bluuebunny/crossref_metadata_2025_split huggingface dataset:
Motion and Load Prediction of Floating Pipelaying Equipment
Authors: Minkenberg H.L. , Gie Tan Seng 
Published: December 2007

In predicting the motions and loads of floating pipelaying equipment - varying from conventional barges to large, highly sophisticated semisubmersibles - several mathematical methods and model experimental techniques are available. This paper reviews the various mathematical methods and correlates the results with model test and prototype data.

Introduction
The concept of a floating barge being a stable floating unit for carrying pipelaying equipment offshore was introduced in 1956. In 1978, the first offshore pipelaying barge, the L.E. Minor, was operated. The pipeline was lowered from the barge to the seafloor using long submerged floating units. By controlling the buoyancy of these units, the required sloping launchway was obtained. Tension was applied only to prevent slipping of the pipeline. The length of such stingers was two to three times the water depth. Stingers up to about 1,000 ft long with a weight up to 250 tons were used. In deeper water and less-sheltered areas, however, stingers of such length and weight became a real problem, especially because of the very large moments generated about the attachment point to the barge. By the introduction of the curves stinger in combination with large axial tensions applied to the pipeline on the barge, the sagbend could be limited so that laying in greater water depth became possible. Allowing a stress level of about 80% of the yielded stress during the laying operations resulted in considerably shorter stingers. Hence, the very large moments about the attachment point to the barge were reduced, which made work in rougher sea conditions possible. Generally, however, the laying techniques themselves hardly changed.
The hull configuration of the unit supporting the pipelaying equipment has varied considerably during the last 10 years. Ship-shaped vessels, small semisubmersibles, and large semisubmersibles with sophisticated pipelaying-controlling systems were developed and taken into operation, in addition to conventional flat-bottom barges. The choice of the type of construction is determined mainly by the following parameters1–3:operational area (worldwide or some specific area - e.g., North Sea, Gulf of Mexico),water depth,size of pipelines (storage capacity, deck area),seabed condition,sea surface condition (workable days, survival capability, stability), andinvestment.
Due to high development and operating costs of pipelaying barges, it is important to consider the various possibilities in early stage. Sea surface conditions and, thus, the hydrodynamic aspects of the various concepts play an important role in the selection of the final concept. The waves, wind, and current acting on the floating pipelaying structure determine mainly whether motions and forces become too large so that the laying activities have to be stopped. The rougher the sea conditions in which it is possible to work, the more time will be available for productive pipelaying in a given season.
Semi-Analytical Well Model of Horizontal Wells With Multiple Hydraulic Fractures
Authors: Wan J. , Aziz K. 
Published: December 2007

SummaryA well model is required to relate the well rate to the well pressure and the wellblock pressure while modeling wells in reservoir simulators. The well index is calculated automatically by simulators for conventional wells, but it is generally calculated by the user and supplied in the input while modeling nonconventional wells when the default procedure available in commercial simulators is not adequate.In this paper we describe a new semi-analytical solution for horizontal wells with multiple fractures. The fractures can be rotated at any horizontal angle to the well, and they need not fully penetrate the formation in the vertical direction. This solution for hydraulically fractured wells is obtained by applying Fourier analysis to a 2D solution; therefore, this solution is easy to obtain when the 2D solution is available. The analytical solution provides the well pressure that can be combined with a numerically computed gridblock pressure to obtain the well index (WI). Results of our rigorous solution are compared with empirical approaches currently in use for calculating the well index and the productivity index. Examples are given when horizontal wells with fractures are modeled using our new approach and conventional methods. These results demonstrate the need for computing the correct WI.
A Study of the Orifice Well Tester and Critical Flow Prover
Authors: Lesem Louis B. , McKetta John J. , Fancher George H. 
Published: December 2007

Introduction
The proration of oil produced in the field frequently is based partially or entirely upon the gas-oil ratio of wells. The measurement of the gas-oil ratio is one of the more important field tests in regulatory and proration work, and the test always should be conducted according to standardized methods and procedure.
Obviously, the gas-oil ratio and the volume of gas produced by a well depend upon many factors but should be independent of the method of measurement and of the devices used to measure gas and oil. Consequently, the volume of gas accompanying a barrel of oil produced by a well may be measured by any reliable and accurate device or instrument. Frequently either a critical flow prover or an orifice well tester is used for this purpose, and for a particular well the same rate of flow of gas should be obtained regardless of whether a critical flow prover or an orifice well tester is employed in the test.
In Texas, when using either instrument, either Capacity Table 1 or 5 is employed in making the necessary computations. If the tables are used, a discrepancy always is found whenever the two instruments are compared by extrapolation to the same conditions of flow. Clearly, Tables 1 and 5 must be at fault in some respects.
The orifice well tester and the Bureau of Mines type of critical flow prover are essentially the same instrument; both devices utilize a square-edged orifice 1/8 in. in diameter as the primary element, and both freely discharge gas to the atmosphere.
Tables for the orifice well tester have been published in the ranges of 0 to 15 in. of water and 0 to 40 in. of mercury (Hg) differential in pressure. Coefficients for the critical flow prover have been published for differentials in pressure greater than 75 psia.
Pressure Buildup Analysis With Wellbore Phase Redistribution
Authors: Fair Walter B. 
Published: December 2007

Abstract
This paper presents an analysis of the effects of wellbore phase redistribution on pressure buildup tests. Wellbore phase redistribution is shown to be a wellbore storage effect and is incorporated mathematically into a new solution of the diffusivity equation. Dimensionless pressure solutions based on an infinite radial reservoir are presented for type-curve matching to analyze pressure buildup tests influenced by wellbore phase redistribution, and example analyses of actual field data are included. The parameters that affect phase redistribution and gas humping are documented also. This information permits analysis of many anomalous pressure buildup tests which previously could not be analyzed quantitatively.
One-Step Furfuryl Alcohol Process for Formation Plugging
Authors: Hess Patrick H. 
Published: December 2007

A one-step furfuryl alcohol resin process has been developed for selective plugging in injection and production wells. Of 36 economic small-volume applications, 28 were successful in achieving permanent plugging. The process is especially useful in steam injection wells. The "chemical clock" catalyst system ensures a controllable, predictable gel time over a wide range of formation temperatures.

Introduction
Furfuryl alcohol (FA) resins are proving to be most useful in oilfield operations. When acidified, these liquids undergo rapid polymerizations to form hard, black, chemically resistant, thermally stable, thermosetting polymers. These polymers are the basis of previously described two-step sand consolidation, and formation plugging processes where either the FA or acid catalyst is placed in the formation first, followed by the other chemical; the chemicals mix, and the polymerization takes place. Generally, two steps with an intermediate spacer have been necessary because the solution rapidly solidifies when the FA and acid mix, whether in the formation, tubing, or pump.
This paper describes a one-step FA process that overcomes the usual problems encountered with a two-step process. This process uses an FA system where, before pumping, the FA and catalyst are mixed to form a solution with a predictable minimum gel time (gel time is the time from mixing until the viscosity has built to the point where the fluid is no longer readily pumpable). Once the gel time is exceeded, the polymerization proceeds rapidly to the fully cured FA (furan) polymer.

Acidic Catalysts
There are three major obstacles to achieving predictable, reproducible FA gel times by adding acidic catalysts directly to the resin:sensitivities to catalyst concentration,reaction temperature, andFA batch history.
The first two problems are illustrated in Fig. 1. Gel times for most polymerizing systems generally decrease with increasing catalyst concentration. This effect is quite pronounced in FA systems. To achieve predictable gel times with acidic catalysts requires accurate measurement of chemical volumes and rapid mixing, difficult requirements under field conditions. Also, to have a reasonable working life, the acid concentration must be so low that a "catalyst-starved" FA system can exist. The resulting polymerization may be benign and occur over a prolonged time span (and quite possibly never reach a high degree of cure). It is more desirable that once the polymerization starts it goes rapidly, with a high exotherm, to the final fully cured state.The temperature effect illustrated in Fig. 1 shows that FA polymerizations, as most chemical reactions, go faster with increasing temperatures. A 2-hour gel time for a given catalyst concentration at room temperature may only be 20 minutes at 140 degrees F (60 degrees C).FA batch history is the third problem. Freshly distilled FA is neutral, but with time and oxygen some of the FA will oxidize to complex acids and lower the pH.
JPT
P. 1834＾
Explosive Fracture Studies on Oil Shale
Authors: Grady Dennis E. , Kipp Marlin E. , Smith Carl S. 
Published: December 2007

Abstract
Fracture, fragmentation, and/or enhanced permeability through explosive methods can be difficult to achieve in the often restricted environment demanded of in-situ resource recovery methods. Blasting within confined volumes and the need for uniform fragment size and permeability adds a dimension for which a history of blasting experience is not available. Computer modeling offers a potential tool for rapid evaluation and optimization of the explosive and geometry parameters. This study deals with intermediate-scale explosive blasting tests within confined volumes that have been conducted on blocks of oil shale to evaluate a computational fracture model under realistic loading conditions. The blocks were instrumented with stress gauges in the material to determine the dynamic stress field induced by the explosion. The blocks were recovered, stabilized, and sectioned after testing to measure the extent of damage and fragment-size distribution. Both stress-wave and fragment-size data were compared with numerical computations.
Shear Wave Velocities Determined From Long- and Short-Spaced Borehole Acoustic Devices
Authors: Koerperich E. A. 
Published: December 2007

Abstract
Acoustic waveforms from long- and short-spaced sonic logs were investigated to determine if shortspaced tools give accurate measurements of shear wave velocity. Compressional wave interference can affect shear velocities from both tools adversely. However, the short-spaced tool was useful over a wider range of conditions.
Case History of Successfully Water Flooding a Fractured Sandstone
Authors: Rausch R.W. , Beaver K.W. 
Published: December 2007

Abstract
By 1955, the First Wall Creek reservoir had reached the stripper stage. At that time a 20-acre double five-spot pilot was started to evaluate waterflood feasibility. Injected water was lost from the pilot area through natural fractures, and the five-spots were not encouraging. However, wells outside the five-spots showed production increases, so the pilot area was expanded to include about 100 acres. The expansion proved highly successful, and a full-scale program is now underway. Sand-oil fracture treatments have contributed to the success of the project.
Introduction
The geology and history of the Salt Creek field, Salt Creek, Wyo., have been described previously. The First Wall Creek pool under consideration here was discovered in 1908 and is one of 11 productive zones found on the Salt Creek anticline. The pool is cut by numerous normal faults of small displacement. Fig. 1 is a field map. Many of the smaller faults have been omitted in this figure. There are surface indications which suggest that some of these faults may be sealed by secondary deposits of calcite. The First Wall Creek pay zone, found at an average depth of 900 ft, is a fine- to medium-grained sand with numerous thin shale partings. Porosity and permeability are locally erratic, and average 15 per cent and 80 md, respectively. Gross thickness of the section averages 120 ft, of which about two-thirds is net pay and the remainder is shale. Core analyses indicate local zones of high permeability, usually near the base of the section. Injectivity profiles from spinner surveys show that extensive natural fracturing is present in some areas, and as a result, matrix permeability does not necessarily determine points of fluid entry into the wellbore. The produced crude is paraffin base, 38 gravity, having an estimated original solution GOR of 550 cu ft/bbl. The northern two-thirds of the Salt Creek field, including all of the First Wall Creek pool, was unitized in 1939, with the Midwest Oil Corp. as unit operator. Pan American Petroleum Corp. conducts the field operations for the unit owners on a contract basis. Sixty-eight companies and individuals are working interest owners in the unit.
Gas Injection
A gas-drive project was started in the Second Wall Creek pool, Salt Creek's largest reservoir, in 1926. This project was successfulit is still in operationso a similar program was attempted in the First Wall Creek starting in 1927. Maximum available surface injection pressure was only 350 psi, and most of the First Wall Creek wells would not take gas at economically significant rates with this injection pressure, so no measurable production benefit was obtained. Injections were nonetheless continued until 1949 to avoid flaring gas. A total of about 2 billion cu ft was injected in 22 years.
JPT
P. 1233ˆ
A Conjugate Gradient-Truncated Direct Method for the Iterative Solution of the Reservoir Simulation Pressure Equation
Authors: Watts James W. 
Published: December 2007

Abstract
This paper describes a way of solving the reservoir simulation pressure equation using preconditioned conjugate gradients. The preconditioning is based on an approximate inverse using a diagonal ordering of the difference equations.
The new method has been tested and compared with the strongly implicit procedure (SIP) on a number of problems in both two and three dimensions. In two dimensions, it is generally faster than SIP; in three dimensions, it is much slower than SIP when SIP works well but can be many times faster than SIP when SIP works poorly.
Use of the new method generally does not require the selection of an iteration parameter, which is a significant advantage over SIP. Furthermore, it is much more reliable than SIP. In other words, it is far less likely to be unable to solve a given problem than SIP is.
Contact Angles for Equilibrated Microemulsion Systems
Authors: Reed Ronald L. , Healy Robert N. 
Published: December 2007

Abstract
Advanced and receded contact angles have been measured on various high- and low-energy substrates as functions of microemulsion-excess phase interfacial tensions (IFT’s). Many experimental difficulties peculiar to these low-tension systems caused large measurement errors. But with this constraint and with one exception, contact angles were hysteresis-free and independent of the substrate.
For lower-phase microemulsions and high-energy substrates, it is proposed that the surfactant polar group adsorbs on the solid and then a surfactant bilayer forms. This bilayer provides the effective substrate that relates to contact angle and IFT’s through Young’s equation.
An optimal salinity for contact angles is defined and related to previously introduced optimal salinities, in particular to that associated with best oil recovery. Results suggest the optimum attainable contact angles for microemulsion-based oil recovery may not be 0°.
Stratification Testing Results in Revised Concept of Reservoir Drive Mechanism, University Block 13 Ellenburger Field
Authors: Ader Joseph C. 
Published: December 2007

Stratification testing in late 1977 proved that water coning is not operative through the Middle Ellenburger zone in the University Block 13 Ellenburger field in Andrews County, TX. The ensuing deepening and development drilling program has proved the existence of deeper reserves and has revised the plan of depletion for this field.

Introduction
The Ellenburger horizon in west Texas was deposited in a shallow marine environment nearly 500 million years ago during the early Ordovician period. The end of the Ellenburger deposition was marked by folding, faulting, and erosional activity. Extensive geological analysis of cores, drill cuttings, logs, and insoluble residue analysis data has shown that the Ellenburger may be divided into distinct upper, middle, and lower zones. Historically, most Ellenburger reservoirs were assumed to have an active bottomwater-drive producing mechanism, with vertical fractures through the thick carbonate being responsible for the vertical fluid movement. Consequently, numerous Ellenburger reservoirs were developed with a majority of the wells completed at or very near the top of the formation to prolong water-free production and minimize the water coning problem associated with an active bottomwater-drive mechanism.Since its discovery in 1960, the University Block 13 Ellenburger field, a west Texas carbonate reservoir found at a depth of approximately 11,000 ft (3353 m), was considered to have a bottomwater-drive mechanism; consequently, completions had been made only in the top of the Upper Ellenburger to minimize water coning as long as possible and to maximize recovery. When the four upstructure Ellenburger wells began producing water in 1977, approximately 8 years earlier than predicted by previous flood-out analysis, a testing program was initiated to determine whether aggravated coning through 140 to 240 ft (43 to 73 m) of oil column or edgewater encroachment through the Upper Ellenburger was responsible for early water production.Special testing, workover, and development drilling activity has resulted in a revised concept of the reservoir drive mechanism in this field. Stratification testing in late 1977 proved that water coning is not operative through the Middle Ellenburger in this reservoir and that the Ellenburger may be divided into upper, middle, and lower zones with restricted vertical communication between zones. To date, four of six deepenings and two development wells have been completed successfully at or near field top allowable of 285 BOPD (45 m3/d oil) per well in the Middle or Lower Ellenburger zones to recover reserves that may have been trapped under former completion practices.Various techniques have been used to evaluate zonation of the Ellenburger in this field. These geological techniques, along with various reservoir analyses, may aid in identifying potential deep zone reserves in other west Texas Ellenburger reservoirs.
JPT
P. 1452
Improved Reservoir CharacterizationA Key to Future Reservoir Management for the West Seminole San Andres Unit
Authors: Harpole Kenneth J. 
Published: December 2007

A comprehensive reservoir study using a black-oil simulation model showedthat control of vertical movement of oil into the gas cap under waterfloodoperations was the key to maximizing oil recovery from this west TexasSan Andres reservoir. Recovery of an additional 4 MMSTB of oil isexpected as a result of a reservoir management plan which includes a46-well infill drilling program.

Introduction
Improved reservoir description is becomingrecognized as an essential requirement for effectivereservoir management. This is particularly important for the extremely heterogeneous, geologicallycomplex San Andres carbonate reservoirs of westTexas. The West Seminole field in west centralGaines County, TX, (Fig. 1) produces from the SanAndres formation at an average depth ofapproximately 5,100 ft. Fig. 2a shows the generalstructural configuration of the reservoir; it consistsof a large main dome with a smaller dome structureto the east. A large primary gas cap, shownschematically in Fig. 2b, covers most of the fieldarea. A summary of basic reservoir and fluid data ispresented in Table 1.
Throughout the field's producing life, there hasbeen a question about the extent of verticalcommunication within the reservoir, particularly betweenthe oil zone and the overlying gas cap. This questionbecame a critical operating consideration when apattern waterflood was proposed in the early 1970's.An extensive reservoir study was undertaken topredict the future production performance of thefield under waterflood operations.
The overall objective of this study was to developthe most profitable and effective reservoir managementprogram for the West Seminole San Andres Unit. Thefollowing specific objectives and procedures weredeveloped for the work.Use all available geologic and engineering datato develop a detailed and accurate reservoirdescription for this field.Incorporate the reservoir descriptioninformation into a black-oil computer simulationmodel. Use the simulator to verify and further refine the reservoir description by history matching thepressure and production data.Use the history-matched simulation model toproject future reservoir performance under currentwaterflood operations.Evaluate various alternative operating plans andrecommend the most effective reservoir managementprogram for the unit.
JPT
P. 2009＾
A Robust Iterative Method for Flash Calculations Using the Soave-Redlich-Kwong or the Peng-Robinson Equation of State
Authors: Nghiem L. X. , Aziz K. , Li Y. K. 
Published: December 2007

Abstract
A robust algorithm for flash calculations that uses an equation of state (EOS) is presented. It first uses a special version of the successive substitution (SS) method and switches to Powell's method if poor convergence is observed. Criteria are established for an efficient switch from one method to the other. Experience shows that this method converges near the critical point and also detects the single-phase region without computing the saturation pressure. The Soave-Redlich-Kwong1 (SRK) and the Peng-Robinson2 (PR) EOS's are used in this work, but the method is general and applies to any EOS.