bluuebunny/crossref_metadata_2025_split huggingface dataset:
EROS--New Observation Vantage Points and Processes
Authors: Fary Raymond W. 
Published: December 2007

A paper, the EROS (Earth Resources Observation Satellite) Program of the Department of the Interior, that was presented by W.A. Fischer to the 44th Annual Fall Meeting of the Society of Petroleum Engineers of AIME addressed the subject of this paper. It is the intent of this one to add information on Program developments in the time since that earlier paper and to provide information based on Program experience other than that previously cited.
The EROS Program objective is to utilize aircraft and spacecraft remote-sensing technology as complementary parts of integrated data collection, processing, and dissemination systems to support resources research and management functions of the Department of the Interior. The Program develops and coordinates research in the applications of new sensors for resources applications in cooperation with NASA. At present there are two major areas of activity: present there are two major areas of activity: The first is related to the Earth Resources Technology Satellite (ERTS). The second is a suite of projects designed to determine the applicability of new aerial and satellite sensing systems and techniques to geologic, geographic, hydrologic, and topographic mapping and for supporting natural resources management functions of the Department of the Interior. Programs with similar goals for agriculture and forestry, and for oceanography are being conducted in the Departments of Agriculture, Commerce, the Naval Oceanographic Office, and in a number of colleges and universities.
The first satellite designed specifically for resources research and applications, ERTS-A, is to be launched in early 1972. It will be an unmanned satellite carrying three experimental systems: A three camera Return Beam Vidicon (RBV) system, a 4-band Multispectral Scanning (MSS) radiometer system, and a Data Collection System (DCS). The RBV cameras will photograph simultaneously and instantaneously areas of the earth 100 × 100 nautical miles - or 10,000 square nautical miles - in the blue-green (.475-.575mu m), the red (.580-.680mu m), and the near infrared (.690-.830mu m). The MSS will record three wavelength bands in the same general spectral range and the fourth band (8.0 mu m) will extend farther into the infrared. The DCS will serve to relay data gathered by devices such as stream gages, water-quality samplers, tiltmeters, and geothermal sensors from their surface bases through the ERTS receiving station at the Goddard Space Flight Center to the experimenters.
The satellite will operate for at least 1 year, in near-polar orbit and, weather and clouds permitting, will image any given area every 18 days.
Engineering Geology Review of the February 9, 1971, Earthquake-San Fernando-Sylmar Area
Authors: Slosson James E. 
Published: December 2007

Abstract
The general Los Angeles area was severely jolted by an earthquake during the early morning hours of February 9, 1971. This earthquake was the strongest to affect the Los Angeles area since the 1933 Compton-Long Beach earthquake. The epicenter of the tremor was near the town of Saugus, California; however, the area of surface rupture and greatest damage was some five to six miles southerly in the San Fernando-Sylmar area. Zones of surface rupture were visible within the bedrock of the southern foothills of the San Gabriel mountains and the alluvium of the San Fernando Valley. Belts of extensive damage to structures paralleled or were essentially superimposed over these fault zones. One of the apparent belts extended westerly from the immediate vicinity of the Olive View Hospital toward the interchange of the Foothill, San Diego, and Golden State freeways and the Van Norman Reservoir. This rupture zone is just southerly of a mapped fault referred to as the Hospital Fault but more closely coincides with a fault zone that has little surface expression but has been interpreted from subsurface data. Another rupture zone coincided with the location of a groundwater barrier which suggests geologically recent fault activity.
This earthquake is of great interest, not only from the catastrophic effects that it wrought, but also:
1. the extensive seismic data for research and development of new codes and earthquake design
2. the relatively high acceleration(s) for a magnitude 6.6 earthquake
3. the apparent high angle reverse (or thrust) type of displacement
4. the relatively high magnitude for the apparent distance of rupture
5. the association of the fault type and pattern with the geologic history of the San Gabriel Mountains
6. the effects on nearby oil fields
7. the attempts by the news media to associate oil drilling, the location of the Van Norman Reservoir, and the sun-moon position with the causation.
The History and Philosophy of Oil Insurance Ltd.
Authors: Grattan L.E. , Bruning R.R. 
Published: December 2007

Abstract
The oil company today uses a variety of concepts in its strategy for protecting against accidental loss. Risk transfer, self-insurance and captive insurance are all common to the practice and literature of risk management. Even though this multiplicity of terms can sometimes be confusing, these concepts basically break down into two categories. Risk is either transferred outside the firm to a third party or retained within.
The physical makeup of the oil industry creates certain risks which are virtually uninsurable by the conventional insurance industry. The major contributing factors to this are the generally large size of the individual facilities and the heavy concentration of facilities of many corporations in one geographical area. This difficulty has become evident in an inability of the insurance companies to supply the oil industry with the protection which it desires.
The concept of Oil Insurance Ltd. was developed by a committee of A.P.I. members during 1970 as a solution to this specific problem. It was quickly evident that the solution should be a company, owned by the oil companies themselves, which could dispense cash settlements to its members and fund itself through premiums. Some method had to be developed for sharing the potentially high losses among the members on an equitable basis. Rather than attempt to build a complicated rating scheme considering size, riskiness of assets, and construction-safety procedures the founders chose to allocate premiums on the simple basis of size, followed by modifications on the basis of individual members loss experience. This notion was simple enough to be workable and was deemed equitable by the group. The effective protection offered by O.I.L. is designed to cover the most important elements in the concept of corporation insurance. By providing for protection against cash drain and giving each member the ability to spread his losses over time, this group captive should prove to be a valuable tool to the insurance manager.
K-Factor Theory
Authors: Kaliappan C.S. , Rowe Allen M. 
Published: December 2007

Abstract
It is the purpose of this paper to outline the present state of art for determining K-factors, in particular those which apply to volatile oil and condensate fluids. Equations are presented that can be used to select K-factors for volatile fluids through convergence pressure calculations. These empirical pressure calculations. These empirical correlations can be used for calculating the K-factors for all the components in a mixture, at pressures greater than 0.7 times the convergence pressure. Relations are also presented to compute the K-factors of C+7 presented to compute the K-factors of C+7 fraction as a function of molecular weight, convergence pressure, and the operating pressure. Pressure-temperature phage envelopes pressure. Pressure-temperature phage envelopes are presented for four multicomponent hydrocarbon mixtures that were used in validating the proposed correlations in this paper. proposed correlations in this paper. The current limitation of the equation of state approach for calculating K-factors for volatile fluids is demonstrated through phase diagrams.

Introduction
The U. S. is currently faced with an energy shortage that has resulted in deep-well exploratory drilling (down to 28,000 ft). Reservoirs discovered at these greater depths are more likely to contain volatile fluids, since the reservoir pressure and temperature are higher than those presently being produced at more shallow depths. Due to the nature of these fluids, the ability to calculate reservoir performance and thus predict recoverable performance and thus predict recoverable reserves will, in part, require the accurate determination of their phase compositions and accurate predictions of the densities of the equilibrium phases. The phase composition calculation results in mass conservation, while an accurate phase-density calculation results in the conservation of pore volume. This paper is concerned with the former problem, the accurate determination of the phase compositions at various stages of reservoir depletion. In turn, the calculation of phase compositions requires accurate K-factors. These K-factors are particularly difficult to determine for volatile particularly difficult to determine for volatile reservoir fluids, especially near the critical state.
A Laboratory Investigation of Miscible Displacement by Carbon Dioxide
Authors: Rathmell J.J. , Stalkup F.I. , Hassinger R.C. 
Published: December 2007

Abstract
We have conducted displacements of reconstituted reservoir fluids in Boise outcrop sandstone cores of 6 to 42.5 ft in length using CO2 at various pressures. Our studies indicate that a miscible displacement may be achieved by CO2 injection at pressures well below those necessary when methane is the injection fluid. Miscibility by CO2 is generated through multiple contact equilibria in which the CO2 is progressively enriched with intermediates progressively enriched with intermediates (ethane through hexane) from the oil.
The miscibility pressure for CO2 and a given reservoir fluid is difficult to determine because CO2 exhibits highly efficient swelling and vaporization of the oil. We also found it impractical to operate below the rates where differences in density between displaced and displacing fluids prevent viscous fingering in vertical cores. We were able to define the miscibility pressure using the anticipated increasing recovery as a function of core length in miscible displacements in combination with effluent fluid visual cell observations and chromatographic data.

Introduction
Miscible displacement processes in petroleum reservoirs fall generally into two classes:
(1) processes in which the injected fluid and in-place fluid form a single-phase solution for all compositions and
(2) processes in which the injected fluid and in-place fluid do not on a single equilibrium contact form a single-phase solution over most of the range of possible compositions, but which may generate a zone of contiguous single-phase compositions by multiple contact mass transfer of components between the injected and in-place fluids.
Processes in Class 1 are sometimes characterized as having first contact miscibility; one example of such a process is the propane slug process. There are two important types of Class 2 processes, the enriched gas-drive process and the high-pressure gas process. In the enriched gas-drive process the injected gas contains methane and intermediate hydrocarbons, usually ethane, propane and butanes. These intermediate hydrocarbons dissolve in the oil, enriching it to the point where it becomes miscible with the injected gas. Miscibility in the high-pressure gas process is generated by transfer of intermediates, ethane through hexane, from the reservoir fluid into the injected lean gas. The enriched gas-drive process and the high-pressure gas process are both characterized at pressures where miscibility is possible by an initial period of immiscible displacement until sufficient mass transfer of intermediates has occurred to satisfy the requirement for miscibility.
Addressing BHA Whirl - The Culprit in Mobile Bay
Authors: Mason J.S. , Sprawls Mike 
Published: December 2007

SPE and IADC Members

Abstract
Lateral BHA (Bottom Hole Assembly) vibration, more particularly BHA whirl, is known to be an extremely destructive downhole phenomenon, the occurrence of which is thought to be one of the primary contributing factors to drillstring failure in Mobile Bay.
Unfortunately, indications that BHA whirl is occurring while drilling are rarely evident from conventional surface measurements, especially in deeper sections of wells. Without knowledge of the existence of a problem, avoidance is almost impossible.
For the first time, the potential for the surface identification of BHA whirl is thought to be possible through the measurement of drillstring vibrations. This paper presents data from a well in Mobile Bay where surface vibration measurement and monitoring was conducted while drilling the 12 1/4" hole section.
Axial and torsional data demonstrate characteristics thought to be indicative of BHA whirl which is shown to be associated with accelerated drillstring fatigue, as demonstrated by BHA failures. Various approaches were taken to eliminate the whirl once the phenomenon was recognized, with ultimate success in that the incidence of BHA failure was reduced. Pre-well planning and improved drilling practices resulted in the use of fewer bits and reduced drilling time over the same section on wells previously drilled in the area.

Introduction
Mobile Bay is situated in the Gulf of Mexico off the coast of Alabama and Mississippi (Fig 1), and has acquired a reputation as a harsh drilling environment. Several operators have experienced problems in drilling Norphlet wells in this area. A variety of problems has been encountered throughout these wells, and probably the most problematic phase has been the intermediate section. Numerous drillstring component and bit failures have been experienced while drilling the intermediate section throughout the area. The intermediate section of a typical Mobile Bay well involves drilling from around 6,000 to 18,000 ft.
One operator having drilled five wells in five blocks in the northwest sector of the area encountered drillstring failures throughout the program, with the most severe problems being on the well drilled in Block 916. The intermediate hole size on this particular well was 13 1/2" as opposed to 12 1/4" on earlier wells. During the drilling of the section, numerous failures were experienced which included a twistoff, nine washouts, two broken jars, 34 cracked boxes and five cracked pins.
While there was only one twist off there were several 'near misses' in that cracks in excess of 180 degrees occurred in jars and crossovers. These failures occurred despite a rigorous inspection schedule during which numerous galled and damaged threads were detected in addition to cracked boxes and pins. Other problems encountered were lost cones from three bits and eccentric wear to drillpipe.
P. 19
The Specification, Design and Construction of Rig 200
Authors: Meakin Chris , Hampton Sam , Quintero Alan 
Published: December 2007

Abstract
A state-of-the-art mechanized drilling rig has been built to drill development wells on the West Tuna platform, Australia's first concrete gravity structure.
This paper discusses how early attention to the design philosophy, effort in preparing the specification, early involvement of operations personnel, and close co-operation between Esso and AOWT during the rig design and fabrication resulted in a cost effective rig.
The paper describes innovations to the base design of the pipe racking system and the integrated driller's cabin (from which equipment can be remotely controlled), and the use of techniques such as HAZOPs, human-machine interface and ergonomic studies. Special attention is paid to design enhancement on the rig floor.
Drilling Directional Holes Having Constant Curvature
Authors: Dareing D.W. 
Published: December 2007

Introduction
It is sometimes desirable, when drilling for oil and gas, to drill away from the vertical so that the bottom end of the wellbore is at a given horizontal distance from the vertical. These wells are called directional wells and are drilled from offshore platforms to reduce the number of offshore structures in a particular oil or gas field. At the present, directional wells are drilled somewhat by trial-and-error, i.e., measurements of drill bit orientation are made periodically and appropriate changes are made in weight on the drill bit to increase or decrease the orientation of the bit. Stabilizers are also used near the bit to control the rate of hole deviation from the vertical.
There are several articles in the literature which discuss directional drilling (and hole deviation, crooked holes, dog-legs, etc.); however, except for very few technical papers, most of the publications are general discussions of the directional drilling problem. A literature survey indicated there are very few, if any, technical publications that relate drilling variables to wellbore curvature.
In 1968, the API funded a 3-year research project (API Research Project 107) at the U. of project (API Research Project 107) at the U. of Arkansas to study a directional-drilling concept proposed by the author. The directional-drilling proposed by the author. The directional-drilling concept is based on the premise that a wellbore, having constant curvature, will be drilled if the curvature of the drill collars directly above the bit is constant while drilling the hole; the deflection of the drill collars directly above the bit is a circular arc. The concept presupposes that the bit will drill in the direction it is pointing. The direction of the bit is controlled pointing. The direction of the bit is controlled by collar deflection that, in turn, depends on collar design and bit force. The research began by developing and solving a nonlinear differential equation of bending, which leads to collar design data. This phase was followed by an experimental phase, designed to verify the premise mentioned above. This paper summarizes premise mentioned above. This paper summarizes the results from the 3-year API project. The experimental work is presented first and is followed by the bending theory.

LABORATORY DRILLING RIG
A laboratory drilling rig (Fig. 1) was designed and built to experimentally verify the directional-drilling concept mentioned above.
Tide Flow: A Low Rate Density Driven Cementing Technique for Highly Deviated Wells
Authors: Kroken W. , Sjåholm Å. J. , Olsen A. S. 
Published: December 2007

Abstract
Over the last five to ten years the oil industry has undergone major changes. Increased focus on increased recovery has led to the development of techniques aimed at achieving longer, highly deviated and horizontal wells which penetrate several targets in a given reservoir.
This paper outlines an alternative cementing technique to the more common turbulent or effective laminar placements and describes two cases where this technique were used at the Gullfaks Field. By using of the density difference between the displaced and the displacing fluids, the mud in the narrow part of the annulus will float up into the wide part of the annulus and be carried away. The effect will be optimised with the use of a low pumping rate, which improves the ability of the fluids to exchange. This technique can be more cost effective than stage-cementing or increasing the hole diameter.
This technique is recommended when turbulent or effective laminar displacement is difficult.
How a 23000' MD Extended Reach Horizontal Well was Drilled in Less Than 24 Days
Authors: Omsberg N. P. , Morgan D. R. 
Published: December 2007

Abstract
From spud to TD, the Joanne 30/7a-Pl 1 well was drilled to a measured depth of 23,035' in 23.65 days. This extraordinary performance was achieved despite a 1600' sidetrack in an upper hole section. Adding time for skidding over the well slot, logging the reservoir interval, running and cementing the production liner and suspending the well brought the total time on the well to 31.65 days. The horizontal displacement for this extended reach well is 18,560', including a 4287' horizontal section in the thin Palaeocene Andrew sand reservoir.
PI 1 was the eleventh well drilled on the Judy template using the Santa Fe Galaxy jack up drilling rig in Phillips J-Block development The drilling program featured a diligent and continuous search for methods to improve performance. This resulted in the implementation of several innovations during the course of the project A continuous improvement trend was clear throughout the template drilling project culminating in the PI 1 well. Several world records were set while drilling this well, including the 24 hour footage and total footage in a single run.
This paper will present the techniques used in the P11 well to show how the impressive result was achieved.
Integrated Geologic, Engineering, and Financial Assessment of Gas Displacement Recovery in Texas
Authors: Beike D. K. , Holtz M. H. 
Published: December 2007

Abstract
A total of 57 commercially viable gas-displacement projects in Texas are classified into seven depositional environments. We collected reservoir and petrophysical data and depth and oil gravity for each reservoir, which gave us a generalized case model for each depositional environment. We also collected and analyzed information about the design of these projects, concentrating on pattern, spacing, and production processes previously applied.
Cost calculations that are presented are in accordance with a previous cost study by Beike and Holtz.1 Finances were analyzed for the case model of each depositional system according to net present value and internal rate of return. We also used an economic sensitivity analysis to investigate the effect of oil price, well spacing, and incremental recovery.
The potential for reserve additions from CO2 flooding in Texas is substantial. An additional 1,730 reservoirs are candidates for gas-displacement recovery. This set of reservoirs contains 70 BSTB of original oil in place, 23 BSTB of mobile oil, and 37 BSTB of residual oil. Factoring in a conservative reserve growth recovery of an additional 10 percent of original oil in place, we estimate that future GDR projects could produce 7 BSTB in Texas. Most of this reserve growth will continue to come from restricted to open-platform carbonate reservoirs in West Texas.
A New Method of Obtaining Injection Profiles in Short Radius Horizontal Wells
Authors: Wallace T. F. , Garrett K. D. , Guillot S. N. 
Published: December 2007

Abstract
An oxygen activation log was modified for use in obtaining injection profile sun'eys in four short radius horizontal injection wells. The tool was run inside a workstring that was temporarily placed in the lateral. Injection was established down the well annulus and the tool measured flow rates at points in the annulus between the workstring and open hole lateral. From this data, a distribution of injection along the lateral could be determined. Three different stimulation techniques were used on the horizontal wells and the profile results provided valuable insight into the effectiveness of these techniques.