bluuebunny/crossref_metadata_2025 huggingface dataset:
The Office Of Coal Research And Its Activities
Authors: Lamb George A.
Published: December 2007

The Office of Coal Research was established by Public Law 86-599, approved July 7, 1960. It was organized upon an operational basis in the spring of 1961, and awarded its first contract in August of that year. It is charged with the development through research of new and more efficient methods of mining, preparing and utilizing coal. This is done through contracts with agencies of Government and with private organizations; OCR does no in-house research.

Private research in the coal industry has been limited to activities by coal associations and by a comparatively few companies. This industry is composed mainly of small business units that are unable to finance laboratory and pilot plant operations. A good deal of coal research has been governmental. Total research, however, has been inadequate and coal resources have not been effectively utilized as a consequence. The necessity for an expanded and more balanced coal research program becomes particularly apparent once consideration is given to future requirements for energy.

1. Future Energy Requirements

Fuel forecasters in estimating long-term energy requirements and supplies have predicted a bright outlook for coal. Some predictions have annual coal output reaching 800 million tons by 1980, almost twice the average of the last five years. The projections reflect advanced statistical techniques in evaluating the prospective growth of the economy and its resulting energy needs, Supplies for the future energy load are distributed between the fuels and hydro. While coal production amounts to new records in the distant years ahead, its share in total energy supply is expected to be near what it is presently.

These projections assume that ultimate consumer energy products will be supplied adequately not only in volume but also by kind and type. The consumer energy schedule shifts continually as it reflects the changing demands for numerous uses. Its appearance, expressed generally in proportions of solids, liquids, gases and electricity, is quite different today from what it was in 1940.
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.

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

Parameter 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

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.

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.

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

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.

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.

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

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&P) waste characteristics developed primarily through ThermoRetec’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

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 (< 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 > 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 (>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.
Field Experience Using Drilling Cost Minimization Programs
Authors: Wood W.D.
Published: December 2007

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

Application of computer-calculated drilling cost minimization has been successful in the exploratory floating-rig drilling of the 9/13 block in the United Kingdom sector of the North Sea. Applications will continue with the drilling of future wells from the "A" platform.

Introduction

Drilling Cost Minimization, Optimum Drilling, OP Drilling and other similar terms have been used for computer-calculated, programmed drilling simulation for several programmed drilling simulation for several years. Speer in 1959 was one of the first to publish a concept of how to calculate cost-minimizing drilling programmes. Galle and Woods detailed programmes. Galle and Woods detailed technical procedures in 1960. By 1964 Edwards was advocating "drill on paper" to reduce drilling costs. Most of the major oil companies since then have used, in varying degrees, some form of calculated cost minimization programme in their drilling efforts.

Lummus presented a description of Amoco's efforts for drilling in the North Sea.

Various optimizing methods have been described; optimization by bit run, by interval or by well, have all been tried. Several methods were described in one recent paper. The use of the computer for paper. The use of the computer for calculating many alternatives and determining the optimum conditions is now routine. Several service organisations offer digital data-gathering equipment, on-site computers and foot-by-foot formation evaluations.

This paper will describe Mobil North Sea Limited's application of computer-calculated simulated drilling for the 9/13 block in the United Kingdom sector of the North Sea.

Background

In 1972 Mobil drilled the first well in the 9/13 block in the United Kingdom sector of the North Sea. With no wells within one hundred miles, this was a rank wildcat and no effort was made towards a calculated optimization program.
A 4-Year Experience With Dynamically Positioned Drilling Vessels
Authors: Vasseur B.
Published: December 2007

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

Three dynamically positioned drilling vessels have now been in operation during several years to fulfill offshore petroleum exploration tasks on a worldwide basis.

Among them are the sisterships "PELICAN" and "HAVDRILL" aboard which the drilling management is provided by FORAMER S.A. of Sevres, France. These are the only two units which have been originally built without any conventional mooring system nor any re-entry guide lines.

Both units have accumulated a combined four-year experience in widely scattered areas ranging from Labrador to Angola. A very large number of data covering the floater behaviour and the resulting operational efficiencies have been gathered and analyzed. They include the environmental conditions; their influence on the unit motions and the positioning over the drilling well; the consequences for the actual activity; the various operational procedures; the economical factors and the procedures; the economical factors and the resulting ability to predict and prepare future tasks.

On the basis of this information it has also been possible to improve the design of future PELICAN-type units capable of drilling in much greater water depths (three are now being built under FORAMER engineering) and to extend the same concept to larger ships and other types of floating units.

The existing dynamically positioned vessels have now fully proved the reliability of anchorless drilling units by safely and efficiently completing their assignments - among which the successful "PELICAN" campaign offshore Labrador during the summer of 1973 has been the most significant demonstration to the entire petroleum exploration industry.
An Overview of the IADC Deepwater Well Control Guidelines
Authors: Christman S. , Kelly A. , Plaisance M. , Kropla S. , Metcalf J. , Robinson E. , Weddle C.
Published: December 2007

In response to technical challenges unique to deepwater drilling and production operations, a Task Force comprised of representatives from major and independent operators, drilling contractors, academia, well-control experts and equipment manufacturers has developed the IADC Deepwater Well Control Guidelines for industry wide circulation. Problem prevention is the emphasis of the Guidelines, which includes chapters on the five key issues identified by participants: Well Planning; Well Control Procedures; Equipment; Emergency Response; and Training. The result is a compilation of the industry's existing best practices, covering considerations and procedures from some of the best people in the industry. Developing the Guidelines within a one-year timeframe with a minimal budget was accomplished through the dedication of committee members, the support of their companies, and use of the Internet to facilitate peer review.
When "No" is the Appropriate Answer to the Customer
Authors: de Wardt J. P. , Leggett D. M.
Published: December 2007

The traditional method of establishing relationships between customers and suppliers in the drilling business is very inefficient and wastes money through consuming resources without adding value. Some new processes have been introduced but low bid is still often the primary determinate of success. These will be reviewed, the issues still to be addressed identified and solutions discussed. Two avenues of improvement will be described: 1) suppliers evaluating their opportunity and declining where appropriate; 2) customers removing cumbersome systems from the past and using new, more intelligent and efficient methods for selecting suppliers.

When saying "no" is the right answer.

Pursuing unsuccessful bids is both a waste of direct effort and a dilution of resources, which could be properly assigned to developing potentially successful opportunities. The current personnel constraints on the drilling business make this intolerable for companies who wish to differentiate themselves. These companies will adopt logical processes to select the bid opportunities they will pursue. These processes will include strategy development with a clear understanding of target markets, business plans which specify prioritization through cost / benefit ratios and decisions trees which consistently lead contractors / suppliers to the highest potential opportunities. Suppliers will ultimately say "no" to the customer when clearly indicated through their decision processes, in a manner that enhances the relationship.

Creating value adding supplier selection processes.

Customers in other industries have gained significant productivity improvements through early selection and alignment of suppliers. Methods exist to quickly assess the real value that can be delivered and to make early selections. Price of the contract can be balanced with the value delivered by the supplier to achieve a true evaluation. Suppliers are integrated into the planning process for maximum benefit and parallel engineering dramatically cuts cycle time and development costs. A far more effective supplier selection method than the current practice will be described which will reduce the expected rise in "no bids".

Improvements in the bidding process will lead to improvement in achieving well objectives through faster cycle times, increased value and more consistent achievement of objectives. A necessary requirement in the current low oil price environment.
Evolution of Well Design in the Campos Basin Deepwater
Authors: Saliés J. B. , Nogueira E. F. , Evandro T. M. F.
Published: December 2007

This paper presents the evolution of well design at the Campos Basin to meet the new challenges of deeper and deeper waters. It discusses how well design has evolved from six casing strings to only three because of the peculiar geological characteristics of deep waters, and technological advances. The main aspects this paper takes in consideration are the evolution of well programs and wellhead systems. It also offers a new integrated approach for drilling, production, and intervention and discusses some of the results. Among other conclusions, we argue that the evolution of well design together with technological advances are key factors in deepwater exploration.
Casing Drilling – A Revolutionary Approach to Reducing Well Costs
Authors: Tessari R. M. (Bob) , Madell Garret
Published: December 2007

Rotary drilling, as we know it today, replaced percussion or cable tool drilling in the 1930's. Since that time, wells have been drilled using a drill string consisting of drill pipe, drill collars, a bit and varying downhole tools known as a "bottom hole assembly" (BHA). When the bit wears out or the BHA has to be changed, the process of "tripping" is commenced. Tripping consists of hoisting the drill string out of the well in lengths of 30, 60, or 90 feet. This process is labour, equipment and energy intensive and takes up to 35% of the total time to drill a well. In addition to the productive drilling time lost to tripping, unscheduled events during tripping can make the drilling process even more inefficient and even lead to losing the well. This paper describes the process of a threeyear research and development project to develop and commercialize casing drilling. Casing drilling will use standard oilfield casing to both drill and simultaneously case the well. Bottom hole assemblies will be retrieved on wire line up the inside of the casing. Casing drilling will eliminate the use of drill pipe, significantly reduce tripping times and reduce time lost due to unscheduled events such as reaming, fishing and taking kicks while tripping (See Fig. #1). This paper describes the tools to be used, including a special purpose built drilling rig for this process. The anticipated results of drilling with casing are discussed and specific conclusions include up to 30% savings in well costs feasible through drilling with casing.
Down-Hole Simulation Cell for Measurement of Lubricity and Differential Pressure Sticking
Authors: Isambourg P. , Ottesen S. , Benaissa S. , Marti J.
Published: December 2007

The impact of lubricity and differential sticking on well cost is becoming more important, due to activity increase in deviated and extended reach wells through depleted reservoirs. Drilling fluid characteristics play a major role in this area. A better understanding of the mechanism of differential sticking and proper evaluation of the lubricating characteristics of different drilling fluid systems, under simulated down-hole conditions, is becoming more important. A specially designed fully automated device permits accurate and reproducible measurements of coefficient of friction between metal and mud filter cake. It also monitors the variation of the filter cake pore pressure and permeability, corresponding forces and sticking time. Testing principle is based on cylindrical captor equipped with sensors (rotational for lubricity and non-rotational with axial motion for differential sticking test). Displacement into the cylindrical filter cake is made automatically through lateral motion of a measurement cell that can be rotated 360 degrees. The main advantage of this apparatus is the fact that the pressure and force sensors are located inside the cell, allowing for direct measurements. Evaluation of both water and oil based fluids differential sticking potential can be achieved, and data generated can be a useful tool to take corrective measures in selecting a suitable stable drilling fluid/additives, that will help prevent differential sticking and reduce torque and drag. A series of differential pressure sticking tests have been conducted. Data generated were used to understand the phenomenon, to characterize the risk of differential pressure sticking associated with drilling fluids, and, also, will be used to further validate numerical models. This paper describes specifications and measurement principle of this special equipment, as well as first results on differential pressure sticking tests.
Successful Use of the Hydraulic Workover Unit Method for Underbalanced Drilling
Authors: Robichaux D.
Published: December 2007

This paper describes two very successful underbalanced drilling operations that were performed in Belgium and in the coastal area of The Netherlands. The underbalanced drilling operations used a hydraulic workover (HWO) unit to effectively control the well pressure during drilling. This method is unique because it reduces damage to the formation and causes very little environmental risk.

For the Belgian operation, drilling was preceded by a series of tests and simulations. A hydraulic workover data acquisition system was installed to provide the highest possible control of the drilling process. A 9 5/8" shoe was drilled, and a cement bond log was run, after which injectivity tests were performed at the shoe. A bottom hole assembly (BHA) with an 8 ½" bit was then used to drill into the reservoir at which point the well was predicted to go underbalance with fresh water as the drilling fluids. Although the well did not flow, the underbalance drilling systems ran flawlessly and the BHA was retrieved without any problems. The well was then cased with 7" liner.

The second case history represents one of the most complex and technically challenging underbalance drilling projects to date due to the offshore environmentally sensitive location in the North Sea and the high BHP of 250 bar. The same steps of preparation as the prior well were gone through but this time the client required a zero discharge of gasses or fluids. Some of the precautions taken consisted of console enclosures, hose covers, drip pans and the entire hydraulic workover unit had to be encapsulated. The target fault was crossed successfully while meeting all of the strict environmental restrictions and client objectives.

The success of the method must also be attributed to the operational planning and close attention paid to experience gained from previous drilling operations from the multidisciplined crews. The execution of the treatment utilized all of the components considered to be state-of-the-art in drilling including the use of a data acquisition system, real-time treatment pressure monitoring and HWO drilling procedures applied.
Pressured Mud Cap Drilling: Efficient Drilling of High-Pressure Fractured Reservoirs
Authors: Urselmann R. , Cummins J. , Worrall R. N. , House G.
Published: December 2007

Drilling sour, high-pressure fractured reservoirs can involve complex, unpredictable, and hazardous well control situations. Using Pressured Mud Cap Drilling, Shell Venezuela S.A. have drilled a sour, high pressure, proof of concept well in an offshore fractured carbonate reservoir. This paper briefly overviews the evolution of this technique.
Full-scale Experimental Study for Improved Understanding of Transient Phenomena in Underbalanced Drilling Operations
Authors: Lage A. C. V. M. , Nakagawa E. Y. , Time R. W. , Vefring E. H. , Rommetveit R.
Published: December 2007

A dynamic computer simulator for underbalanced drilling can contribute significantly for designing an UBD operation and defining the most appropriate operational procedures. Timing for flow stabilization, pressure peaks in the returns and pressure variations at the bottom of the well are some of the aspects involved in determining the adequate injection flow rates, separation system and drilling procedures.

A full-scale experimental investigation was planned and executed to provide data for the evaluation and improvement of transient underbalanced drilling computer simulators. The tests were performed in a 1278 m vertical well in a research facility in Brazil. The experiments involved the injection of liquid and gas through a 3 1/2" drill-string (ID=2.992") and the return of the mixture via the annulus between the drill-string and a 7" casing (ID=6.366").

First, a pulse consisting of a gas-liquid mixture with high velocity was injected. The available data acquisition system in the research facility kept track of the whole evolution of the gas distribution inside the drill-string and through the annulus. A sequence of two gas pulses was pumped and analyzed as well.

These tests revealed some important aspects about the flow behavior: how gas spreads along flow direction and gas rise velocities. This information gives support for the perfecting gas rise velocity model and the numerical schemes used to solve the conservation equations.
A New International Standard for Casing/Tubing Connection Testing
Authors: Payne M. L. , Schwind B. E.
Published: December 2007

This paper presents background on and an overview of a new International Standard for casing/tubing connection testing. This new standard is a recommended practice and has been developed with broad international input via an ISO Work Group that has been active in recent years. Industry experiences from previous public and proprietary connection test procedures have been studied and the lessons learned have been incorporated into this new standard. Adoption of the new standard by E&P operators world-wide is recommended and will carry substantial benefits. These benefits include elimination of connections in the market place with inadequate qualification testing, documentation of manufacturer-rated connection integrity including combined loads, and stringent yet cost-effective qualification tests to evaluate connection ratings. Industry trends towards more efficient pipe design methods, such as probabilistic methods, make connection rating and qualification more crucial than in years past. Attaining these objectives will enable higher reliability in the industry's drilling and completion programs. Simultaneously, more cost effective wells will result from objective data on the performance of casing and tubing connections.
Field Evaluation of Corrosion Control Chemicals in the Viking Gas Field
Authors: King W.R. , Taylor F.R.
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 discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Corrosion inhibitors were field tested to find a chemical which, using methanol as a carrier, gave the best performance in three types of well completion. Inhibitor performance was evaluated on the basis of performance was evaluated on the basis of corrosion protection, low toxic transfer to the effluent water and lack of emulsion forming tendencies.

Introduction

The Viking Gas Field, 86 miles East of Mablethorpe, Lincolnshire, England was discovered in 1968 by Conoco and the National Coal Board (Exploration) Limited, at approximately 9,000 ft subsea in the Rotliegend sandstone. Two main reservoirs Viking 'A' and Viking 'B' as well as a series of smaller satellite structures are linked by a pipeline system to an onshore gas dehydration pipeline system to an onshore gas dehydration plant at Mablethorpe (Figure 1). plant at Mablethorpe (Figure 1).The produced gas contains 0.3–0.35 Mol % of CO2, no detectable H2S and is fully saturated with water vapour under wellhead flowing conditions. As the partial pressure of CO2 is in the range where corrosion is probable, chemical-injection facilities for each probable, chemical-injection facilities for each well were provided in the original process design.

No gas dehydration is carried out offshore except for the removal of free water condensed in process equipment as a result of pressure and temperature drops. The gas flowing from the wells is first passed to a wellhead separator for initial passed to a wellhead separator for initial removal of liquids (condensate/water) and then to a flow control valve at which the gas pressure is reduced to pipeline entrance conditions (+ 1450 psig). Secondary liquid removal takes place, after this pressure drop, in pipeline scrubbers before the gas passes directly to the main 28" pipeline to shore.

The liquids removed at the wellhead separators and at the pipeline scrubbers are passed to a three phase separator operating passed to a three phase separator operating at 400 psig. The condensate from the three phase separator is passed to one side of an phase separator is passed to one side of an atmospheric surge tank and then pumped back into the pipeline to shore. Water from the three phase separator is further treated for condensate removal on the other side of the surge tank before passing for final condensate removal to a utility sump with a sea leg. Provision is also made to route all liquids directly to the pipeline to shore, bypassing the liquid handling facilities.
Level 5 Multilateral Completed on Alaska's North Slope: A Case History
Authors: Isaacson William S. , Seale Rocky
Published: December 2007

Recent advances in multilateral technology have broadened the perspective of both re-entry and grass root wells. New tool designs, procedures, and completion equipment allow increased possibilities and functionality of multilateral wells. Multiple reservoir penetrations of a single or several reservoirs are possible from one well. Injection or production can be controlled in each leg of the well by means of downhole chokes or independent production strings. Advantages of this technology include, reduced surface footprint in environmentally sensitive or space confined areas, lower capital expenditures on surface facilities and existing wellbore infrastructure, and elimination of drilling new wells through potentially hazardous formations.

In late 1995 ARCO Alaska, Inc. began to evaluate multilateral technology and its application for adding value in the Kuparuk River Field on the North Slope of Alaska. The incentive for bringing multilateral technology to Kuparuk was access to smaller pockets of reserves, not economically recoverable at new well costs. This paper provides an in depth review of the first level 5 multilateral well constructed on the North Slope. Discussed are characteristics of a level 5 multilateral and the reasons this wellbore configuration was needed in Kuparuk. The discussion portrays equipment and procedures developed to accomplish well construction and provides a detailed review of the actual operations, with lessons learned during the process.