bluuebunny/crossref_metadata_2025_split huggingface dataset:
Real-Time Wire Management System Improves Reliability and Efficiency in Slickline Service Operations
Authors: De Jesús O. , Mineo R. , Foster J. C. , Hamid S. 
Published: December 2007

Abstract
The technological enhancements, new tools, versatility, and cost efficiency of slickline services have increased its usage considerably in the last decade. However, an efficient method to capture the integrity of slickline wire prior to its use has not been available until recently. This paper will discuss a new Real-Time Wire-Management System that has been developed to predict the used life of the wire in slickline operations. The system uses a general wire model to detect fatigue failure in the wire. The model results are accumulated for the whole life of each drum of wire, and then, when the use life exceeds predetermined levels, the operator can remove the slickline tool and can make appropriate changes to the wire. A specified amount of line can be cut off to move the bending point to a new location, or the line can be reversed, extending the life of the whole unit by moving the operation to wire that was located previously at the core of the drum. Finally, the system can help the operator determine when a drum of wire should be discarded completely. Field applications have shown that this system can result in enhanced reliability in slickline operations and that cost savings from reductions in catastrophic operational events can be significant.
Complete Decision-Tree Analysis Using Simulation Methods: Illustrated With an Example of Bitumen Production in Alberta Using Steam Injection
Authors: Laughton D. , Joe G. , Paduada M. , Samis M. 
Published: December 2007

Abstract
In September 2003, the SPE held a workshop on the future of asset valuation in corporate asset design and selection process. One suggestion that came out of the workshop was that methods should be developed that will allow the use of decision tree analysis not only in the exploration and appraisal phases of the asset life cycle, but throughout the cycle, and in such a way that the decisions to be analysed are made not only in response to the resolution of geological uncertainty but also in response to the resolution of price and other commercial uncertainty.
This will require a significant expansion of the computational technology available to deal in decision tree analysis with complex policy spaces in the face of complex structures of underlying uncertainties.
Work has been gong for several years in financial markets to deal similar issues using different subtle combinations of simulation and optimisation methods. Two of these combinations the Longstaff Schwartz method and the stochastic programming method have been applied recently to valuations in the mining industry in situations that are analogous to those faced by the upstream petroleum industry.
In this paper, we show how the Longstaff-Schwartz method, as adapted for use in a mining context, may be applied to the analysis of decision-making and value in the development of a bitumen deposit in Alberta using steam injection, where the underlying uncertainties are price movements in the bitumen produced and the natural gas used to produce the steam, and technological and geological uncertainties in the production and cost profiles. The analysis is complicated by the fiscal regime that brings to bear at each time the past price history through a particular form of ring-fenced resource rent royalty.
Coupling EOS Compositional and Surfactant Models in a Fully Implicit Parallel Reservoir Simulator Using EACN Concept
Authors: Han C. , Delshad M. , Pope G. A. , Sepehrnoori K. 
Published: December 2007

Abstract
EOS compositional and surfactant models are coupled in a fully implicit parallel reservoir simulator using Equivalent Alkane Carbon Number (EACN) of oleic phase. The EACN of the oleic phase is computed using a mole-fraction-weighted carbon number for each component present in the oleic phase. Important microemulsion properties such as optimum salinity and optimum solubilization parameter as a function of EACN of oleic phase are implemented based on known correlations. The simulator developed is validated using our IMPEC chemical flooding simulator, UTCHEM. Case studies including a large-scale simulation emphasize that surfactant floods should be carefully modeled taking EACN of crude oil into consideration for more realistic and accurate oil recovery predictions.
World's First Gravel-Packed Uniform Inflow Control Completion
Authors: Augustine J. , Mathis S. , Nguyen H. , Gann C. , Gill J. 
Published: December 2007

Abstract
The Etame oil field, offshore Gabon, West Africa, has been producing since September 2002. The Etame oil reservoir is an oval-shaped, low-relief structure with a moderate aquifer drive. In order to maximize ultimate field recovery, the ET- 6H well was drilled with a horizontal lateral positioned to traverse the reservoir near the structural crest and to be within the Upper Gamba sandstone throughout its length. The Gamba sandstone averages 45 ft in thickness and overlies a significant angular unconformity. The subcropping Dentale- aged sandstones and interbedded shales below this unconformity have dips up to 12 degrees. The oil column of approximately 170 ft extends below this unconformity. Previous wells in the field were completed using open-hole horizontal gravel packs (OHGPs) and have experienced excellent sand control performance. However, OHGPs offer no protection against early water breakthrough. The Gamba sand averages 30% porosity with a permeability range of 1 to 3 darcies. The Dentale sands are much more variable, with porosities of 18-30% and a permeability range of 50-1000 md. Thus, if a portion of the lateral is situated immediately above a high permeability Dentale sand, the well will be at risk of early water breakthrough and subsequent reduced recovery if it is completed with a standard OHGP.
The operator gravel packed the ET-6H well and used a system that provides a near uniform inflow profile along the entire lateral length to protect against early water breakthrough. The gravel packing of inflow control devices presented some unique challenges due to their differences from standard sand control screens.
This paper describes the implementation of the world's first gravel packed uniform inflow control completion, including: inflow control device selection process, gravel pack design, data from the gravel pack operation, and resulting well performance.
Deepwater Completion Challenges Redefine Best Practices for Completion and Packer Fluid Selection
Authors: Javora P. H. , Stevens R. , Devine C. , Jeu S. , Simmons M. , Firmin G. , Poole G. , Franklin B. , Qu Q. 
Published: December 2007

Abstract
New materials used in deepwater production tubulars, and the increasingly complex and costly deepwater projects, demand greater attention to the design and selection of completion and packer fluids. This requires an integrated approach, from mud displacement through final sand control completion, in order to optimize fluid compatibility and effectiveness. In addition to standard compatibilities with reservoir rock and fluid, compatibilities of completion or packer fluid with control line, stimulation, and production fluids must be considered. Furthermore, compatibility of completion and packer fluids with production tubular metallurgies must be assured in order to prevent environmental cracking. The impact of the production environment on the potential formation of gas hydrates or crystallization of brine due to pressure, at the near- freezing mudline temperatures, must be understood for each of the wellbore fluids used during the completion process. For some projects, more than one completion or packer fluid choice is available, in which case each fluid should be evaluated to select the best ‘fit-for-purpose’ fluid.
This paper presents a new paradigm for testing and evaluating completion and packer fluids for selection in deepwater applications. Details for each test procedure and evaluation method are presented and include completion or packer fluid compatibilities with formation or synthetic formation water, control line fluids, and produced fluids. Core flow studies used to test fluid compatibility with the formation rock, and standard stress-cracking tests, conducted according to NACE guidelines, used to avoid the potential for environmentally assisted cracking of chrome production tubulars, are presented. Specialized evaluation methods to avoid the formation of gas hydrates and the pressure crystallization of completion and packer fluids are also presented. The best fit- for-purpose fluid was selected by following this new paradigm for a GOM deepwater project. Lessons learned are summarized in the paper.
Hybrid Simulation Using Neural Networks To Predict Drilling Hydraulics in Real Time
Authors: Fruhwirth R. K. , Thonhauser G. , Mathis W. 
Published: December 2007

Abstract
Prediction of hydraulic pressure for drilling operations is of essential interest, e.g. for well planning before and decision support while drilling. Until now numerous analytical models were developed but due to the lack of knowledge about important boundary conditions like in-situ mud rheology, well geometry and pipe roughness these models typically show limited success. The proposed method merges (existing) analytical models with knowledge based models utilizing drilling data. The model preference is thereby based on a range of statistical properties of the data. Neural networks are used to build a hybrid simulation trained and improved using historical data.
Prior to building such hybrid models it is important to get informative data sets. Automatic operations recognition enables an efficient selection of the drilling operations in all the recorded data. To remove noise and redundant information the data is filtered and re-sampled by sophisticated digital signal processing (DSP) techniques. The original sensor data from the past is not the only data source. Descriptive features are derived to achieve independence from specific well data, like drill string configuration, mud type and well trajectory.
For building the hybrid models novel neural network architecture is used in combination with parallel learning to avoid trapping into local error minima. In addition automatic network growing and highly sophisticated stopping criterions offer a robust and efficient estimation of the optimal network. Since a model for "normal" drilling is desired for automatic identification of "abnormal" drilling conditions in real time, data associated to abnormal drilling situations is excluded from network training. A sensitivity analysis provides a ranking about the impact of the particular model input onto the final results enabling us to remove unnecessary data and features.
Uses and Misuses of Pressure Data for Reserve Estimation
Authors: McLaughlin J. , Gouge B. 
Published: December 2007

Abstract
Pressure data can be a critical component of a reserve estimate. This data can come in many forms including: Pore pressure data captured prior to a well's completionEstimated pore pressure taken during completionDrawdown data collected during productionPressure buildup data collected with a bottomhole pressure gauge.
Each of these data sources requires its own analysis and quality check techniques. With the appropriate supporting geological and engineering data, pressure measurements and analysis of sufficient quality can potentially provide evidence for fluid contacts, reservoir continuity, rock properties, original hydrocarbons in place, and reservoir geometry.
Often the Securities and Exchange Commission (SEC) and of the Society of Petroleum Engineers / World Petroleum Congress (SPE/WPC) definition requirements for "certainty", "reasonable certainty", and "known accumulations" disqualify some pressure interpretation methods for particular reserve estimation uses. This paper highlights some of the common pressure analysis applications that are not recognized by one or both of the reserve standards. Also presented are some applications that have been sanctioned for select reserve estimation applications.
As can be expected for such a broad topic as pressure data, many issues are not black-and-white. In these cases, this paper outlines some of the critical concerns to be considered when evaluating a pressure analysis application for assigning reserves under SEC or SPE/WPC guidelines.
Capillary Wicking in Gas Wells
Authors: Mahadevan J. , Sharma M. M. , Yortsos Y. C. 
Published: December 2007

Abstract
Gas expansion near the wellbore during production causes the evaporation of connate water. When the reservoir permeability is low, capillarity is controlling, causing liquid movement to the near-wellbore region where drying rates are higher. In tight gas sands or in shale gas formations, where capillarity is high, the gas production itself can cause depletion of the water saturation below residual values, due to such evaporation.
In this work we present a study of the fundamental processes involved during the flow of a gas in a liquid-saturated porous medium. We have modeled evaporation by accounting for the capillary driven film flow or ‘wicking’ of saline liquid to the wellbore or the near-fracture region and the effect of gas expansion. It is shown that, for gas reservoirs with connate water saturation, large pressure drawdowns lead to a drying front that develops at the formation face and propagates into the reservoir. When pressure drops are lower, water rapidly redistributes due to capillarity-induced movement of liquid from high-to low-saturation regions. This phase redistribution causes higher drying rates near the wellbore.
The results show, for the first time, the effect of both capillarity-induced film flow and gas compressibility on the rate of drying in gas wells. The model can be used to help maximize gas production under conditions such as waterblocking by optimizing the operating conditions.Additionally it can be used to obtain a better understanding of the impact of capillarity on evaporation and consequent processes, such as salt precipitation.
Use of Reservoir Formation Failure and Sanding Prediction Analysis for Viable Well-Construction and Completion-Design Options
Authors: Fuh G. -F. , Ramshaw I. , Freedman K. , Abdelmalek N. , Morita N. 
Published: December 2007

Abstract
Using two field case examples, this paper presents our current well construction and completion design analysis based on the following approach: (1) carry out detailed evaluation or determination of reservoir formation strength distribution using core testing, log data and drilling data analysis for rock strength estimate and its correlation with core testing results; (2) conduct a series of triaxial tests on selected reservoir core samples in the low to intermediate strength range for defining the stress-strain relationship (or material laws), rock failure and yield criteria, and other non-linear rock parameters required for numerical modeling analysis; (3) perform a series of formation failure and sanding potential analysis for a variety of possible well completion design scenarios using 3-D finite element technique for rock structure coupled with well production and fluid flow simulation. The types of completion design analyzed include cased hole completion using conventional perforations or stress-oriented perforations in inclined or high-angle well, openhole completion in high-angle or horizontal well, screen failure analysis in openhole completion, etc. In addition to investigating the mechanical response of the rock formations in each completion design, the model simulates both well drawdown and reservoir depletion effects on sand failure potential throughout the reservoir life. The results of such systematic study provide useful guidelines on well design and completion strategy for sand control or sand management in order to optimize well productivity. The two case examples presented in this paper highlight the use of this technique and approach. We have used this type of analysis and process for the well design in our business operations around the world with good success.
Based on our case example analyses and the specific rock failure characteristics as defined in the laboratory testing results and subsequent numerical simulations of sanding behavior, we are able to identify the most viable well construction and completion design for achieving a superior well deliverability and productivity for the long term, minimizing problems due to unintended solid influx and/or loss of well integrity over the reservoir life. The two field case examples in the North Sea as presented demonstrate and highlight the fundamental concept, methodology and the procedures for conducting the well design analysis through a series of computer simulations of various options for well completion schemes. The field example results will also show the effective use of rock failure characteristics by the engineers for the control of critical flowing bottom-hole pressure in relation to the reservoir drawdown and depletion to avoid premature sand failures during well production.
Preparing a Business Case for Technology Investment in Production Operations
Authors: Hite J. R. , Farid K. , Blanton M. L. , Gard F. , Crawley C. , Menda D. B.H. , Dotterer R. A. , Saputelli L. , Deaton D. F. , Sankaran S. 
Published: December 2007

Abstract
This paper describes the principles for preparing a convincing business case. The focus is on technology investments in production operations.
There seems to be wide-spread support in most large organizations for the implementation of new technology. The challenge is in speaking to decision makers in a clear and convincing manner. A good business case describes clearly what the investment is, what the risks are, and what the expected benefits are.
Analytical Solution for Injection-Falloff-Production Test
Authors: Chen Shi , Li Gaoming , Reynolds A. C. 
Published: December 2007

Abstract
A novel well-test for in situ estimation of relative per-meabilities was recently proposed. This test consists of three periods, (i) injection of water into an oil reservoir, (ii) a falloff test and (iii) a producing period. The pro-ducing period is critical as it yields production data that reflects changes in sandface mobility and is thus highly sensitive to the parameters used to model relative permeability curves. A major shortcoming of the data analysis procedure proposed in previous work was that it required a numerical reservoir simulator for matching pressure data. In this work, based on Buckley-Leverett theory and ideas from a front tracking method, we derive an approximate analytical solution for the pressure response during an injection/falloff/production test (IFPT) by applying on the Thompson-Reynolds steady-state theory. By matching data to the analytical solution by minimization of a weighted least squares objective function, we generate estimates of absolute permeability, relative permeabilities and the well skin factor. We show the method can be applied with either power law models or B-splines.
Factors Affecting Horizontal Well Gravel-Pack Efficiency
Authors: Ojo K. P. , Osisanya S. O. , Ayeni K. B. 
Published: December 2007

Abstract
Four major factors affecting horizontal well gravel pack were studied using a 3-D simulator developed for horizontal well gravel packing. The factors include settling effect, gravel concentration, injection rate, and carrier fluid viscosity. The gravel pack process was simulated and the effectiveness and pack efficiency of the gravel pack job is determined using the simulator. The effect of carrier fluid viscosity on gravel-pack efficiency was studied by varying the viscosity between 1 and 51 cp, injection rate between 1 and 4 barrel per minute, and gravel concentration between 0.50 and 4.0 pound mass per gallon. These three factors affect the settling factor of the gravel as it enters the horizontal section which subsequently affects the pack effciciency of the gravel pack process.
Maximizing Production Capacity Using Intelligent-Well Systems in a Deepwater, West-Africa Field
Authors: Goggin D. J. , Ovuede M. A. , Liu N. , Ozdogan U. , Coleman P. B. , Meinert D. P. , Nygard I. , Gontijo J. 
Published: December 2007

Abstract
Large, deepwater fields with a limited number of wells may require intelligent well systems to maximize production capacity under facility constraints. Agbami field, a highly-dipping reservoir with many producing zones and few wells, will use intelligent well systems to manage fluid fronts in a gravity-stable recovery scheme.
The reservoir has many producing zones with high-quality rock properties. Intelligent well systems, which consist of interval control valves (ICVs) and many sensors, will be used to monitor, analyze, and control (MAC) injection and production at the zonal level. Analysis of sensor data will allow operations to estimate well capacity and calculate actual flow rates. Decisions for operational control will be made based on the data analysis, the results of which will be used to optimize overall field performance and maximize financial returns.
In this study, a strategy was developed to maximize Agbami's full-field rate capacity in three production phases; ramp-up, plateau, and decline. Rate capacity response was investigated at the field, well, and zonal levels, including operational and reservoir uncertainties; e.g., injector plugging, well downtime, permeability variation, and fault-seal settings. Using a combination of scenario-testing and mitigation strategies, several key decisions were made, including the number and placement location of ICVs based on well type, range of production and injection rates, and zonal allocation.
Operating in the Shadow of a Megalopolis
Authors: Dudics D. D. , Arsenault L. 
Published: December 2007

Abstract
Webster's New College Dictionary defines a Megalopolis as: "A region composed of several large cities and their suburbs in sufficient close proximity to be considered a single urban complex". To say that Los Angeles and Long Beach, California make up a single urban complex would be making an understatement. Twelve-million people living eyeball-to-eyeball are less like an urban complex and more like an urban nightmare, especially when one is caught up in the morning or evening commute. Shear numbers aside, the region's weather, beaches and amenities still draw newcomers who want to live the LA lifestyle.
Within earshot of the beaches, marinas and pleasure boats in Long Beach Harbor the Thums Long Beach Company (THUMS) has produced oil for over forty years. A key to operating successfully in such an environmentally sensitive area has been the company's two-fold approach to managing stakeholder relations. First and foremost, focus on the community. Second, and almost as equally important, communicate, communicate and communicate.
Oil was first discovered in Long Beach Harbor in the 1930's. The vast Wilmington Oil Field (4th largest in the Continental U.S.) runs along the Southern California coast from just offshore Seal Beach to just under Redondo Beach, 12 miles to the north. Original oil in place is estimated to be 3.1 billion barrels. To date, almost a 1 billion barrels have been produced.