bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Comparison of Stimulation Treatments in the Deep Anadarko and Deep Delaware Basins
Authors: Barrett N.D. , Thompson J.C. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The Delaware Basin of West Texas and the Anadarko Basin of Western Oklahoma and the Texas Panhandle are currently the most active areas in the United States insofar as development of ultra deep formations is concerned. Nearly all of these deep formations in both areas require stimulation to be commercially productive. While some of the formations in productive. While some of the formations in the two areas appear to respond similarly to laboratory tests, different stimulation treatments have evolved. Although fracture acidizing is common to both areas, the types and concentrations of acid and techniques of application vary greatly. Since effective stimulation is obtained in both areas, it was felt that a comparison of factors involved in treatment design, the treatments themselves, and the results obtained might lead to some common factors that would be useful in design of more economical and effective stimulation treatments for all ultra deep formations. This paper presents these comparisons for the Delaware and Anadarko Basins. An analysis of these comparisons attempts to explain the reason for variations in treatment design in some instances and to show why one type, or even a modification between the two, might be better in other instances. The paper also presents some of the basic considerations presents some of the basic considerations involved in stimulation of all ultra deep formations.

Introduction
The Delaware Basin of West Texas (Fig. 1) and the Anadarko Basin of Western Oklahoma and the Texas Panhandle (Fig. 2) are both active in development of ultra-deep (18,000–25,000) formations. Target sands in the Delaware Basin may be the Wolfcamp, Morrow, Devonian, Frisselman or Ellenburger, while primary targets in the Anadarko Basin may be either the Morrow or Hunton. The deepest of the targets in each basin, the Ellenburger and the Hunton, are similar in many respects. Both are massive sections with narrow zones of porosity development. The Ellenburger is a highly soluble dolomite while the Hunton is an even more soluble limestone. The zones of porosity development in the Hunton, however, are dolomitic. Depths, bottom-hole temperatures, porosities and permeabilities of the two porosities and permeabilities of the two formations are roughly equivalent as shown in the generalized comparison in Table 1.
Rod-Pumping Optimization Through Surface and Downhole Parameter Estimation and Simulation
Authors: Vázquez M. , Fernandes J. 
Published: December 2007

AbstractParameter Estimation and simulation techniques, in real time, make easy to infer instantaneous values of rod-pumping variables. In order to maximize production, minimize operating costs and extent useful life of the equipment; monitoring, control and automation have to be included in any new completion task. In Rod Pumping Systems there are analytical tools, which allow diagnosing the well behavior, being the most representative the Dynagraph Charts (surface and downhole). In this work, a mathematical model infering the Surface Dynagraph Chart (S.D.C.) based on Motor Power Consumption, Pumping Unit Geometry and Torque Analysis considering inertia effects is developed and used in conjunction with a characteristics model wave equation to estimate the Downhole Dynagraph Chart (D.D.C.). Dynagraph Charts, Surface Temperature and Surface Pressure (Tubing Head Pressure) logging are interpreted (using well design and completion information) in order to analyze, diagnose the state of the well and finally a recommendation is issued, bringing as a result a field action. Generally, these actions are based on Strokes per Minute S.P.M control of the well and this can be done in an automatic way (through Variable Speed Drivers V.S.D.), closing the Control Loop. With this optimization scheme a constant monitoring of each of the field wells is carried out and the wells are kept at optima operational levels. These models were tested successfully in three oil production fields, around 60 wells.
A New Method for Controlling Incompetent Sands
Authors: Henderson J.K. , Sallee W.L. , Stout C.M. 
Published: December 2007

Abstract
A new approach to the persistent problem of unconsolidated sands, has been the development and use of plastic coated walnut shells. Laboratory data, supplemented by results from initial field treatments, indicate that this method has furnished satisfactory sand control, without production losses. In fact, in a number of cases, stimulation of production has been obtained.
In general, the treatment consists of injecting a graded solid into a producing formation under elevated hydraulic pressure. Specifically, the injected solid consists of ground walnut shells (usually 20 to 30 mesh in size) coated with unset plastic, and carried into the formation by means of an oil-type carrier fluid. Once the plastic coated shells are in place around the outside of the casing, the plastic is allowed to set up, consolidating the walnut shells into a permeable screen, and preventing the influx of unconsolidated sand during subsequent production of the well.
In some applications, due to special formation requirements, a spearhead of sand has been injected into the formation ahead of the plastic coated walnut shells. This reduces the possibility of fine, ungraded formation sands plugging the openings in the plastic/walnut shell screen.
Advantages of this method include: ease of application; benefits to production; use in dual completion; elimination of costly fishing operations required in removing conventional screens.
Steels For Drill Pipe, Tool Joints And Drill Collars
Authors: Marsee Jack 
Published: December 2007

Publication Rights Reserved
This paper was prepared for the 92nd AIME Annual Meeting in Dallas, Texas, February 24–28, 1963, and is considered the property of the Society of Petroleum Engineers. Permission to published is hereby restricted to an abstract of not more than 300 words, with no Illustrations, unless the paper is specifically released to the press by the Editor of the Journal of Petroleum Technology or the Executive Secretary. Such abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request providing proper credit is given that publication and the original presentation of the paper.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.
A discussion having the title "Steels for Drill Pipe, Tool Joints, and Drill Collars" written by a user is naturally a discussion of significant problems arising from usage of these drill string items. The discussion that follows indicates user problems that may or may not be solved by metallurgical improvements.

PENETRATION RATE FACTORS
A way to reduce drilling cost is to drill faster. The following is a simplified expression of the drilling rate equation:
R =
Cf = Drillability coefficient W = Bit weight N = Rotary speed D = Bit dullness
Thus drilling rate increases with drillability, weight, and rotary speed, and decreases with dullness. The bit weight and rotary speed exponents vary with the type of formation being drilled and are of such value that a point can be reached where further increase results in no better rate of penetration.
The bit weight and rotary speed that will yield maximum performance depends in part upon the ability to clean the hole ahead of the bit. This is the function of rig hydraulic horsepower that generally accounts for use of higher circulating pressure and the consequent demand for larger pumps.
Rock bits have been improved to withstand higher weight and more rotary speed. The steel is tougher so teeth don't break off quite so readily. This fact permits use of a longer toothed bit that produces a faster drilling rate.
Growing effort to achieve a faster drilling rate by use of increased bit weight, rotary speed, hydraulic horsepower and bits with more bottomhole action has created drill string deterioration and failure problems of considerable proportions.
New Roles for Automation in the North Sea
Authors: Mears F.C. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Summary
A large North Sea Platform may have many diverse operations associated with it. These include drilling, production, storage, custody transfer, a pipeline operation, and generation of a significant block of electric power. Superimposed on these is a comprehensive safety system and the monitoring of environmental factors and structural integrity. There is a need to coordinate these operations through an information system. The thrust of this paper is not toward describing the functions in detail but rather to suggest a common building block, which has computer intelligence, to serve all the functions. The specific needs of a particular function is implemented by a particular function is implemented by a stored program.

TRADITIONAL OIL FIELD AUTOMATION VERSUS AUTOMATION OF A LARGE NORTH SEA PLATFORM
Automation or supervisory control of oil fields and pipelines has been in general use for approximately 15 years. This is a system whereby control of valves, motors, shutdown systems, etc. are performed by local controllers. performed by local controllers. Located at a well head area or at a piece of process equipment is a box called an RTU process equipment is a box called an RTU (Remote Terminal Unit). All status information on valve positions, turbine meter readings, and continuous readings from flow and pressure transducers are digitized and sent over a telemetry link to a master station in a central control location. Special displays of lights, indicators and recorders give the operator knowledge of every well head area and process equipment. The next logical step is to attach a computer to the master station. See Figure 1. This permits certain automatic operations to take place like:Periodic scan of all inputs for alarm status.Recording in memory, perhaps every 5 minutes, flow, pressure, and temperature readings to enable the generation of reports.Set up automatic tests of wells.
Locating the Dog-Legs and Jump-Shifts in North Sea Pressure Profiles
Authors: Gill J.A. , Gregg D.N. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Pressure profile plots in the North Sea have been difficult to interpret and calibrate, due to erroneous positioning of "normal" compaction trend lines. Recent ADT shale parameter plots, particularly shale factor plots, assist greatly in locating dog-legs and jump-shifts in the complex stratigraphy of North Sea sediments.
Many of these geopressured Tertiary shales, treated simply as "gumbo", have been inadvertently drilled in underbalance, with resultant hole problems and loss of expensive drilling time. A better way combines balance of shale pore pressures with correct mud density; mud chemistry designed to remove or at least restrict water from these already-wet, pressured shales; and deliberately controlled drilling rates to allow mud chemistry time to act.

Introduction
The great majority of drilling problems, the world around, stem from (largely problems, the world around, stem from (largely unrecognized) pressure profile problems and misconceptions.
Many drilling people in the North Sea still intuitively feel that pressures:originate in sands;occur only at depth;are somewhat linear in nature.
Our experience in interpreting ADT shale parameter plots in many different sedimentary parameter plots in many different sedimentary basins of the world - and we feel most privileged to have been given this unique privileged to have been given this unique opportunity - has led us to the exact opposite conclusions; that pressure(s):originate in compacting shales;are generated in the younger shales, often at shallow depths;are a continuous zig-zag affair rather than a linear "gradient";"reverse" back to "normal" in older shales at greater depths.
Drilling Costs
Authors: Jenkins P.B. , Crockford A.L. 
Published: December 2007

Abstract
Drilling costs in offshore U.K. waters are very high, and subject to large variations. To gain an insight into the major elements of total well costs a hypothetical exploration well is constructed. This well is assumed to be drilled from a contractor rig to a depth of 10,000 feet, in 500 feet of water located 100 miles from the nearest supply base. The proportion of each operation to total well cost is given. A time breakdown estimated from experience during 1974 is presented for this well. From the combination of costs, and times, average daily rates are generated.
Reference is then made to actual drilling costs experienced since January, 1973 during which time 24 wells have been drilling by Shell Expro. The major influences upon well costs are identified, with tentative trends predicted for future drilling costs.
Choice of type of rig and typical contract conditions are reviewed together with the methods and major areas in which a reduction of drilling costs are sought.
In conclusion, the likely impact of inflation during 1975 is illustrated by reference to the hypothetical well.

Introduction
The cost of drilling a well in U.K. waters, particularly the Northern North Sea, is a voyage into the unknown. Factors affecting the eventual cost exhibit only one common characteristic, multiplication rather than addition. Basic costs, such as rig hire, or transport, are high. The weather conditions encountered dictate high capital costs for equipment designed for this environment. Even given the latest equipment, weather downtime still introduces a large variation in the time required for an operation and hence the cost. An illustration of the magnitude of this problem is given by the fact that during the winter months the maximum wave heights can exceed 30 feet, the approximate operating limit for many rigs, for 30% of the time.
If contractor rigs are used, current rig hire rates can be higher than $40,000 per day. Back-up costs, for materials and per day. Back-up costs, for materials and transport etc. can exceed $25,000. Hence drilling offshore U.K. is an expensive business. Realisation of the extent of these costs, and the relationship between the various costs aids any attempt at cost reduction.
Genesis, Migration and Entrapment of Jurassic Oil in the North Sea
Authors: Selley Richard C. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Many major North Sea oil fields occur in Jurassic sandstone reservoirs. Trapping mechanisms are diverse, but the most common types are tilted horsts and block-faulted anticlines. These have undergone complex tectonic evolutions, which in different structures, predate, postdate and were synchronous with the deposition of the reservoir formations. Thus depositional thinning and truncation are commonly present over the crests of these features, but at different stratigraphic intervals in different fields.
Several marine and nonmarine shales with source potential occur interbedded with the reservoir sands. It is unlikely, however, that oil generation occurred before the Palaeocene. Some structures were certainly not sealed until well into the Cretaceous and a considerable thickness of Cretaceous cover must have been deposited to enable the geothermal gradient to build up sufficiently for the source rocks to generate their hydrocarbons.

Introduction
Within the last 5 years several major oil fields have been found in Jurassic sandstone reservoirs of the northern North Sea. The object of this paper is to review the habitat of the Jurassic oil; to discuss its genesis, migration and entrapment, and the nature of the reservoirs.
The paper commences with a brief account of the geography and stratigraphy of the Jurassic rocks; this is followed by accounts of the source rocks and reservoir rocks. The penultimate section describes the structural penultimate section describes the structural style of the traps and the paper concludes with an analysis of the time and mechanism of oil generation, migration and entrapment.

Jurassic Geography and Stratigraphy
Prior to the Cretaceous period, North America, Greenland and Western Europe formed a single area of continental crust. Tensional forces commenced in the Triassic. These caused downwarping of sedimentary basins and fault-bounded rift valleys. Ultimately, the North American, Greenland and European plates were torn apart as new oceanic crust formed in what are now the ocean basins of the Atlantic. It was against this background of tensional tectonic forces that the Jurassic rocks of the North Sea were deposited.
Subsidence began in the North Sea basin in the Permian. Thick continental red sandstones and shales were deposited throughout the Permian and Triassic with local intermittent phases of evaporite formation. A fault-bounded axial rift valley developed down the North Sea basin, close to the modern median line.
A Systematic Approach To North Sea Data Evaluation
Authors: Gaffney P.D. , Cox T.F. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Lack of reservoir information increases oil field investment risk. It is therefore, essential to allot the funds and time available for data collection in such a manner that this risk is minimized.
A simple systematic approach is defined for data collection and assessment. This approach requires:The definition of the levels of data that can be obtained at various stages in a field's life.The formation of a field plan, based on currently available data, which closely links that data with the investment decisions that must be made.The determination of the cost of error in the investment plan due to error in the field data.The allocation of data collection effort in order to minimize the cost of investment error.
Emphasis is placed on the continuous revision of the field plan and the cost of error estimates throughout the development phase of a field's life. The resulting phase of a field's life. The resulting guidance in data collection is of particular importance in the development stage of a North Sea field where large investment decisions are based on very limited information.
Various approaches to cost of error estimation are outlined with emphasis being placed on clarity of presentation to allow day placed on clarity of presentation to allow day to day use by Field Engineers and Management.

Introduction
The object of this paper is to outline methods of reducing oil field investment risks by correct allocation of reservoir data collection and evaluation effort. The systems outlined here are basic. They are intended to provide a framework to which future more rigorous methods of data control can be applied.
We are concerned with the problem of collecting the right data at the right time and applying it correctly to field development and operations decisions. A rigorous operations research approach to oil field information handling is beyond the scope of a single paper.
Practical Implications of Gradual NORM Accumulations in Storage Tank Sludges to Waste Removal Actions
Authors: Ann Magee Darcy 
Published: December 2007

Abstract
A Waste Removal Action has been conducted at a former oil reclamation plant located in Grapeland, Texas. This site is a listed Texas State Superfund Site, identified as the McBay State Superfund Site (McBay). The waste removal action was conducted under the regulatory authority of both the Texas Natural Resource Conservation Commission (TNRCC) and the Railroad Commission of Texas (RRC). This was the first and, to date, only site removal action both of these regulatory agencies have overseen concurrently.
Throughout several decades extending back to the 1930's, the McBay site had been used for various operations, including gas recycling, oil field parts storage, and oil reclamation. The bulk of the environmental issues which landed the site on the State Superfund list stemmed from operations associated with the oil reclamation operations. Historical documents reveal that the plant received regulated wastes including petroleum refining wastes, waste motor vehicle lubricating oils, barge bottoms, tank bottoms, and slop oil during its oil reclamation operations.
The TNRCC and RRC shared waste characterization and removal oversight, with each agency defining its particular requirements in separate Agreed Orders. Subsequent to the development of the Agreed Orders, a site evaluation suggested the potential of wastes and waste containers impacted by Naturally Occurring Radioactive Materials (NORM).
The differing focus of the agencies has resulted in a thorough and unique approach to site characterization, waste disposal, and waste recycling, especially as concerns NORM wastes. The application of regulatory guidelines has also resulted in a unique mixture of hazardous waste exemptions as defined under TNRCC, RRC, and Texas Department of Health (TDH) NORM regulations.
NORM concentrations detected at the McBay site were compared to a database of exploration and production (E&#38;P) waste characteristics developed primarily through ThermoRetec&#8217;s extensive work with both the American Petroleum Institute (API), and The Gas Research Institute (GRI). Data was also compared to TNRCC and RRC regulatory standards, including hazardous waste thresholds, Class 1 waste thresholds, and used oil thresholds.
Environmentally Safe Oil-Based Fluids for Drilling Activities
Authors: Sáchez G. , León N. , Esclapés M. , Galindo I. , Martínez A. , Bruzual J. , Siegert I. 
Published: December 2007

Abstract
Diesel based drilling fluids had been widely used in the past due to its low price in the market. However, it has been well documented the adverse health and environmental effects of Diesel mostly due to the high aromatic hydrocarbon content which makes it toxic. As an alternative to the use of Diesel, PDVSA-Intevep has addressed efforts toward the development of environmentally safe drilling fluids. In that sense, new oil based mud formulated with mineral oil (&lt; 0.1% aromatics) and palm tree oil (without aromatic), both produced in Venezuela, have been used for drilling operation proposes to overcome the environmental and health risks. The present work evaluated the toxicity and biodegradability of mineral and palm tree oil-base drilling fluids compared to those formulated with Diesel. Standard procedures were performed for both tests. US-EPA protocols were followed for toxicity evaluation and A.S.T.M for biodegradability tests. Biodegradation rate of drilling cuttings impregnated with the three fluids were estimated in soil pans at laboratory scale to determine bioremediation process of the waste. The results indicate that mineral and palm tree oil based fluids are no toxic (LC50 &gt; 30,000 ppm) while Diesel showed high toxicity levels (LC50 19,000 ppm). Under anaerobic conditions, the palm tree oil based fluid was the only biodegraded (&gt;70%). From the soil pan studies, the three types of oil impregnated cuttings showed to be bioremediated; nevertheless, the palm tree cuttings biodegrade in soil compost even without aeration.