bluuebunny/crossref_metadata_2025_split huggingface dataset:
The U.K. Offshore Operators' Response to the Piper Alpha Disaster
Authors: Taylor B.G.S. 
Published: December 2007

Summary
This paper describes the U.K. government's inquiry into the Piper Alpha disaster and examines one organization's response to recommendations from that inquiry.

Introduction
Immediately after the July 1988 Piper Alpha disaster, U.K. offshore operating companies reviewed their "software" procedures, such as permits to work, and initiated "hardware" changes based on lessons learned from the disaster. These included provision for and siting of emergency shutdown valves, subsea isolation systems, prevention of smoke ingress to accommodations, provision for better marking and screening of emergency walkways, and improved firefighting systems.
The government inquiry into Piper Alpha, headed by Lord Cullen, was given two tasks: to determine the cause of the disaster and to recommend how similar disasters could be prevented. The U.K. Offshore Operators Assn. Ltd. (UKOOA) contributed to the second task by providing the majority of expert witnesses.
Lord Cullen's report recommended sweeping changes to the U.K. regulatory regime and listed 106 specific recommendations for consideration by government and industry. UKOOA immediately endorsed the recommendations, is monitoring their implementation, and is coordinating the industry studies needed to support a number of them.

Background
UKOOA represents the 36 oil and gas companies designated operators of licenses on the U.K. continental shelf. Its main objectives are to provide an industry forum for discussion of matters of mutual interest to its members and, as appropriate, to provide the industry with a means of communication with the U.K. government and other relevant bodies. Its strength lies in the work of its committees. Volunteers from UKOOA's member companies comprise the 40 permanent committees and subcommittees.
The Piper Alpha disaster shocked the industry and the general public. In the aftermath of the personal tragedies came the inevitable self-examination and uncertainty. The designs and operating procedures, which for so long had been considered dependable and safe, now looked vulnerable. What had gone wrong? What could be done to prevent a similar accident?
Improved Simultaneous Determination of Formation Properties from Well Logs
Authors: Roper William A. , Jones Vaughn A. 
Published: December 2007

A well log computation technique, similar to one developed earlier, can be used to differentiate the separate contributions of many possible minerals. The scheme may be extended to include the possible minerals. The scheme may be extended to include the effects of resistivity tools as they relate to porosity and saturation.

Introduction
The successful application of computer log analysis to the Chaveroo field by Burke, Curts, and Cox stimulated our interest in this method. The modification of their method, which is presented here, has been used successfully by Getty Oil Co. in the analysis of logs from several fields.
For both methods a set of simultaneous equations relating log response to formation composition is solved for the fractions of each component present. The method presented here allows inclusion of geological information and an arbitrary number of logs. As will be shown, the present method allows greater flexibility and control than the previous method of Burke et al.
To assist in visualizing, the mathematical relationships are supplemented by a graphical analogy. In the text of the paper, the solution process is discussed in terms of this graphical analogy. Computational aspects of the solution are described in the Appendix.

Basis of Computation
The basic assumption employed by Burke et al. was that logged values can be represented as a linear equation of the form:
where Xa is the logged or measured value of some property of a mixture containing n components. i property of a mixture containing n components. i is the fraction of component i in the mixture, and Xi is the property value assigned to a pure component i.
For example, if a formation is water-filled dolomite, the logged sonic transit time may be represented by
where
w + D = 1.
If the sonic transit times in water ( tw) and dolomite ( tD) are known, the fractions of water ( w) and dolomite (0D) can be calculated.
If the solid matrix is a mixture of dolomite and gypsum, and if sonic and neutron-porosity logs are available, the fractions of water, dolomite, and gypsum can be obtained by solving the following set of simultaneous equations:
Na = Nw w + ND 0D + NG 0G
ta = tw 0w + tD 0D + tG 0G
with the added restriction that all 0's must be positive. In these equations Na is the logged neutron positive. In these equations Na is the logged neutron porosity. porosity. The requirement of positive 's can be expressed conveniently in graphical form. In Fig. 1, pure component points are labeled W, D, and G, representing water, dolomite, and gypsum, respectively.
JPT
P. 827
Velocity-Porosity Logging in Volcanic Rocks
Authors: Carroll Roderick D. 
Published: December 2007

Abstract
Volcanic rocks exhibit a wide range in porosity and velocity and are an excellent medium for checking the time-average formula. An analysis of core porosity data and velocity logs from five wells at the Atomic Energy Commission's Nevada Test Site indicates that the time-average formula applies in these rocks. An equation with the constants tma = 54 sec/ft; tf = 189 sec/ft best fits the data. The close agreement of this equation with that generally assumed for sandstones suggests that in volcanic rock areas, where porosity-velocity data are lacking, existing interpretation charts for sandstones, relating sonic log travel time to porosity, may be applied to these rocks.

Introduction
The U. S. Geological Survey for several years has assisted the U. S. Atomic Energy Commission in evaluating rock media in the vicinity of underground nuclear detonations. The greater portion of this work has been concerned with volcanic rock sequences at the AEC's Nevada Test Site located in Nye County, Nev. In describing these media, physical properties play a large role, and a logical and necessary adjunct to these investigations has been the extensive use of wireline logs in exploratory wells. This paper concerns the use of velocity logs as a porosity-measuring tool in these volcanic rocks. porosity-measuring tool in these volcanic rocks. The use of velocity logs to determine porosity has generally been restricted to sandstones and carbonate rocks. This arises as a natural consequence of the favorable environment presented by these rocks for the accumulation of oil and gas. In the study of these rocks, Wyllie's time-average equation has been used widely.
Although volcanic rocks in general are not considered a favorable environment for petroleum, some instances have been reported of the location of oil in such rocks. Oil production has been reported from both a volcanic tuff and a welded tuff in the Eagle Springs field, Nye County, Nev., about 100 miles north of the Nevada Test Site.
Notwithstanding the poor suitability of volcanic rocks as a petroleum-producing medium, these rocks offer an excellent opportunity for testing the general applicability of Wyllie's equation because continuous sequences of saturated volcanic rock several thousand feet thick can be found in which porosity and velocity vary over broad ranges.
Influence of Pore Pressure on Drilling Response in Hard Shales
Authors: Gray-Stephens Douglas , Cook J. M. , Sheppard Michael C. 
Published: December 2007

Summary
Results are presented from laboratory drilling studies of two different hard shales similar to those found in some areas of the North Sea. Two laboratory drilling machines with milled-tooth bits were used. Pore pressure was measured in all the experiments, and in some it was reduced to several megapascals below bottomhole pressure (BHP). Pore-pressure reduction was achieved by allowing the pore fluid to drain out of the shale while external stresses were maintained constant. The influence of BHP was studied for values from 3 to 33 MPa [435 to 4,786 psi]. The differential pressure, which equals BHP minus pore pressure, ranged from near balance to &gt; 10 MPa [&gt; 1,450 psi]. BHP was found to have a strong influence on drilling response, but differential pressure did not, contrary to conventional wisdom. The results are compared with other drilling experiments and single-cutter experiments in the literature.
Laboratory Study Provides Guidelines for Diverting Acid With Foam
Authors: Thompson K. E. , Gdanskl R. D. 
Published: December 2007

Summary
A series of experiments was conducted in which foam quality, foam reactivity, diverting-stage volume, core permeability, and treatment design were varied. The goal was to determine how these parameters affect diversion in competing limestone cores. Situations involving natural permeability differences and diversion to damaged cores were considered. Experiments indicate that the minimum foam quality required for useful resistance to acid flow is 60%; foams of 70% or 80% quality were the most effective for diversion. Both acid and brine foams were used. Acid foams provide good diversion and can be included easily in a treatment, while in high-porosity, low-permeability limestones like chalk, brine foams appear to be more effective than acid foams. One can expect to maintain good diversion up to a permeability ratio of 10. Results also show that both types of foam effectively divert acid to damaged cores.
Density of Liquefied Natural Gas
Authors: Jensen Robert H. , Kurata Fred 
Published: December 2007

An experimentally derived tabular correlation for LNG density as a function of temperature, pressure, and gas gravity has been designed for use in the field. The advantages of this correlation are that a gas gravity analysis is more easily obtained than a composition analysis and that density is determined by direct interpolation of the gas gravity tables.

Introduction
Liquefied natural gas, LNG, is being handled in increasing quantities, and a reliable and convenient method of determining LNG density is desired. If a composition analysis is available, the correlations of Harmens and of Lyckman, Eckert, and Prausnitz may be used to calculate LNG density.
Harmens' correlation was developed for the density of pure light hydrocarbon liquids at saturation and for the density of mixtures of such hydrocarbons, particularly of LNG. In the correlation, Eq. 1 is used particularly of LNG. In the correlation, Eq. 1 is used to calculate liquid density:
(1) p = C * F ( Tr )
C and F(Tr) were tabulated by Harmens. C is an empirical density constant, and F(Tr) is Harmens generalized density function. Tr is reduced temperature, T/Tc. To apply the correlation to mixtures, mixing rules were given to compute C and Tc from mixture composition and pure component values.
In the correlation of Lyckman, Eckert, and Prausnitz, reduced saturated volume Vr is given as a Prausnitz, reduced saturated volume Vr is given as a quadratic function of acentric factor:
(2) (1) 2 (2)Vr = V/Vc = Vr(0) + wVr + w Vr (3) p = M / V ,
where V is molar volume, Vc is critical molar volume, and M is molecular weight. The generalized functions of reduced temperature, Vr(0), Vr(1), and Vr(2), were tabulated by Lyckman, et al., in the range Tr = 0.560 to Tr = 0.990. Chueh and Prausnitz fitted the tabulated values to Eq. 4 and provided the coefficients a (j) to f(j).
(4) ( j ) ( j ) ( j ) ( j ) 2 ( j ) 3Vr = a + b Tr + c Tr + d Tr ( j ) ( j ) + e / Tr + f ln ( 1 − Tr )
Eq. 4 is valid for reduced temperatures from 0.560 to 0.995. Mixing rules were suggested by Chueh and Prausnitz to calculate pseudocritical volume and Prausnitz to calculate pseudocritical volume and temperature, and mixture acentric factor, for application of the correlation to mixtures of known composition.
In using the foregoing correlations, a composition analysis is required, and mixture pseudo constants must be calculated. To provide an easier and quicker procedure for the man in the field, a study was procedure for the man in the field, a study was undertaken to correlate LNG density as a function of three measurable properties: temperature, pressure, and the gas gravity of gasified LNG. A technician can make these measurements routinely with commercially available equipment.

Theory
To derive the LNG density correlation, equations are required for computing ternary mixture compositions, gas gravities, and liquid densities at fixed temperatures and pressures.
JPT
P. 683
Degradation of Titanium Drillpipe From Corrosion and Wear
Authors: Ferg T. E. , Craig B. D. , Aldrich C. S. 
Published: December 2007

Summary
Drilling deeper than 35, 000 ft is limited by the extreme hook loads of steel drillpipe and temperature constraints of aluminum drillpipe. Titanium Alloys Ti-6A1-4V and Beta C have been proposed for use in drillpipe for wells deeper than 35, 000 ft because of their high strength/weight ratios, superior high-temperature corrosion resistance, and thermal stability. Their suitability in drilling environments, however, has not been evaluated. To determine the corrosion and wear characteristics of two types of titanium-alloy drillpipe under dogleg conditions, a test cell was constructed to test titanium drillpipe joints in contact with API Spec. 5CT Grade P-110 casing in different drilling muds. Titanium-alloy pipe and Grade P-110 casing wear rates were measured, and tests showed that both titanium-alloy pipes exhibited much greater wear than did steel drillpipe in water-based mud under the same conditions. Test data showed that the total wear rate of Alloys Ti-6A1-4V and Beta C in a drilling environment is a combination of mechanical wear and corrosion.
Effect of Multiple Hydraulic Fractures on Gas-Well Performance
Authors: Al-Hashim H.S. , Kissami Mimoune , Al-Yousef H.Y. 
Published: December 2007

Summary
This paper describes the use of a single-phase 2D numerical model to study the performance of a well intersected by two perpendicular vertical fractures assumed to have either infinite or finite conductivities. Analysis of the simulated drawdown tests at a constant flow rate showed that the transient flow behavior of a well intersected by finite-conductivity (CfD&lt;500) perpendicular fractures does not exhibit the bilinear and formation linear flow periods. However, when fracture conductivities were infinite (CfD =500), the formation linear flow period was observed. This period was used to determine the fracture half length and gave a fracture half-length equal to the sum of the two fracture half-lengths (xf + yf). The beginning of the pseudoradial flow period for any conductivity was found to decrease as yf/xf increased and to increase as the fracture conductivities increased for a given yf/xf. A single hydraulic fracture gave higher productivity than two fractures of the same total length when fracture conductivity was infinite. However, when fracture conductivity was low, the two fractures gave higher productivity than the single fracture.

Introduction
Hydraulic fracturing is an effective way to increase the productivity of wells producing from low-permeability formations. Considerable research has been conducted to determine the effect of hydraulic fractures on well performance and pressure-transient behavior. The results have been used to improve the design of hydraulic fractures.
The increasing use of hydraulic fracturing to improve the productivity of oil and gas wells in low-permeability reservoirs has resulted in many research efforts aimed at increasing fracturing capabilities and evaluating fracture characteristics in the postfracturing period.
The massive hydraulic fracturing (MHF) treatment is now a proven technique for developing commercial wells in low-permeability or tight gas formations. The purpose of MHF is to expose a large surface area of the low-permeability formation (in-situ permeability =0.1 md) to flow into the wellbore.
Over the past few decades, hydraulic fracturing and explosive shooting of wells have been used to improve the productivity of tight reservoirs. An alternative to these techniques, one that uses certain features of both but appears better for creating multiple fractures, is tailored-pulse loading.
Warpinski et al. in 1979 and Schmidt et al. in 1980 demonstrated that propellants can create multiple fractures in the field without damaging the wellbore region. Their results indicated that the long loading time of the pulse allows greater fracture extension and thus gives more opportunity for connecting a wellbore to the reservoir's natural fracture system.
Polymer Solution Flow in Porous Media
Authors: Harvey A. Herbert , Menzie D.E. 
Published: December 2007

Abstract
A method is described for the analysis of rate-dependent effects in the flow of polymer solutions through unconsolidated porous media. Experimental data are presented for solutions of polyacrylamide, polyethylene oxide, and polyacrylamide, polyethylene oxide, and polysaccharide.

Introduction
A major obstacle to wider use of polymer flooding seems to be the lack of a satisfactory method for predicting the performance of this oil recovery predicting the performance of this oil recovery process. Although it is frequently possible to process. Although it is frequently possible to predict that a polymer flood would recover more oil predict that a polymer flood would recover more oil from a reservoir than could be produced with a waterflood, it is difficult to make a realistic economic comparison of the two processes.
Waterflood prediction techniques which consider areal sweep and reservoir stratification have been used to evaluate the effect of improved mobility ratio on oil recovery. If accurate relative permeability data are available and if stratigraphic permeability data are available and if stratigraphic variations in the reservoir are known, then these prediction techniques may lead to a rough prediction techniques may lead to a rough approximation of the performance of a polymer flood. However, such prediction techniques fail to consider that the apparent flow resistance to a polymer solution depends on flow velocity as well polymer solution depends on flow velocity as well as permeability. These rate-dependent effects may be significant in a pattern flood, since fluid velocity is not constant. They may also be significant in a heterogeneous reservoir. Under favorable conditions some rate-dependent fluids will tend to even out the flood front in a stratified reservoir and thereby increase oil recovery. This effect cannot be anticipated with conventional waterflood prediction techniques.
The basis for much of the difficulty in predicting the performance of a polymer flood is a lack of understanding of the behavior of high molecular weight polymer solutions flowing through porous materials. Until we are able to predict how these solutions will flow through a simple system such as a glass bead pack, it seems unlikely that we will be able to develop a realistic mathematical model to describe the much more complex problem of flow in an oil reservoir.
It is the purpose of this study to develop a method for investigating the flow of these high molecular weight polymer solutions through unconsolidated porous media and to study the rheologic properties of solutions of certain polymers which, are of interest from the standpoint of possible application to polymer flooding.
A Systematic Approach for the Prevention and Treatment of Formation Damage Caused by Asphaltene Deposition
Authors: Leontaritis K. J. , Amaefule J. O. , Charles R. E. 
Published: December 2007

SummaryAsphaltene plugging is a known cause of near-wellbore formation damage. Deposited asphaltenes can reduce effective hydrocarbon mobility by (1) blocking the pore throats; (2) adsorbing onto the rock, thereby altering the formation wettability from water-wet to oil-wet; and (3) increasing hydrocarbon viscosity by nucleating water-in-oil emulsions. Asphaltene flocculation and deposition can be avoided in some, but not all, cases. Some formation damage resulting from asphaltene plugging is permanent and hence must be prevented rather than treated. Prevention of asphaltene-induced formation damage should be started in the early stages of drilling and well completion, once the oil is known to be asphaltenic.This paper presents a systematic approach to successful diagnosis, prevention, and mitigation of asphaltene problems during recovery of asphaltenic oils. A mechanism of asphaltene flocculation and deposition is proposed and analyzed, and the previously defined concept of asphaltene deposition envelope is further refined. Diagnostic technology is presented that can test the compatibility of drilling and completion fluids with any asphaltenic oil. Important issues that need to be considered in the design of treatments for asphaltene removal are discussed. Finally, the paper presents a methodology for restoring unfavorable wettability changes caused by asphaltene deposition.
Impairment by Suspended Solids Invasion: Testing and Prediction
Authors: Oort Eric van , van Velzen J. F. G. , Leerlooijer Klaas 
Published: December 2007

Summary
A new model was developed to predict wellbore impairment by internal filter-cake formation during water injection. In the model, formation damage is approached semiempirically; no assumptions were made with respect to the specific mechanism underlying impairment. Model constants, derived from linear core-flow experiments, were used to calculate radial flow damage. Radial coreflow experiments subsequently were carried out to validate the proposed model. Theory and experiment were in good agreement. This paper shows that the model can obtain realistic performance and half-life estimates for water injectors. During the experiments, a pronounced velocity effect on impairment rate was found. The extent of impairment increased by several orders of magnitude when injection dropped below a critical inflow velocity of 2 cm/min. The generally accepted : "⅓: 17 rule" (the particle/pore ratio for internal cake formation) is confirmed for inflow velocities exceeding 10 cm/min. At low injection velocities (&lt;2 cm/min), even smaller particles were found to cause increased damage: a "⅓: 114 rule" may be more applicable for such low inflow velocities.