bluuebunny/crossref_metadata_2025_split huggingface dataset:
Computer directed supervisory control and monitoring in Libya
Authors: Babinec M.E. 
Published: December 2007

Abstract
In early 1970, Oasis Oil Company of Libya put into operation a computer directed put into operation a computer directed Supervisory Control and Monitoring System for the company-operated power generation and distribution, pipeline, and oil production facilities within the Sirte Basin of the Libyan Arab Republic.
A single on-line computer has been installed at a site deep in the Sahara Desert to operate in conjunction with fourteen Satellite Stations, via the company-operated communications system, for control and monitoring of several producing oilfields, five mainline pump stations, ten gas turbine driven generators at four dispersed locations, and a 138 KV power transmission system.
The harsh desert environmental conditions coupled with temperature variations from 30 degrees F to 140 degrees F have presented formidable obstacles for the implementation of this system. The overall system operation, however, has been quite successful.
Details of this particular computer application including performance history and cost information, are given. Various aspects of system software, hardware configuration, input-output devices and the communication links are discussed. Salient design and implementation problem areas are also touched upon.

Introduction
Following a feasibility study, Oasis Oil. Company of Libya decided in December, 1966 to install a computer directed Supervisory Control and Monitoring System to improve coordination of the company's widely dispersed field operations. (See Exhibit I.) This system would centralize collection of basic operational data, monitor and report alarm conditions, and provide remote control of equipment. Besides wide dispersement, factors in favor of computer directed surveillance and control were expansion flexibility and relative ease of computer program modification to match field changes. program modification to match field changes. In March, 1969 the computer system went "on line" and began interrogation and control of the first of fourteen Satellite Stations. Implementation of the system was completed in October, 1971. Three new Satellite Stations were added to the system in January, 1972.
Formation Evaluation Parameters of the Rotliegendes Sandstone, North Sea Area
Authors: Fertl W.H. , Cavanaugh R.J. , Shepler J.C. , Cope B.G. 
Published: December 2007

Abstract
Over the past few years the Permian Rotliegendes Sandstone in the North Sea area has been established as a profilic and fascinating gasbearing formation. Realistic evaluation of major gas deposits accumulated in this reservoir rock requires an engineered use of well logging data and core interpretation on a comparative basis. Permeability relationship, data on cementation factor and saturation exponent, matrix grain density, rock compressibility, etc. are discussed on several field cases.

Introduction
Over the past several years the shelf region of the North Sea has developed into Europe's most promising offshore area of exploration for gas and oil. In rapid succession substantial gas reserves have been delineated especially in the southern region of the North Sea area. This is illustrated by figure 1 showing a generalized map of offshore operation in the North Sea area (Hark et.al., 1971). A corresponding schematic geological profile through the southern part of the British North Sea shelf profile through the southern part of the British North Sea shelf area is given in figure 2 (Hornabrook, 1967).
The so-called Rotliegendes sandstone, or Lower Permian age, has been established as a profilic gasbearing formation of major areal extent, covering large parts of both the North Sea and NW-Europe (Holland, Germany). A stratigraphic table of the North Sea area is given in figure 3 (Heybroek et.al., 1967).
Despite the fact that several hundred wells have been drilled in the North Sea, only limited data have been published on formation properties of the Rotliegendes. Our present discussion attempts to shed some light on our many observations and the problems one may face in evaluating reservoir characteristics problems one may face in evaluating reservoir characteristics of the Rotliegendes using well logging, core analysis, and other laboratory data.
Extended Reach Drilling: Managing Networking, Guidelines, and Lessons Learned
Authors: Judzis Arnis , Jardaneh Kamal , Bowes Colin 
Published: December 2007

Abstract
During the last two years, BP Exploration developed a plan to assure all aspects of Extended Reach Drilling (ERD) opportunities were understood by business units (Assets). A global network of personnel involved in both ERD operations and technology support pursued a structured approach to enhance ERD option selection, well planning, well construction, and performance measures. This led to a successful initiative to develop a comprehensive set of ERD "Guidelines". Experiences from operations worldwide are included in sections ranging from drilling fluids to stuck pipe prevention. The versatility of the Guidelines was in part attributed to its electronic distribution, available either through local network servers or through the company's intranet.
The ERD guidelines focus on well design, planning, and operations. For engineers in the Assets, the guidelines and information provide a basis for determining "what is possible". Well planning is an iterative process to determine the optimal mix of rig equipment, fluid and tubular requirements, drillstring design, and so on. The strategy behind the information in the Guidelines and the transfer of "best practices" by the BP Exploration ERD Network was to support an iterative process by which learning would take place and performance improved. Thus the Extended Reach Drilling Network has provided a method by which ERD achievements and lessons learned are consolidated, and the information necessary for Assets to identify opportunities are available.
Development of a One Piece Liner Hanger/Liner Top Packer/ Production Packer System for Monobore Wells in Alaska's Kuparuk River Field
Authors: Trantham J. A. , Anderson L. F. 
Published: December 2007

Abstract
To meet the need to reduce monobore tubingless injector completion cost, a combination device to hang a liner, seal the liner top, and perform completion packer function with a compact single unit has been developed. This combination system will improve the economic feasibility of the Kuparuk River Field monobore project in Alaska. This paper will describe the current system, discuss the benefit for a single trip completion, present test results, and discuss the running procedures of the single trip multipurpose packer.
Field Specific Analysis Reinforces Role of Bit Technology in Improving Overall Drilling Economics
Authors: Turner E. C. 
Published: December 2007

Abstract
An earlier macro-analysis of more than 100,000 bit records from around the world revealed that technological advancements in PDC bit design and application have contributed to a reduction in global cost per foot an average 35%, while roller cone bit performance improvements have resulted in an 8% drilling cost reduction on average. A new study of field specific bit performance and bit usage patterns further supports the results of the previous study by documenting at a micro level the impact of bit technology on drilling economics.
The impact of improvements in bit technology have significantly reduced drilling costs and increased overall drilling efficiency in both high-cost and low-cost drilling theaters worldwide. Technical advancements have improved both bit life and penetration rates.
World's First 4.5" Coiled Tubing Pipeline
Authors: El Laithy W.F. 
Published: December 2007

Abstract
Coiled tubing is rapidly growing pipeline technology. Utilization of coiled tubing as pipelines is new application to an existing technology. Until recently coiled tubing was used primarily by service companies for coiled tubing workovers. As the technology expanded the industry began using coiled tubing for other applications such as drilling, coring, logging, well clean out operations and artificial lift. As the tubing mills began production larger sizes, it became possible to consider using coiled tubing as pipelines. The application of coiled tubing as a pipeline began in the Gulf of Mexico. The early results supported the application as being a low cost, time saving, economic alternative to conventional welded pipe for flowlines. Coiled pipe applications have been used in 4 to 100 feet of water in the Gulf of Mexico area and the installation techniques have varied significantly.
In 1994, the Gulf of Suez Petroleum Company (GUPCO), a joint venture company between Amoco Production Co. and the Egyptian Petroleum Co. embarked on the first international application of the 3.5 inch coiled pipe using a dynamic lay procedure. The cost savings from the first two jobs were estimated to be in excess of 70% when compared to the traditional lay vessel charges. Engineering design and field experience was shared at the Middle East Oil Show (MEOS 95) in Bahrain during 1995 (SPE 29786). Subsequently Gupco has taken a leading role in the application of coiled pipe technology with the 1996 installations using the first production of 4.5 inch coiled pipe, one of which is a record setting 62,000 FT. high pressure water supply line. Cost savings of this larger diameter coiled pipe are still yielding 55% cost savings over the conventional barge lay techniques. This paper will cover the significant findings of that engineering work and present actual field case histories on Egypt's first 4.5 inch coiled pipeline projects.

Introduction
The Gulf of Suez Petroleum Company has been using coiled pipe technology since 1994. Since that time the technology has grown with larger diameters being offered. These larger pipes have enabled the company to examine additional opportunities in the Gulf.
To date the company has installed 45,000 feet of 3.5 inch and 72,000 feet of 4.5 inch coiled pipe. In 1994 GUPCO embarked on its first two coiled pipeline projects using the 3.5 inch material. By 1995 a new larger diameter coiled pipe was being offered. The 4.5 inch material offered additional application in the Gulf and GUPCO pursued three additional projects. P. 121^
99.9% Sulphur Recovery from H2S Containing Gas Streams
Authors: Savin S. , Nougayrede J. , Legendre O. , Nedez C. 
Published: December 2007

Abstract
Catalytic processes available today for the treatment of H2S containing gases in refineries and gas plants, are limited to an overall sulphur recovery performance that can't exceed 99.7 %. A new process is proposed to reach 99.9 % min. sulphur recoveries, based on the direct oxidation of H2S below sulphur dew point, using a new catalyst especially designed for this application. A first industrial experience is currently on stream.

Introduction
Reducing atmospheric pollution by SO2 has become a major environmental concern for natural gas and oil industries.
The so-called "modified Claus" process has known a wide-spread development for some decades, to recover more and more H2S from acid gas fields and crude oils by converting it into the more environmentally friendly sulphur, according to the following reaction sequences:
In the same time, steadily tightening regulations have nourished the parallel development of improved techniques to help to get the best of the Claus process by acting mainly in two fields:–catalyst developments, aimed at improving Claus as well as COS/CS2 hydrolysis reactions using advanced pure aluminas, increasing the life time of alumina-based catalysts downstream by oxygen scavenging, increasing the overall catalytic activity by introducing the performing titanium dioxide.–process developments, not only to improve the basic Claus sulphur recovery unit, but also to further process the Claus plant tail gas in order to get rid of the maximum of residual H2S.
Totally catalytic routes involving the most up to date catalysts from Sulphur Recovery Unit to Tail Gas Treatment make it possible today to industrially reach an overall sulphur recovery as high as - but not exceeding - 99.7%.
The 99.9 % sulphur recovery performance can be presently achieved only by implementing wet Tail Gas Treatment processes involving a solvent absorption step and subsequent recycling of H2S. Although efficient, these processes are highly expensive, both as regards capital investment and operating costs, and moreover, they generate liquid acid wastes to be treated.
It was decided to try to overcome these two disadvantages by reconsidering the approach of the 99.9% performance through a totally catalytic route. This challenge supposed to basically reconsider both process and catalyst philosophies.

1. Process
A significant breakthrough in tail gas treating was introduced in the 70's with the concept of operating below sulphur dew point. This combined two major advantages:–the enhancement of the formation of sulphur through immediate trapping within the catalyst porous network–the decrease of yield losses in the form of gaseous elemental sulphur.
This concept entails a cyclic operating mode, with the continuous succession of two sequences : an adsorption-reaction phase where the sulphur is formed and remains adsorbed within the catalyst, followed by a regeneration phase where the sulphur is expelled from the catalyst by heating up to 300 C, and recovered by condensing.
P. 233^
Air Toxic Emissions Characterization of Natural Gas Processing Plants
Authors: Ferry K. R. , Gundappa M. , LaCosse J. P. , Shareef G. S. , Johnson K. L. , McCarthy J. M. 
Published: December 2007

Abstract
The U.S. Environmental Protection Agency (EPA) is developing air toxic regulations for oil and natural gas production, with the proposed rule scheduled for promulgation in 1997. The EPA is also scheduled to promulgate air toxic regulations for industrial combustion sources by the year 2000. In addition, several states have air toxic regulatory initiatives that affect the gas industry. Because these regulations could have large economic and operational impacts on the gas industry, the Gas Research Institute (GRI) has initiated a multiphase research program. One of the objectives of this program is to determine potential sources of air toxic emissions in the natural gas industry, the quantities of air toxics emitted, and individual species emitted from typical equipment.
The primary objective of the testing conducted in this program at gas processing plants was to assess potential air toxic and criteria pollutant emissions associated with combustion equipment, including characterizing the following emission sources: internal combustion (IC) engines, gas turbines, incinerators, heaters, and boilers. The pollutant classes evaluated include aldehydes, criteria pollutants, volatile organic compounds, semi-volatile organic compounds, metals, and reduced sulfur compounds. In addition, unit operational data were obtained during testing. To date, eight field measurement campaigns have been conducted at natural gas pipeline and gas processing facilities. Three (3) of these campaigns involved testing at sour gas processing plants, while two (2) other campaigns focused on emission sources at sweet gas plants. The emission test results for these programs are summarized in this paper.
In addition to emissions characterization, the effects of maintenance and performance tuning on emission levels was investigated during one campaign. Results on emissions, efficiency, and cost impacts associated with maintenance and tuning activities conducted on three engines, two incinerators, and two process heaters are reported.
Pipeline and Related Issues
Authors: Lindsey Rhonda P. , Simmons Jerry R. 
Published: December 2007

Abstract
The McGrath Lake oil spill in Ventura County stimulated public concern regarding crude oil gathering pipeline safety. This December 22, 1993 incident occurred from a crude oil shipping line. This spill released an estimated 2,200 barrels (42 gallons = 1 barrel) of crude oil. This oil surfaced and flowed another 1,200 feet into McGrath Lake. The lake is part of a tidal wetland within a large coastal dune system.
One result of this incident was the passage of California Assembly Bill 3261 (O’Connell) as codified in California Government Code Section 51015.05 in 1994. This bill required the California State Fire Marshal (CSFM): establish and maintain centralized database containing specific information and data (pipeline locations, ownership, age, inspection history, etc.) regarding certain crude oil pipelines,conduct a study of the fitness and safety of these crude oil pipelines, andinvestigate incentive options that would encourage pipeline replacement or improvements, including, but not limited to, a review of existing regulatory, permit, and environmental impact report requirements and other existing public policies that could act as barriers to the replacement or improvement of these pipelines.
The following pipelines were included in the data base and study: pipelines for the transportation of crude oil that operate at gravity or at a stress level of 20% or less of the specified minimum yield strength of the pipe; and,pipelines for the transportation of petroleum (crude oil) in onshore gathering lines located in rural areas.
Production Business Planning to Maximize Field Potential
Authors: Ruble D. B. 
Published: December 2007

Abstract
Since 1992, Exxon Company USA’s New Orleans Production Organization has utilized a Business Planning Process to assist with maximizing field potential and improving profitability. The process, based upon Field Level Business Team planning, has allowed NOPO to more effectively identify, resource and implement business opportunities. This paper discusses and provides examples of the processes, tools and results from the Field Level Business Team structure and planning process. The results from the organization, assisted by the process, have been: increased volumes, identification of additional opportunities, &gt;100% reserve replacement, reduced unit expenses, increased profit and return on investment and a focus of our resources on the assets with the greatest potential.
A Simple Method for Estimating Well Productivity
Authors: Brooks James E. 
Published: December 2007

Abstract
We present a simple method for estimating the well productivity of a natural completion. The method gives quick, accurate estimates of productivity that agree well with established finite-element calculations. We show that three nondimensional groups - determined by the major governing parameters: penetration length, shot density, perforation tunnel diameter, permeability anisotropy, wellbore damage length and perforating damage - control most of the functional dependence of well productivity. One practical application of the method is in selecting the best perforating system from a suite of alternatives. The analysis is also useful in determining economical trade-offs between marginal increases in productivity and contemplated improvements in any of the perforating parameters (perforation length, shot density and tunnel diameter).

Introduction
Researchers have been devising various methods for estimating well productivity from a perforated formation for many years. Most methods assume that the flow in the permeable formation can be modeled by potential theory, that is, as a solution to Laplace's equation, subject to particular boundary conditions. An oft-quoted study is that of Tariq, who used a finite-element method to solve numerically the well flow over a wide range of perforating and formation parameters. These results were later reduced to a series of analytical approximations by Karakas and Tariq that now serve as the basis for two commercially available computer codes that are in common use today.
Although useful in estimating well productivity and in assessing trade-offs between different gun systems, the computer analyses sometimes tend to obscure insight to the relative importance of the various competing parameters. Nondimensional analysis can often be of great use in these situations by grouping together the most important parameters to reveal the underlining functional dependencies. And that is the purpose of this study.

Basis of the Method
The method assumes that the dominant variables determining productivity are: perforation length (P), shot density (N), diameter of the perforation tunnel (d), anisotropy or ratio of horizontal permeability to vertical permeability of the formation (a), diameter of the wellbore (D), length of local wellbore damage (L), and the damage caused by the perforating jet (bc). The method assumes that there is no appreciable difference in productivity caused by the phasing of the gun, as long as the perforations are distributed along a spiral pattern. Both the wellbore damage and the perforating damage (the local impairment to permeability caused by the perforating jet) are initially assumed to be zero. Later on, we show that these effects can also be included as part of the analysis.
Experimental Study on the Impact of Perforations on Hydraulic Fracture Tortuosity
Authors: van de Ketterij R. G. , de Pater C. J. 
Published: December 2007

Abstract
We performed scaled model tests to study the relation between completion and treatment parameters and the near wellbore geometry for highly deviated, cased perforated wellbores.
We have instrumented our casings to observe the moment fluid flow around the casing causes a significant increase in the amount of pressure acting on the wall of the borehole. When fluid flow around the liner occurs extensively before fracture initiation, this leads effectively to an open hole situation at the moment of initiation. Otherwise the perforations will be the only possible initiation sites.
In our experiments with a perforation phasing of 90° the perforations on top of the borehole acted in most cases as initiation sites. We performed stress calculations with a simple analytical model to understand the influence of the perforation angle on initiation pressure and fracture propagation.
Coiled Tubing Horizontal Underbalanced Drilling Project; Costs and Operational Analyses
Authors: Borbely L. , Brazier R. , Giddings C. , Cox R. 
Published: December 2007

Abstract
Coiled tubing drilling remains one of the fastest growing technologies in the drilling industry. As of year-end 1996 approximately 60 horizontal underbalanced wells have been drilled in Western Canada with coiled tubing. The benefits of this technology are intuitive, however there have been few opportunities to make direct comparisons to adjacent horizontal wells drilled with conventional techniques.
In 1996, Crestar Energy Inc. contracted Canadian Fracmaster Ltd. to drill 5 horizontal underbalanced wells in Southeast Alberta. The drilling of these wells provided opportunity for project analysis of operational factors and costs. This paper presents the results of the five wells drilled, analyzes time breakdowns for key operational steps. Cost comparisons of these wells with similar conventional overbalanced wells and initial reservoir productivity will also be assessed.