rate required to control the well was defined, the casing head was inspected to assure the success of the attempt, and it was in good condition to perform the operations.
The operative sequence to control the contingency in a minimum time consisted of connecting the 20 x 13 3/8-inch casing head to a cementing ship through 2-inch lines in order to pump seawater. The total time required to control the gas blowout was 11 hours after the kick was taken. The success consisted of reaching a flowing pressure at the tie-back depth (680 m) greater than the reservoir pressure, which was generated by the frictional pressure losses and the hydrostatic head of the multiphase flow (gas and seawater) inside the injection string.
Real-Time Measurement of Downhole Annular Cementing Temperature for Precise Cementing Design and Application
Authors: Dillenbeck R. L. , Mombourquette I. G. 
Published: December 2007

AbstractThe tests required to customize a cement system for a well are run either at Bottom Hole Static Temperature (BHST) or at a lesser temperature known as Bottom Hole Circulating Temperature (BHCT), depending on the specific test being run. Many of the characteristics being optimized in a cement system must be tested as closely as possible to the actual temperature encountered by the cement slurry as it is circulated into a well. Failure to test the system at the correct temperature can result in improper loading of expensive additives, and expensive cementing failures. Many in the industry have long realized that standardized API tables will not always give the most accurate representation of BHCT for every well. In order to most accurately design a cement system, it is necessary to have a better understanding of the actual temperature encountered by the system during placement in a given well. Accordingly, computer models have been developed to simulate conditions encountered down hole. Having worked with such programs, the authors believe that in order to be accurate, most of these models require lithological thermal conductivity, and fluid specific heat data that is not generally available on most new wells. Because of these requirements, many simulations are run where "default" or "average" input values are used, and the Circulating Temperature projections become highly educated guesses.In an effort to procure more accurate and useful data, technology has been developed that allows for the monitoring of annular temperature of all fluids during placement of cement in a new well. Further, the technology allows for continued monitoring of the cement temperature during the critical cement transitory hydration phase, as well as throughout the life of the well. The authors will detail the development of the technology and the actual application in the field in multiple countries. Data obtained from wells utilizing the technology is analyzed and compared to current API values as well as BHCT projections from a Finite Analysis computer model. Finally, the authors will detail how the information made available by this technology can be applied to provide more accurate, fit for purpose cement designs that are optimized for the actual conditions encountered in a well.
Innovative Solution for Cementing Across Formations with Very Low Fracture Gradients
Authors: Hun Christian , El-Hassan Hassan , Husam Helou , Hasni A. Latif , Mohsen A. Hameed 
Published: December 2007

Abstract
Lost circulation is a common problem in the massive Simsima and Umm El Radhuma carbonate formations that extend across all United Arab Emirates fields and the Gulf countries. To minimize losses during drilling, 8.10-lbm/gal emulsion mud or aerated mud is often used.
As the result of corrosive brines presence across the formations extending to the shallow depths and causing casing corrosion problems, one of the main objectives of cementing the 9 5/8-in. casing is to ensure well integrity and casing protection by having cement to surface.
In these carbonates, multistage cementing tools have operational problems and frequently develop casing leaks over the life of a well. Top jobs do not guarantee complete linear and radial coverage of the casing along the whole interval. Complete losses are expected with conventional lightweight cement systems, and their set cement properties do not meet requirements for casing corrosion protection. These issues make successful cementing in these formations a real challenge.
To overcome the challenges, a new ultralightweight cement system (ULC) with a density close to that of water and superior set cement properties was used to ensure good casing protection and zonal isolation. This paper addresses the challenge to measure the low density of the slurry and the tools necessary to differentiate between mix fluid and the final slurry.
The new ultra-lightweight cement was evaluated using standard cement evaluation logs, and case studies are presented that confirm successful zonal isolation.
Real Options and Probabilistic Economics: Bridging the Gap
Authors: Hooper H. T. , Rutherford S. R. 
Published: December 2007

AbstractThree approaches to economic evaluations that have been widely discussed in the literature are decision trees, Monte Carlo simulation, and real options. Authors have shown that the incorporation of decision tree logic into Monte Carlo simulation offers an added degree of insight into the evaluation, and generally provides a more realistic valuation of an asset by incorporating some degree of management decision making. While probabilistic economics (either decision trees or Monte Carlo simulations) and real options differ significantly in the type and amount of input data, as well as the format and applicability of output, they both have capability to capture some value of active decision making by management. This paper attempts to bridge the gap between the two approaches, at least conceptually, for the practicing engineer. Rather than take an academic approach, the authors illustrate key points through real world examples. Also, since discount factors are often considered the most fundamental difference between the discounted cash flow and options pricing approaches, the implications of that issue are discussed as well. Finally, attempts to "compensate" option-pricing algorithms such as the classic Black and Scholes are discussed, in an effort to incorporate more reality into real options evaluations.