bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Approach to Information Discovery—Geography Really Does Matter
Authors: Palkowsky B. 
Published: December 2007

Abstract
The energy industry is under constant pressure to improve performance measures and knowledge worker productivity. The demand to adequately replace reserves and increase profitability is constantly there despite the decline in field sizes, decreased well production and escalating depletion rates. The costly investments needed to build reserves utilizing the rapidly declining workforce demands further adoption of new technology. Innovative technology has always played a key role in making knowledge workers more productive by reducing workflow cycle time and improving reservoir prediction accuracy.
Reservoir Drilling Fluids—Designing for Challenging Wells in a Remote Location
Authors: Bradshaw R. , Hodge R. , Wolf N. O. , Knox D. , Hudson C. , Svoboda C. 
Published: December 2007

Abstract
The Belanak A platform is situated in the Natuna Sea region of Indonesia. The reservoir sections are high temperature (315°F BHST), and the openhole sections were planned to be between 3500 and 4500 ft horizontal, some with tortuous well paths required to meet the target. In order to ensure excellent drilling performance and optimum protection of the producing formation, a formate-based, low-solids reservoir drilling fluid was selected – the first time such a system had been used in Indonesia.
In this paper, the authors detail the design and successful application of the unique reservoir drill-in fluid in the demanding and remote well.
Drilling and Completing Wells Uphill
Authors: Prince P. , Tarmidi R. , Hou T. W. 
Published: December 2007

Abstract
In the work environment of continuous improvement as a method to reduce both drilling and production costs, alternative means are required to attain objectives which have previously been deemed unachievable. The introduction of new tools and technologies has enabled increasingly challenging wellpaths to be drilled and completed. Trajectories labeled as undrillable even a few short years ago are now being realized.
The high cost and environmental concerns associated with offshore installations and the resultant requirement for drilling multiple wells from a common facility, has been a significant driver in the field of extended reach drilling to drain reservoirs with significant step-out. Sub-surface geological issues and wells with multiple targets have resulted in complex 3D well trajectories such as ‘pregnant lady’, ‘snake’ and ‘dragon’ wells.
Within the above context, Brunei Shell Petroleum (BSP) has identified that by drilling ‘fishhook’ shape wells, whereby a large section of the wellpath is drilled and completed at an inclination greater than 90°, significant savings in both drilling and production costs can be achieved. This is a case study of such a well drilled in mid 2004, whereby some 875m, or 35% of the total well trajectory was drilled at an inclination greater than 90°. The well also required 7" casing to be run and cemented to well TD, sand control in the form of Frac and Packs, and Expandable Sand Screens (ESS) run across three reservoir zones, with isolation between each zone.
Maximum inclination was 126.5°, and some 366m true vertical depth (TVD) reclaimed.
A Flow Assurance Study for a Satellite Crude-Oil System With Severe Emulsion
Authors: Tang Y. , Wong S. 
Published: December 2007

Abstract
This paper discusses a recently completed FEED and post-FEED flow assurance study for the development of two satellite crude oil producing systems in West Africa. A 33 km 24 in. trunkline will transport the satellite field production to the main field.
With a gas/liquid two-phase trunkline, terrain induced slugging required a slug catcher that was too big to be cost-effective. To mitigate the severe slugging problem, a gas/liquid separator was recommended at the inlet of the satellite manifold and the liquid surge volume could be completely eliminated. A 4 in. separate gas pipeline was adequate to avoid surge capacity requirements at the outlet.
The demulsifier becomes less effective at watercuts (WC) greater than 60% and the peak viscosity can be as high as 10,000 cp. The restricting factors are the maximum-allowable-operating-pressure (MAOP) of 46 bara for the pipeline startup. A two-step ramp-up schedule was recommended to keep the peak pressure to an acceptable level. A limited number of well VSDs (Variable Speed Drive for ESP wellhead control) are required based on the slower ramp-up scheme and production profile.
Some guidelines are given in this paper for managing emulsion crude oil system issues.
A Rigorous Compressible Streamline Formulation for Two- and Three-Phase Black-Oil Simulation
Authors: Cheng H. , Osako I. , Datta-Gupta A. , King M. J. 
Published: December 2007

Abstract
Streamline simulators have received increased attention in the petroleum industry because of their ability to effectively handle multimillion cell detailed geologic models and large simulation models. The efficiency of streamline simulation has relied primarily on the decoupling of the 3-D saturation equation into 1-D equations along streamlines using the streamline time of flight as the spatial coordinate. Until now, this decoupling has been strictly valid for incompressible flow. Applications to compressible flow have generally lacked strong theoretical foundations and for the most part yielded mixed or unsatisfactory results.
In this paper for the first time we generalize streamline models to compressible flow using a rigorous formulation while retaining much of its favorable characteristics. Our new formulation is based on three major elements and requires only minor modifications to existing streamline models. First, we introduce an ‘effective density’ for the total fluids along the streamlines. This density captures the changes in the fluid volume with pressure and can be conveniently and efficiently traced along streamlines. Thus, we simultaneously compute time of flight and volume changes along streamlines. Second, we incorporate a density-dependent source term in the streamline saturation equation to account for compressibility effects. Third, the effective density, fluid volumes and the time-of-flight information are used to incorporate cross-streamline effects via pressure updates and remapping of saturations. Our proposed approach preserves the 1-D nature of the saturation calculations and all the associated advantages of the streamline approach. The saturation calculations are fully decoupled from the underlying grid and can be carried out using large time steps without grid-based stability limits.
We demonstrate the validity and practical utility of our approach using synthetic and field examples and comparison with both commercial finite difference and streamline simulators. The synthetic examples involve waterflooding in a ¼-five spot pattern under undersaturated conditions and also three phase flow with both free and solution gas. Our results show close agreement with the finite difference simulator in terms of water-oil and gas-oil ratio histories for an extended period of time. The field example is from a highly heterogeneous carbonate reservoir in West Texas and includes multiple patterns consisting of 11 injectors, 31 producers and over 30 years of production history. Our proposed formulation results in significant improvement in performance prediction over current commercial streamline simulators.
Strength Analysis of Liners for Horizontal Wells
Authors: Plácido J. C. R. , Pasqualino I. P. , Fonseca C. E. 
Published: December 2007

Abstract
Liners with slots or holes are broadly employed to increase the production of horizontal wells. However, as these openings at the casing wall can reduce its strength under mechanical loading, such as radial compression, axial tension and bending, the structural response of the liners must be properly studied. A numerical and experimental procedure has been developed to optimize liner geometries. Different liner conceptions, with varied arrangements of slots and holes have been proposed to study its structural response under mechanical loading. The proposed conceptions were analyzed with the aid of nonlinear three dimensional finite element models incorporating metal plasticity, contact behavior and large rotations. Experimental tests of liners with slots under radial compression and bending were accomplished. The finite element models were calibrated through the correlation of experimental and numerical results.
Coal Failure and Consequences for Coalbed Methane Wells
Authors: Palmer I. , Moschovidis Z. , Cameron J. 
Published: December 2007

Abstract
We provide a summary of coal failure during the life of a typical coalbed methane (CBM) well, and some consequences for the CBM industry. Because coals are weak in general, these consequences are often important, and can have a significant impact on drilling, completion, and production of CBM wells.
Failure during drilling: horizontal wells are the preferred completion in the Arkoma basin, for instance. Drilling horizontal wells is sometimes hindered by hole collapse, especially when drilling underbalanced, or drilling through a depleted coal. We demonstrate the relative importance of this by comparing drilling stability in coals of various ranks and depths.
Failure during hydraulic fracturing: in weak coals the increased pore pressure around a fracture can cause shear failure. The likelihood of shear failure is charted against coal rank, for given in situ stress, and fracturing pressure. When coal fails in shear, coal fines are produced in the reservoir, as has been demonstrated in the lab. The creation and movement of such fines can reduce the coal permeability, and the frac conductivity. However, dilatancy accompanying shear failure can also lead to permeability increases.
Failure during production: when a CBM well is put on production, by applying a drawdown, the lowering of BHFP can cause failure of the coal (or collapse of a horizontal openhole) if it is weak enough. The critical drawdown for failure and fines production can be predicted by using advanced technology borrowed from the sand production arena. We can characterize the probability of failure by coal rank, drawdown, depletion, as well as other parameters like in situ stress.
Careful assessment of the likelihood of coal failure during drilling, fracturing, or production, as a function of coal rank and in situ stress, can lead to mitigating efforts to avoid the bad consequences. For example, applying a smaller drawdown in a producing CBM well may prevent or defer failure in weak coals and mitigate fines plugging of the formation and fracture, fill in the wellbore, and pump or compressor problems.
Evaluation of Unconventional Resource Plays
Authors: Haskett W. J. , Brown P. J. 
Published: December 2007

Abstract
Making sound business decisions in one of the hottest domestic exploration plays, unconventional gas, offers a set of challenges not usually encountered with more traditional opportunities. Unlike with standard prospect and conventional play risk analysis, geologic chance is not a major issue, and estimates of initial production, decline rates, mechanical efficiency, and success planning dominate the analysis rather than traditional volumetric determinations. The valuation and assessment of unconventional or "continuous resource" opportunities is not feasible using traditional probabilistic, volumetric-based methods. A fully stochastic business, value-chain model is the best way to assess the potential of an unconventional play. Such an evaluation method allows for multi-disciplinary and cost input that affords decision makers with the appropriate data to make good decisions.
The boundaries of unconventional reservoirs extend well beyond the limits of most individual acreage holdings. As such, the recommendations of Schmoker and others to base the full resource availability on a cell or single well drainage area should be embraced as a starting point.
Resource uncertainty is handled by a continuum of well size distributions arranged to form an EUR Envelope. Volumes are only part of the equation, however. Uncertainty in the production profile must be taken into account, with variations in initial production, decline rate, and hyperbolic exponent figuring prominently in the final assessment of profitability.
There are four main stages in the exploitation of unconventional opportunities: Exploration, Evaluation, Delineation, and Development. Proper assessment, including identification and management of downside risk, requires a decision-focused, integrated, multi-discipline evaluation process through the four stages.
Unconventional plays use an initial number of wells to test the viability of a play and stimulation technology/methods. These pilot programs can be optimized, for number of wells, and company risk tolerance. Pilot Effectiveness is the (measurable) probability of the pilot program providing truthful results given the small number of test wells modeled.
Output from the proposed stochastic evaluation method include both single economic and product-based metrics in cumulative probability curves, as well as time series output in both aggregate and pathway forms. A thorough understanding of results analysis, Value of Information, and decision options is encouraged in order to take full benefit of the stochastic assessment method.
A New Approach for Capitalizing on Continuous Downhole Pressure Data
Authors: Viberti D. , Verga F. , Delbosco P. 
Published: December 2007

Abstract
Intelligent completions typically include permanent downhole gauges (PDG's) for continuous, real-time pressure and temperature monitoring. If adequately applied, such new technologies should allow anticipation of oil production and increase of final recovery with respect to traditional completions. In fact, pressure data collected from PDG's represent an essential information for understanding the dynamic behavior of the field and for reservoir surveillance. The potential drawback is that the number of data collected by PDG's can grow enormously, making it very difficult, if not impossible, to handle the entire pressure history as it was recorded. As a consequence it might often be necessary to reduce the pressure measurements to a manageable size, though without losing any potential information contained in the recorded data.
As extensively reported in the literature, long-term data might be subject to different kinds of errors and noise, and not be representative of the real system response. Before the data can be used for interpretation purposes, especially if pressure derivatives are to be calculated (for instance, in well test analysis), an adequate filtering process should be applied. Multi-step procedures based on the wavelet analysis were presented in the literature for processing and interpreting longterm pressure data from PDG's. In this paper an improved approach largely based on the wavelet algorithms is proposed and discussed for the treatment of pressure data.
All the steps of the procedure, namely outliers removal, denoising, transient identification, and data reduction were applied both to synthetic and real pressure recordings. Results indicated that the application of the proposed approach allows identification of the actual reservoir response and subsequent interpretation of pressure data for an effective characterization of the reservoir behavior even from very disturbed signals.
Mapping Fluid Flow in a Reservoir Using Tiltmeter-Based Surface-Deformation Measurements
Authors: Du J. , Brissenden S. J. , McGillivray P. , Bourne S. , Hofstra P. , Davis E. J. , Roadarmel W. H. , Wolhart S. L. , Wright C. A. 
Published: December 2007

Abstract
Surface deformation measurements have been used for years in oilfields to monitor production, waterflooding, waste injection, steam flooding, and Cyclic Steam Stimulation (CSS). They have been proven to be a very effective way to monitor the field operations and save money for operators wishing to avoid unwanted surface breeches, casing failures and excessive subsidence due to production. This paper demonstrates that more information can be extracted from surface deformation measurements by inverting the surface deformation for the volumetric deformation at the reservoir level, so the areal distribution of volumetric deformation can be identified. First, a poroelastic model is presented to calculate the deformation due to the volumetric change in the reservoir. Then, a linear geophysical model is formulated to invert for the reservoir volumetric deformation from the measured surface deformation (or tilt). Constraints are added into the procedure as necessary to better resolve the inversion problem. After each inversion, the theoretical surface deformation (displacement, tilt, reservoir compaction and volumetric strain) can be calculated from the inverted volumetric deformation distribution which best fits the measured deformation data (or tilt) at the surface. The technique of mapping fluid flow using surface deformation was applied to real data from a cyclic steam injection project.
Assessment and Development of the Dry Horseshoe Canyon CBM Play in Canada
Authors: Bastian P. A. , Wirth O. F. R. , Wang L. , Voneiff G. W. 
Published: December 2007

Abstract
This paper discusses how the Horseshoe Canyon coalbed methane (CBM) play in Western Canada was converted from an under-explored, non-commercial resource to a major commercial play through the application and modification of technology and analysis techniques from other basins, and how this play is being developed today. As of December 2004, production from the Horseshoe Canyon CBM play is estimated to be over 100 MMscfd of gas, with future production expected to grow significantly. The first commercial developments were completed in 2003 and 2004, and drilling is increasing and expected to exceed 3,000 wells per year in 2005.1
The Horseshoe Canyon CBM play covers a large geographic area of 200 miles by 50 miles, and exists in a large, complex vertical section with numerous coal, sand, silt, shale and mudstone layers. In addition, the play is naturally under-pressured, and the coal beds are mostly dry. Because of these complex and unique characteristics, assessment of commercial viability and development optimization can be confusing and only applicable over small parts of the play. MGV Energy, Inc. (a wholly-owned subsidiary of Ft. Worth-based Quicksilver Resources, Inc.) and its initial joint venture (JV) partner, PanCanadian Petroleum Limited (now EnCana Corp.), discovered the techniques to achieve commerciality and pioneered many of the practices used by industry today for Horseshoe Canyon CBM development. In this paper, we discuss identification of the reservoir opportunity, including data acquisition and analysis. We describe geologic and reservoir models, and production forecasting methods. We also cover completion and production practices, spacing optimization and reserves estimation procedures.
Streamline Simulation of Four-Phase WAG Processes
Authors: Bhambri P. , Mohanty K. K. 
Published: December 2007

Abstract
Miscible or near-miscible water-alternating-gas (WAG) flooding is an attaractive process for medium viscosity (30-300 cp) oils if solvents are available. Four fluid phases can develop in these processes. Very few reservoir simulators and none of the published streamline simulators can handle four fluid phases. In this work, we have developed a four-phase streamline module that works with an existing finite-difference simulator to study gas or WAG injections in medium viscosity reservoirs. 2-D and 3-D simulations of WAG injections in quarter five-spot models have been demonstrated using this simulator. WAG injection simulation of the reservoir oil indicates that four phases exist near the gas-oil displacement front. The second liquid phase (or the third hydrocarbon phase) is present in many grid blocks under the conditions studied. WAG injection improves the sweep over the single slug solvent injection. For the cases studied, the sweep efficiency increases with the WAG ratio, but this result cannot be generalized. Reservoir hetrogeneity also affects the sweep. Gravity override is observed in WAG simulations with the vertical (X-Z) crossection. Oil recovery is low in the lower part of the reservoir. Horizontal production wells affect the fluid flow and thus the sweep of the reservoirs.
Optimizing the Subsurface Work Environment of the Future
Authors: Reece C. A. , Catron R. E. , Hammond R. D. , Schmidtke E. A. 
Published: December 2007

Abstract
Over its history, ExxonMobil* has pursued a variety of initiatives to improve its subsurface work environment and capabilities. A recent multi-disciplinary and multi-company effort identified a step change improvement opportunity in the subsurface work environment with:
increased integration across technical disciplines and functional companies, general interest oversight of ongoing initiatives to ensure that all efforts are aligned with a desired end state while capturing efficiencies, and improvements in foundational areas such as data management concurrent with the development of new capabilities.
This paper shares ExxonMobil's vision for the Subsurface Work Environment of the Future and critical success factors to achieve it. ExxonMobil's commitment to global standards and a global functional organization provides a unique framework upon which to integrate and leverage work processes, tools and technology across its upstream companies and technical disciplines. This vision is based on business-driven affordability, proprietary and commercial technology and a systems management approach to the subsurface business.
Injectivity Profiling in Horizontal Wells Through Distributed Temperature Monitoring
Authors: Pimenov V. , Brown G. , Tertychnyi V. , Shandrygin A. , Popov Y. 
Published: December 2007

Abstract
Downhole permanent monitoring sensors offer unique options for continuous evaluating flow regimes, completion integrity, formation properties, flow assurance effectiveness and optimal production/injection operations. The use of temperature data for vertical injection wells has been widely applied in practice and has been thoroughly discussed in literature. The problems occur for Distributed Temperature Sensors (DTS) installed in horizontal well due to small variations of geothermal temperature along the wellbore. Unlike the conventional gauges, DTS data are acquired in both temporal and spatial dimensions that exploit the great potential for real-time operation optimization.
We present an interpretation technique for analysis of temperature profiles recorded with fiber optic distributed temperature sensor (DTS) in horizontal water injectors. Simple semi analytical models were developed for simulating mass and heat transfer in horizontal well and collector during injection and warm back. Two inversion procedures based on these models were developed allowing calculation of injectivity profile from temperature profiles recorded during injection and warm-back. These procedures were successfully validated on CFD numerical model and tested on field data.