bluuebunny/crossref_metadata_2025_split huggingface dataset:
Performances of Openhole Completed and Cased Horizontal/Undulating Wells in Thin-Bedded, Tight Sand Gas Reservoirs
Authors: Göktas B. , Ertekin T. 
Published: December 2007

Abstract
With the recent advancements in drilling technology, drilling undulating wells, which specifically target various zones in a reservoir, has become a rather routine application. In accordance, drilling engineers are able to steer the well to coincide with pre-established sinusoidal trajectories. This advancement in drilling practices calls for the enhancement of our understanding of the production characteristics of undulating wells. This paper provides an in-depth comparative analysis of production performances of open-hole completed and cased horizontal/sinusoidal wells.
Horizontal wells offer great advantages in thin-layered, tight sand gas reservoirs as they increase the productivity through a larger contact area with formations. In this study, a comprehensive performance comparison of open-hole vs. perforated horizontal wells in thin, tight sand gas reservoirs is presented. This is accomplished using a 3-D, single-phase flow model, which is capable of accommodating vertical, horizontal, undulating, perforated, and fractured wells. Effects of drilling damage and crushed zones are considered in the simulations. The parametric study presented in this paper includes various phase angles, shot densities, perforation lengths, and number of fractures. Additionally, the study considers effects of uneven perforation lengths on the topology of the flow fields generated around the perforations. The flow performance comparison is further extended to undulating wells in thin-layered, tight sand gas reservoirs with shale streaks. In the presence of shale streaks, it is observed that undulating wells, which penetrate individual isolated layers, perform more effectively than horizontal wells.
Use of Prior Information in Gradient-Based History-Matching
Authors: Brun Bertrand , Gosselin Olivier , Barker John W. 
Published: December 2007

Abstract
This paper demonstrates how certain geological constraints can be imposed during gradient-based history matching by use of a prior term in the objective function. We extend an existing method of parameter selection (gradzone analysis) to the case where the prior covariance matrix is non-diagonal. We show that the parameter selection can be made independently of the weight assigned to the prior information, and illustrate how the shape of the gradzones is modified to re ect the correlation structure of the porosity or permeability fields. Finally, the use of the prior term to preserve a relationship between porosity and permeability during the history-matching process is demonstrated.
A Successful Case On Environmental Permit
Authors: Fontanelli G. F. 
Published: December 2007

Abstract
In Brazil, gas and oil exploration and production (E&P) is ruled by environmental laws that do not meet its characteristics of integrated and sequential development of its activities. Thus, every well drilling, for instance, must be licensed. On the other hand, there are mechanisms predicted in general and basic laws by which the industries may have easier ways to get environmental permits, taking into consideration the activity types. Unfortunately, this has not been observed by environmental control agencies, by this way becoming the issue ‘environmental permits in Brazil’ hard and ‘heavy’.
In 1998, E&P in State of Espírito Santo (called in this paper as Company), Brazil, got success in dealing with the state environmental agency (EA) about validity conditions of a future permit. The new permit, issued by the end of 1998, comprises Company's usual onshore E&P activities, and determines that they could be developed without individual (site) permits.
This paper shows, via case study, how the agreement was established and how the negotiations between Company and the government EA were carried out. This agreement ended in a global E&P permit that allows usual E&P activities be started regardless of government formal approval, provided EA be communicated 30 or 60 days before the beginning of the activity. After this lack of time, the activity can be developed. The activities are in general well drilling, seismic survey, oil and gas production and increasing of oil and gas pipeline capacities.
The main conclusion that comes from this paper is that an enterprise should use strict ethical principles when talking to an EA. This results in a relationship of confidence between the parts, and occasional difficulties that usually appear in this kind of process are more easily solved.
Feasibility 0f Monitoring CO2 Sequestration in a Mature Oil Field Using Time-Lapse Seismic Analysis
Authors: Fanchi John R. 
Published: December 2007

Abstract
A goal of CO2 sequestration is to provide economically competitive and environmentally safe options to offset projected growth in baseline emissions of greenhouse gases. The sequestration of CO2 in subsurface formations is a gas storage process. Among the issues that must be considered in a gas storage project are verification of injected gas inventory and monitoring of injected gas migration. This paper uses an integrated flow model to assess the feasibility of monitoring CO2 sequestration in a mature oil field using time-lapse seismic analysis.
New Developments in Aerated Mud Hydraulics for Drilling in Inclined Wells
Authors: Sunthankar A. A. , Kuru E. , Miska S. , Kamp A. 
Published: December 2007

Abstract
When drilling with aerated drilling fluids, bottomhole pressure is a strong function of gas-liquid flow patterns. The existing methods of predicting flow patterns are mostly based on the extrapolation of results from pipe flow to flow in annuli. Due to non-linear relationships between flow rate, pipe size and pressure drop, this practice may not be appropriate to apply in drilling operations. Therefore, in order to verify the applicability of the existing practice, the present study focuses on the flow of aerated drilling fluids through an inclined annulus, typical for drilling operations in directional wells.
Extensive experiments were performed in a unique fieldscale low-pressure flow loop (8 in × 4.5 in annular geometry, 90 ft long) in inclined positions (15°, 45° from vertical) with (100 rpm) and without drillpipe rotation. The liquids used were water and aqueous polymer solution (CMC+XCD+water), at flow rates in the range of 100–360 gpm and air in the range of 8–85 scfm (for 15°) and 250–1150 scfm (for 45°). Gas/liquid ratios were chosen so as to simulate similar gas/liquid ratios under downhole conditions, correcting for the fact that the actual pressure in the flow loop was much lower than the bottomhole conditions. Measurements of pressure drop and average liquid holdup over the entire annular section were carried out. To our knowledge, no such data has been published before.
The two-phase flow patterns were identified by visual observations. Bubbly flow and the slug flow are the two flow patterns observed over the ranges of the chosen test matrix. The presence of slug flow does not justify many of the existing simulation practices, which assume homogeneous gas-liquid flow.
Also, the flow pattern boundaries proved to be shifted as compared to pipe flow. The transition between bubbly flow and slug flow (for 15° inclination) was observed at a void fraction of 0.32 as compared to that reported for pipe flow (0.25). On the contrary, for air-aqueous polymer fluid flow, it was the same as for air-water pipe flow (0.25). For flow with drillpipe rotation, churn flow was observed instead of slug flow due to the churning of slugs by the rotating drillpipe.
While there was no significant effect of drillpipe rotation on the pressure drop for air-water flow, the pressure drop decreased in case of air-aqueous polymer fluid flow with drillpipe rotation. A higher pressure drop was observed in case of air-aqueous polymer fluid flow as compared to air-water flow.
An existing unified pipe flow model1 was modified based on the experimental results and was also evaluated against experimental and field data. The comparison shows that the pressure drop prediction by the modified model for inclined wells is better than some other existing models, though it still under-predicts the experimental pressure drop measurements.
Slickline-Deployed Electro-Mechanical Intervention System, a Cost-Effective Alternative to Traditional Cased-Hole Services
Authors: Foster Jerry , Clemens Jack , Moore Darrell 
Published: December 2007

Abstract
During the '90s, the introduction of battery powered electromechanical intervention tools increased the versatility of slickline service and changed its image from a simple method that performed mechanical workovers to a complex service technology that could provide safe, cost-efficient alternatives for: locating downhole tubular goods/profilesproducing quality logs from downhole memory surveys at half the cost of traditional servicesaccurate depth measurement for support of all new completion technologiessetting packers without explosivesperforating or cutting tubing or casing.
Slickline has again expanded its capabilities. In addition to its proven performance for well remediation, maintenance, and pressure control applications, the new enhancements to the self-powered slickline tools can now be used to perform diagnostic and conformance control functions requiring memory production logging.
Applications that require electrical initiation or mechanical manipulation at the tool interface can now be performed with slickline and battery power, insulating the tools from the surface equipment. Mechanical signals transmitted through the wire control the tool start and stop functions and provide real time position telemetry. As a result of the advances in service tools, slickline has increased the scope of its services without a compromise to operational safety and job efficiency and offers the most cost efficient services in well workovers.
The case histories will describe how the electromechanical intervention tools provide a cost-effective alternative to traditional cased-hole logging systems for many applications as well as many operations that traditionally had to be performed by other service options.
Production Response From Southeastern New Mexico Morrow Wells Stimulated with Binary Foams
Authors: Walser D. W. , Gerstner M. J. 
Published: December 2007

Abstract
For many years, local industry consensus and various authors1,2,3 have concluded that with few exceptions4, fracture-stimulation of the Morrow sand series in southeastern New Mexico is best undertaken utilizing fluids containing [at least] CO2, KCl, and methanol. Unfortunately, this conclusion originates from hearsay and limited studies that looked at only a few treatments. Difficulties with past efforts to verify and compare post-fracture well performance were centered on the inability to database naturally-occurring parameters for the majority of wells, as well as problems stemming from inaccurate and erroneous public data.
Localized successes with foams containing CO2, KCl, nitrogen, and methanol prompted a more comprehensive study of the area that attempted to address the problems associated with the evaluation of public production data.
A Graphical Information System5 was coupled with publicly available production data and internal pumping service company records6 to attempt to determine if one completion methodology was really any better than another. Production from wells treated with Binary foams over a four-year period (1996 – 1999) was compared to production from up to 19 offsets per well of interest. A set of relatively rigid criteria was set up and followed to ensure that the study was as objective as possible, given the constraints of working with public data. Although it was not possible to "normalize" the wells of interest or their offsets to account for differences in natural parameters, the large number of wells examined provided some degree of confidence in the validity of the process.
Conclusions are presented. The average first 90-day cumulative production from wells treated with Binary foam was higher than the average of wells that were stimulated with other systems. Evidence is also presented to suggest that it may be prudent to fracture-stimulate wells with high initial natural production.
An Innovative All Electric Well Production System
Authors: Rivenbark Mark , Khater Sami , Dietz Wesley , Steven Barnes 
Published: December 2007

Abstract
A major operator in the Middle East has been producing gas from the same formation for approximately 20 years. Traditionally, hydraulic actuators have been used to control the wellhead gate valves in these gas wells. These actuators have been operated from a hydraulic control panel that is pneumatically powered, and the compressors used to generate the instrument air are electrically driven. The existing systems have not only been inefficient, as they required electricity to power the hydraulic actuators, but they were also very maintenance intensive.
When the decision was made to begin a 5-year drilling program to develop additional gas reserves, an important part of the project development process was the investigation of alternatives to existing wellsite equipment. A unique system in which the gate-valve actuators, the control panel with a PLC as well as the pressure pilots, fusible plugs and ESD switches were electrically controlled, was chosen for testing. The system also incorporates a battery back up to maintain operation in the event of a power failure.
This paper will discuss the system and the testing program developed to assess its capabilities as well as the testing that was required to comply with other industry mandated testing. The paper will also delve into other ongoing projects using this technology and highlight the superiority of an electric system over more conventional hydraulic or pneumatic systems. For the project discussed in this paper, an existing well was converted to the all electric system, and a rigorous one year testing program was carried out by the operator. In addition to normal exposure to the elements and routine opening and closing of the well to meet production demands,
the test also included over 300 additional open and close cycles on each of the three electric actuators on the tree.
The operator estimates capital cost savings for the all electric system in excess of $200,000 per well over the present pneumatic/hydraulic systems. Additional savings would also be generated in the future from the manpower reductions planned when the system was fully proven. Finally, a reduction in maintenance would also impact operational costs.
In a recent analysis of the system capabilities to date, the operator specifically noted the following benefits: The operators were able to handle their duties much more easily since the system is all push button.The self-diagnostic features built into the panel allow quick troubleshooting of the system rather than requiring assessment of problems through trial and error.The maintenance record to date has shown that minimal maintenance has been required.
The results of this project have also shown that other potential applications such as unmanned platforms and pipelines could benefit from this all-electric system.
Automated Chemical Control of H2S Content of Natural Gas
Authors: Roth Dane , White Bob , Benavides Danny , Lame Charles , Arreola Rosendo 
Published: December 2007

Abstract
This paper introduces a new field application for the automation of hydrogen sulfide chemical scavenger injection systems in natural gas pipelines. The automated system combines currently available technology into a cost saving tool that has proven itself reliable in maintaining the level of hydrogen sulfide needed for contract gas sales. The benefits that an automated system provides are multi-faceted. These benefits are shown in the savings of man-hours, safety, and chemical usage optimization. Eliminating the need for intermittent checks of the hydrogen sulfide level and chemical pump adjustments saves employee time. Safety is improved due to the fact that the employee does not have to manually check the hydrogen sulfide level, thus not opening valves that would release natural gas containing hydrogen sulfide. The automated system also optimizes chemical usage by continually monitoring the system and maintaining the hydrogen sulfide content at the level needed for gas sales. The content of hydrogen sulfide in a natural gas gathering system is a dynamic and continually changing system due to several factors, i.e. new wells brought online, wells being shut in for various reasons, and the changing hydrogen sulfide level in individual wells. This system will automatically adjust for these continuous variations and lead to significant savings in hydrogen sulfide scavenger chemical applications.
Experience of Collecting Daily Production Data Using Handheld Devices and the Internet
Authors: Boone Douglas M. 
Published: December 2007

Abstract
This paper describes the experience of working with over a dozen companies in the design and implementation of a web-based field data collection system. Daily well, tank, and meter readings are entered in the field using a handheld computer in place of paper gauge sheets. The data is transmitted electronically to a database server on the Internet. A touch-tone telephone offers an alternative means for data entry. Users can display and plot the data using a PC application that accesses the data across the Internet.
This paper will review the experience gained in the following areas: Field operations and system designHardware durability in the fieldInterfaces for pumpersAlternative data entry systemsCommunications in rural areasInternet database and engineering applicationsTraining and supportCost-benefit analysis
The Historical 20th Century and the Future 21st Century of Petroleum Engineering Professional Registration
Authors: Wines G. Bing 
Published: December 2007

Abstract
Professional recognition for the Petroleum Engineering profession began developing in the early 20th century1,2. Professional Registration for the Petroleum Engineer has seen some drastic changes since its implementation unto the national scene in 1907. Most of these changes occurred through the nationally administered National Council of Engineering and Land Surveyors (NCEES). The national Petroleum Engineering Professional Exam began in 1973 when NCEES started offering it to all states. The requirements to become registered gradually became stiffer. The advent of the Sunset Legislation fad in the 1980's really changed the state requirements. In 1973, the PE Exam began as a twenty problem offered, choose eight to work, objective style exam. By 1999, it had evolved to an eighty question, no choice, all multiple choice exam. As we enter the 21st century, computers will eventually administer the PE Exam.
Best Practices in the Preston Spraberry Unit
Authors: Long Scott W. , Smith Elton J. , Hoff Charlie R. , Garza Albert A. 
Published: December 2007

Abstract
During the last several years the Petroleum Industry has adopted the term "Best Practices" to describe an efficient method of producing oil and gas. The definition of this "method" is very subjective and is continually changing with acceptance of new improved and proven rod pumping knowledge. The best way to describe the term Best Practices is by using the phrase "Work in Progress" or "Continuous Improvement."
This paper describes and presents the implementation of a Best Practices program in the Preston Spraberry Unit located in West Texas. This accepted Best Practices program is presented as follows: Complete initial pumping well analysis.Matching lift operations to current producing rates by optimizing the following: plunger diameter, strokes per minute, stroke length, tubing anchor catcher, and downhole gas separation.Managing downhole rodstring buckling by re-evaluation of rodstring designs and installation of sinkerbars.Installing pump-off controllers to manage production rates, optimize run times and monitor equipment performance.Follow-up well-site diagnostic analyses after several months of operation to evaluate initial well analysis and original well work, and implement further modifications.
Due to the successful implementation of this Best Practices program, tubing leaks were reduced by 61%, rod part replacements were reduced by 35%, and pump repairs were reduced by 6% during the two-year test period.
Recognition and continued development of these successful Best Practices will provide the oil and gas industry with improved artificial lift guidelines. Implementation of these guidelines will allow for more effective use of all valuable resources to more efficiently produce oil and gas.
Enhanced Oil Recovery with Downhole Vibration Stimulation
Authors: Westermark R. V. , Brett J. F. , Maloney D. R. 
Published: December 2007

Abstract
The use of vibration to improve oil recovery has long been investigated. The background for this novel technology is reviewed along with the project rationalizations, designs considerations, and measurements performed in advance of a downhole vibration stimulation field test. This field demonstration will pilot test the potential of downhole vibration to enhance oil recovery from a shallow oilfield in Osage County, Oklahoma. The project is supported by the Department of Energy (DOE), Seismic Recovery LLC, Phillips Petroleum Co., and Grand Resources, Inc. Recent literature has reported successful vibration stimulation in shallow reservoirs with high water oil ratios (WOR). Osage County has, like many areas of the United States, numerous old fields under waterflood, with many wells producing marginal oil with substantial water production.
Two Methods for Achieving a Dual Gradient in Deepwater
Authors: Herrmann Robert P. , Shaughnessy John M. 
Published: December 2007

Abstract
The advantages of a dual gradient mud column have been well documented. Significant work has been done on the riserless drilling systems by several different companies. This paper will propose two methods to achieve the same dual gradient. Nitrogen Injection: Building from proven air drilling procedures and underbalanced techniques nitrogen can be used to cut the mud weight back in the riser above the seafloor or the cut can be made deeper by combination with a concentric riser.Floating Mud Cap: A dual activity rig can use a casing riser linked to the adjacent marine drilling riser. A submersible pump in the casing riser regulates returns that will set the mud cap level in the drilling riser. A pressure sensor in the subsea BOP allows monitoring the effective hydrostatic pressure. This approach again combines field proven procedures and hardware in the deepwater environment.
Both methods will be presented with emphasis on the hardware and operational procedures required to successfully implement them. Both of the methods employ existing equipment and procedures.
Advances in Expandable Tubing – A Case History
Authors: Ruggier Michael , Benzie Scott , Urselmann Rob , Mosser Henrik , van Noort Roger 
Published: December 2007

AbstractThe paper describes the world’s first use of expandable solid tubing to close off perforations. The development and testing of the system leading up to the two field installations is described with the execution and validation process.The fundamental concept of solid tubular expansion had been proven to be sound, but four main development hurdles needed to be overcome. Extensive innovation in design and material selection culminated in two main applications being fulfilled, with subsequent testing proving the absolute success of the technology. These first few steps pave the way to a number of existing commercial applications and our ultimate goal of mono-diameter wells.