bluuebunny/crossref_metadata_2025_split huggingface dataset:
Alaska and the International Oil Scene
Authors: Symonds Edward 
Published: December 2007

It is a great pleasure to be invited to Anchorage to address the first Alaska Regional Meeting, The Alaska Oil scene, of the Society of Petroleum Engineers of AIME. My last visit to this city was almost 10 years ago. At that time I tried to keep my mouth shut. But I could not help believing - even in the Cook Inlet perspective of those days - that this state was a very exciting oil province. Today we recognize it as probably the greatest in the history of the U. S.
Since that early visit the demand problems in the oil industry have certainly been multiplying. I have some slides showing the scale of demand growth and the part that we now expect Alaska to play in meeting it.
There was a time when the industry's professional pessimists used the Prudhoe Bay professional pessimists used the Prudhoe Bay discoveries as proof that the industry was in for new troubles. The theory was that at least 15 billion bbl of recoverable oil in the Prudhoe Bay area would give rise to a new source Of about 2 million B/D of production by 1980. This would pour into the West Coast market, more than doubling its present supply. Together with some increase in production from other parts of Alaska and with California continuing parts of Alaska and with California continuing to produce about 1 million B/D, local needs would be unable to absorb the new supply. With Canadian imports remaining economically attractive, and with no obvious way of transporting crude oil to the big markets of the Midwest and the East Coast, it was argued that nearly 1-1/2 million B/D would be hunting desperately for buyers on the West Coast. As a result, the price structure would crumble. Production in price structure would crumble. Production in the Southwest would have to be cut back … or so said the pessimists.
This was a gloomy outlook for the oil companies. And we broadly agree with the basic statistics that I just mentioned. But we do not agree about Alaska's impact on the industry. In fact, the oil shortages that appeared last summer made it clear how greatly the pessimists had misjudged the outlook.
Today, we are much more conscious than we used to be of the obstacles to North Slope development. Ever since Seward's $7 million "folly" in 1867, many people have had mixed feelings about what Alaskans call outside "spoilators". The gold discoveries on Bonanza Creek in the Klondike in 1896, the Kennecott discovery in the Copper River basin in 1900, and the excesses of the fish trappers in the first half of this century, all gave a very solid basis to fears like those expressed by Thomas E. Kelly of the Dept. of Mineral Resources of Alaska. At a meeting of the Society of Petroleum Engineers not much over a year ago, he talked about the after-math of exploitation as a "tragic scene on the Alaskan landscape."
Pipelining and People in the Arctic
Authors: Hurd Lee G. 
Published: December 2007

Abstract
It seems certain that the decade of the '70s will see some dramatic changes in energy supply and delivery systems throughout North America. Energy requirements are accelerating and the increases in traditional sources of supply are lagging behind.
Several new energy sources will be investigated and some tapped. This paper describes the study of one such new source: the connection by a pipeline into the Arctic of new reserves of gas in Alaska and northern Canada with markets in the U.S. and Canada.
Reserves which would support such a pipeline may be proved now and the potential pipeline may be proved now and the potential for additional reserves in the Arctic is more than encouraging.
Three groups, one of which is The Northwest Project Study Group, have announced study projects. The Northwest group has committed over $12 million to research and studies and is well underway with its work.
Pipelining in the Arctic will be an unique challenge. Permafrost, in all its variations, exists under the soil through nearly half the length of the pipeline. In addition, massive ice lenses and vertical ice wedges will be encountered. Any disturbance of the thin insulating organic surface layer will start thermal erosion in many areas.
The Northwest Group is investigating the feasibility of carrying refrigerated gas in a buried line and to evaluate the scheme has had constructed a pipeline test facility in the Arctic. The facility includes long sections of 48-inch diameter pipe through which air at controlled temperatures is circulated. The test program will evaluate pipe stability in high ice content permafrost; will test foundation types; will investigate surface restoration methods, drainage problems, etc.; and will include investigation of construction practices.
A detailed knowledge of the unique arctic ecology will be essential. Ecologically sensitive areas must be identified and respected. Wildlife species must be understood and undue disturbance avoided.
The native people living along the pipeline route, while few in number, must be pipeline route, while few in number, must be included in the plans and programs of such a pipeline project. pipeline project.
Insulated Gravel Embankments for Arctic Road Construction
Authors: Condo A.C. , Burt Glenn R. 
Published: December 2007

Abstract
Permafrost creates special engineering problems for the design, construction and problems for the design, construction and maintenance of embankments. Lack of knowledge about permafrost and environmental conditions has resulted in tremendous maintenance costs as well as relocation or abandonment of highways, railroads and other embankment structures. Therefore, careful consideration must be given to the design and construction of embankments to be placed on permafrost.
Since the spring of 1969, ARCO Chemical Company has been working on embankment design and construction methods which could serve as alternates to the conventional (5–6 feet of gravel) method of embankment construction on the North Slope. Study and research has resulted in the development of ARCOFOAM Insulated Embankment Systems which are technically (thermally and structurally) capable of being used as an alternate method in the design and construction of Arctic Embankments.

Introduction
The problems of permafrost degradation must be considered in the design of Arctic and sub-Arctic embankments. Two basic design methods which may be utilized are the active and passive techniques. The active method eliminates the permafrost by excavation and fill. An example would be stage construction of sub-Arctic roadways. These are built by placement of fill and constant maintenance placement of fill and constant maintenance over a period of years as melt and subsidence of the permafrost occurs. On the North Slope of Alaska, which is underlaid with more than 1,000 feet of permafrost, the active method is impractical. The passive method prevents permafrost degradation by keeping prevents permafrost degradation by keeping it in a continually frozen state so there will be no melt and subsequent subsidence. Therefore, the passive method controls the design of roads, airfields and other embankments in the Arctic.
Subsurface features of prime concern in Arctic embankment work include soil type, water content, permafrost which, when melted, causes subsidence or settlement.
We can establish the mean annual air temperature, mean annual air freezing index, mean annual air thawing index and the amplitude of temperature fluctuation however, thermal design is related to the temperature that occurs at the soil-air interface. This temperature is affected by numerous items, such as depth of snow, soil type, wind and evaporation cooling rates at the interface.
U. S. Hydrocarbon Finding Cost
Authors: Howell F.N. , Merklein H.A. 
Published: December 2007

Introduction
It is the purpose of this paper to develop a trend of hydrocarbon finding costs, spanning the period from 1938 to 1968, and to compare this trend with others that have been occurring in the petroleum industry. Such a comparison of long-run trends may be useful as an early-warning device capable of detecting impending difficulties that are to be expected in the supply structure of domestically produced hydrocarbons.
Finding costs are defined as total exploration expenditures in a given year, divided by the total quantity of hydrocarbon reserves that have been discovered as a result of these expenditures. Thus the two major items that need to be considered are exploration expenditures and reserve discoveries. These will be discussed in that order.

EXPLORATION EXPENDITURES
One part of the U. S. hydrocarbon finding costs, namely total exploration expenditures, is straightforward and presents no great conceptual problem. However, as will be seen later, a substantial amount of statistical data manipulation and interpolation is required for a reliable estimate of this factor.
Exploration exploration, as used in this study, consist of the following subcategories:
Drilling and equipping exploratory wells Acquiring undeveloped acreage Lease rentals Geological and geophysical expenditures Test well contributions Land Department (leasing and scouting) Other, including direct overhead
Collection and evaluation of data on each of the above subcategories and, for that matter, on other petroleum statistics, is accomplished each year by a joint effort of the American Petroleum Institute (API), the Independent Petroleum Association of America (IPAA), and the Mid-Continent Oil and Gas Association (MCOGA). This Joint Association Survey is prepared annually to provide information on finding, developing, and producing hydrocarbons by the oil and gas producing industry in the United States.
Optimization of Sucker Rod Replacement
Authors: Powers Maston L. 
Published: December 2007

Abstract
A technique has been developed to optimize sucker-rod string replacement decisions. The basis for this optimization assumes that the failure frequency expectation of sucker rods increases with time at a variable rate approximating a Gaussian curve throughout their usable life. At some point in time the maintenance cost of continued operation of a fatigued rod string exceeds the capital cost and associated maintenance cost of a replacement string. A mathematical expression representing this optimum replacement point was developed and solved for the time interval between sucker rod failures. The resulting equation can be applied to a partial replacement as well as a complete replacement rod string. A graphical solution was developed to implement the optimization technique for routine field use.

Introduction
A need for improved criteria for making sucker-rod string replacement decisions became evident while making a detailed study of operating costs and field practices in the midcontinent area. It was found that sucker rods were being replaced on as many bases as there were individuals making replacement decisions.
During the time interval for which sucker-rod replacement data was compiled, Nov., 1969, through Aug., 1970, it was found that fatigued rod strings were being replaced after an average of 7.6 failures. Wells that exhibited symptoms of specific mechanical problems were excluded from this analysis. For example, instances of chronic joint failures were attributed to improper makeup practices rather than fatigue.
Judgment indicated that the observed replacement practices needed improvement. An engineering basis for economically optimizing sucker-rod replacement decisions was therefore pursued. pursued.

Basis of Optimization Technique
Performance of sucker rods is affected by numerous well conditions such as maximum rod stress, stress range, pumping speed, corrosivity of the environment, and a variety of mechanical problems. Thus, each well can be expected to problems. Thus, each well can be expected to exhibit unique behavior. However, by assuming that individual well conditions remain constant during an analysis period, sucker rod performance can be generalized. performance can be generalized. For any combination of constant well conditions a properly designed sucker rod string will initially have relatively infrequent failures. As a result of cyclic loading in normal use, the failure frequency expectation of the string should increase with time in a rough approximation to a Gaussian curve, as depicted in Fig. 1.
Finite Element Analysis of Single Well Backflow Tracer Test in a Homogeneous Reservoir
Authors: Chase Curtis 
Published: December 2007

Abstract
The single well backflow tracer test, in which one tracer is injected into a reservoir and then monitored at the same well as the fluid is withdrawn, is modeled for a homogeneous infinite reservoir. A numerical solution to the partial differential equation modeling the system partial differential equation modeling the system is obtained by the method of finite elements. For equivalent accuracy this method appears to give solutions in considerably less computer time than that required to solve the same problem by finite differences. An approximate analytical solution is also obtained.
The mathematical model contains three dimensionless parameters. Unfortunately, the injection of a single pulse of tracer does not supply enough information to uniquely determine these parameters. One method of determining all three is to inject three distinct pulses of tracer into the reservoir and allow each pulse to penetrate a different distance.
Partitioning of tracer into a stationary oil phase or onto the surface of reservoir rock can cause a significant increase in the amount of dispersion observed at the well bore. An example is presented which illustrates these sorption effects.
PURPOSE AND SCOPE PURPOSE AND SCOPEIn the simplest single well backflow tracer test a pulse of tracer is injected into a reservoir. After a period of time flow is reversed, and tracer concentration is monitored as the carrier fluid is withdrawn. Proper interpretation of the well bore tracer concentration response during withdrawal offers a possible means of evaluating certain reservoir properties in situ. The advantage of in situ determination of reservoir properties lies in the fact that the results are representative of a larger reservoir volume than are results from logs or core samples.
Properties primarily of interest which might be obtainable from a backflow tracer test are (1) reservoir residual oil saturation and (2) the parameters which characterize dispersion. Knowledge of the dispersion parameters is necessary in order to correctly evaluate possible secondary recovery projects in which mixing of the displacing and displaced fluids takes place because of dispersion.
The tracer concentration within the well bore is governed by the convective-diffusion equation.
New Oil Gelling Systems Prevent Damage in Water-Sensitive Sands
Authors: Kucera C.H. , Smith C.F. , Braunlich F.H. 
Published: December 2007

Abstract
Development of viscous fracturing fluids has renewed interest in fracturing with oil base materials. Oil, once the primary frac fluid, was displaced when aqueous systems allowed more flexibility and safety. Water-sensitive and some other easily damaged formations were victims of this change since most of the new developments in fracturing technology could not be applied. Recent developments have led to gelled oil systems which allow injection rates and prop carrying capacities previously unattainable with other oil base systems. These gelled oil systems can be continuously mixed to carry 10–20 sand concentrations in excess of five pounds per gallon at rates of 20 barrels per pounds per gallon at rates of 20 barrels per minute down 2-1/2 inch tubing. These systems do not damage water sensitive formations. The gel is broken by an internal breaker system.
This paper describes the chemical development of the new gelling agents and their application in many experimental treatments. Rheological comparisons with other viscous frac fluids are shown and other potential applications of the systems are discussed. These include use as drilling fluids, workover fluids and packer fluids where formation damage is critical.

Introduction
The choice of fluids used in fracturing and their application has been cyclic in nature. Originally fracturing was done with oil exclusively. With later development of horsepower, friction control, desirability of large volume treatments, and emphasis on treatment safety, it became advantageous to use aqueous fluids, including brine, water and acid. The switch to aqueous fluids was so complete that by 1968 oil base fracturing fluids accounted for less than 10 per cent of the total volume of frac fluids pumped in the United States. pumped in the United States. With the general swing to water based fluids, research and development effort during the past 15 years has been devoted primarily to the improvement of aqueous frac fluids. Throughout this time, however, there has remained a need for oil-base fluids to treat formations which are water sensitive. Injection of aqueous fluids into these formations often fails to provide stimulation benefits and may result in a productivity decrease. Even the use of potassium chloride or calcium chloride has not been successful in fracturing many of these zones.
An Investigative Study on Horizontal Well and Extended Reach Technologies with Reported Problem Areas and Operational Practice in North America and Europe
Authors: Ikeda S. , Takeuchi T. , Crouse P. C. 
Published: December 2007

Abstract
In 1994 and 1995, a study was initiated to investigate developments, activity, and philosophies of the larger oil and gas industry in implementing horizontal well and extended reach technologies. To date, North American and European operators, contractors, service companies, government authorities, and educational institutions have been interviewed directly along with the development of data resources and references. Over 100 people shared in direct interviews, constituting 13 operators in Europe, 14 operators in North America, 2 drilling contractors, and 5 major manufacturing/service companies. Over 40 person-to-person interviews were accomplished in North America and Europe. Any company specific information shared in the interviews were given in confidence in that the companies would not be identified in any summary results; thus this paper refers to industry findings. Interviews along with approximately 1000 references and industry well information provided a detailed look at horizontal well and extended reach technology industry along with application strategy and philosophy.
Second Generation Synthetic Fluids in the North Sea: Are They Better?
Authors: Friedheim J. E. , Conn H. L. 
Published: December 2007

Abstract
At the beginning of the 1990's, three synthetic type materials were introduced – esters, ethers and polyalphaolefins. Now after heading towards the last half of this decade, a new generation of synthetics are gaining popularity – linear alpha olefins and isomerised olefins. Another base fluid, linear paraffin, which can be considered pseudo-oil rather than synthetic, is also making an impact. Each of these materials have similarities as well as differences both as base fluids and drilling muds.
North Sea applications of synthetic-based muds highlight the major aspects which not only delineate the first generation of fluids from the second but also the various fluids themselves. Each area – the United Kingdom, Norway, and the Netherlands – not only have different marketplaces, but also different emphasis on the many facets of environmental as well as health and safety concerns. This variance from country to country provided the impetus for the introduction of these various fluids.
This paper provides an overview of these second generation fluids and deals with their technical, environmental, and economical status as it relates to the North Sea drilling area. It will also discuss these second generation fluids in light of their predecessors and emphasise the differences. Details will be provided into the chemistry of these second generation fluids and actual field data will be provided to illustrate their effectiveness.
Land Rig Move Between Central Asia (Kazakhstan) and Eastern Europe (Romania)
Authors: Rabier J P 
Published: December 2007

Abstract
The FORASOL NATIONAL 1625/3 rig was mobilized from a west European port to the rig site in central KAZAKHSTAN (near AKTIUBINSK) in 1993. The rig was transported by ocean and river ship (5), block trains (5) and 250 truck loads.
A survey was of course required in order to determine the best routing in function of port facilities (transhipment), availability of cranes and handling equipments and seasonal influences. This survey required several months work..
The main caracteristics of our equipment.
The Challenges of Drilling Wells Approaching 40,000 ft.
Authors: Norman Monica , Tveit Leon , Kalvenes Øystein , Humblen Jarl Ove 
Published: December 2007

Abstract
This paper describes the results from an extensive, joint, development project between Norsk Hydro A/S and Anchor Drilling Fluids A/S, aimed at identifying the potential problems associated with drilling wells approaching 40,000 ft., mainly focusing on the drilling fluid aspects.
The major obstacles related to drilling such extremely long wells were identified as:Drilling equipmentFluid related problems:–Pressure losses–ECD effects–Wellbore stability–Lubricity–Hole Cleaning
The project also incorporated the development of a new, environmentally friendly, synthetic oil based mud system, and further developments of existing systems in order to solve the identified fluid-related problems. Results from field tests are reported.
Field Validated Hydraulic Model Predictions Give Guidelines for Optimal Annular Flow in Slimhole Drilling
Authors: Cartalos U. , King I. , Dupuis D. , Sagot A. 
Published: December 2007

Abstract
Accurate prediction of annular flow is of primaiy importance in slimhole drilling. A model was developed that better represents actual annular configurations. It accounts for axial variations of drillpipe eccentricity and for effects arising from drillpipe rotation. The model is validated with data obtained from 3 industrial slimhole wells (4"3/4 and 3"3/8 phases). Based on model predictions, guidelines are given to define flow parameters and to adapt fluid rheology in order to obtain optimal hole cleaning under safe drilling conditions.
Analysis of Carbonate Dual Porosity Systems from Borehole Electrical Images
Authors: Newberry B. M. , Grace L. M. , Stief D. D. 
Published: December 2007

Abstract
Many productive carbonates have dual porosity systems with widely varying proportions of primary and secondary porosity. The secondary porosity may contain vugs, molds and fractures. Most interpretation methods rely on traditional resistivity and porosity logs. These often fail to produce results consistent with production because of the complex nature of the dual-porosity carbonate. Borehole electrical images provide both the small-scale resolution and azimuthal borehole coverage to quantitatively resolve the heterogeneous nature of the porosity components. The primary assumption for this technique is that the resistivity data from the electrical images are measured in the flushed zone of the borehole. Then, the electrical images can be transformed into a porosity map of the borehole. Automated analysis of this porosity map, windowed over short intervals, provides a continuous output of the primary and secondary porosity components. This method has been applied to a variety of carbonate formations where conventional log analysis has usually failed. The predicted results compare accurately with the actual production.