bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Review of the Acoustic Determination of Liquid Levels in Gas Wells
Authors: Thomas Kent L. 
Published: December 2007

In a recent article by Andsager and Knapp, a new method was presented foracoustically determining liquid levels in natural gas wells. The methodconsists of generating a sound wave at the wellhead, and measuring the timerequired for the wave to travel to the liquid level and back to the wellhead. The depth of the liquid level then can be obtained by integrating therelationship between velocity, distance and time.
(Equation 1)
The accurate determination of liquid levels by this technique is necessarilydependent upon one's ability to predict acoustic velocities of natural gas as afunction of both temperature and pressure.
Starting from the equation of the speed of sound in a compressible fluid,
(Equation 2)
Andsager and Knapp derived the following equation for a real gas.
(Equation 3)
When Eq. 3 was tested against 42 sets of experimental data, they found thatthe predicted values were too low. The ratio of the predicted to experimentalvelocity in each case was approximately equal to the square root of the gascompressibility factor.
(Equation 4)
In evaluating Eq. 3 during the integration of Eq. 1, Andsager and Knapp usedgas compressibility factors based on AGA data and specific heats from theEngineering Data Book. In using these specific heats to calculate K, theauthors were assuming K (T, p) to be independent of pressure since thespecific heats listed in this reference were evaluated at atmospheric pressure. It appears, therefore, that for the conditions of the experiments reported intheir paper
(Equation 5).
Data from Edmister for methane bears out the validity of Eq. 5 over thepressure range shown in Table 1.
Andsager and Knapp should be commended for providing an excellent workingequation for calculating acoustic velocities for the pressure range for whichEq. 5 is valid. Eq. 4, however, should be used with caution at high pressuresor in the neighborhood of the critical point of a gas since the approximationshown as Eq. 5 becomes invalid in these regions.
Gas Prices and Gas Volumes The Current Posture
Authors: Jacobs John C. 
Published: December 2007

By 1990, the U.S. demand for gas could fall short of the supply by as much as 8 trillion cubic feet. Given proper governmental regulation, this supply could be met by importing liquefied natural gas or by gasifying coal, lignite and oil shade.

Introduction
Natural gas has become the single most important fuel produced in the U.S., and the use of it in other parts produced in the U.S., and the use of it in other parts of the world is increasing rapidly. This form of energy is the subject of far-reaching decisions in business, financial and governmental circles, and the continuation of its importance among fuels rests upon the supply available. Supply, in turn, resolves into a physical availability component (how much is there?) and a market incentive component (how much will users be allowed to pay?).
It is the burden of this paper to show (1) that many people want - and will pay for - comfort in forms people want - and will pay for - comfort in forms that can be satisfied only by increasing quantities of gas; (2) that adequate supplies of gas can be made available to meet this demand from sources domestic and foreign, natural and synthetic; and, (3) that the major question as to satisfying these wants is whether the governmental authorities will break with those past practices that have produced today's impasse in past practices that have produced today's impasse in world affairs and foreign trade and, instead, follow policies that will permit the necessary formation of policies that will permit the necessary formation of capital and freedom of commerce.

Demand
All authorities agree that there is a substantially increasing demand for gas in the U. S. Estimates of future gas consumption are shown in Table 1, which shows gas use increasing at the compound rate of 2.8 to 4.2 percent/year between 1965 and 1985. The estimates are made by highly experienced people who have taken into account oil reasonably measurable influences. With few exceptions each estimate assumes a continuation of past trends in birth rates, increasing efficiency of utilization, growth in GNP and relative prices of competitive fuels, with an adjustment for the prices of competitive fuels, with an adjustment for the inroads of nuclear power. But it is also assumed that communism will be contained without war, that the rich nations will continue to grow richer relative to the poor nations, that waste disposal (including that of nuclear power plants) will not become a limitation, and that air pollution control will not materially affect gas usage. One can only pause and remember the estimates of future whale oil use that undoubtedly were being made in 1859 as Colonel Drake spudded his well in Pennsylvania, or estimates of gas for lighting use that were being made in New Jersey when the local gas company threatened Thomas Alva Edison about his delinquent bill an action in part responsible for the electric light bulb.
JPT
P. 563
A Comprehensive Mechanistic Model for Upward Two-Phase Flow in Wellbores
Authors: Ansari A. M. , Sylvester N. D. , Sarica C. , Shoham O. , Brill J. P. 
Published: December 2007

Summary
A comprehensive model is formulated to predict the flow behavior for upward two-phase flow. This model is composed of a model for flow-pattern prediction and a set of independent mechanistic models for predicting such flow characteristics as holdup and pressure drop in bubble, slug, and annular flow. The comprehensive model is evaluated by using a well data bank made up of 1,712 well cases covering a wide variety of field data. Model performance is also compared with six commonly used empirical correlations and the Hasan-Kabir mechanistic model. Overall model performance is in good agreement with the data. In comparison with other methods, the comprehensive model performed the best.
Completion Techniques for Horizontal Wells in the Pearsall Austin Chalk
Authors: Pope C. D. , Handren P. J. 
Published: December 2007

Summary
Oryx Energy Co. used three basic completion techniques and various combinations of them to complete 20 horizontal wells in the Pearsall Austin Chalk. The completion method selected is based on a general set of guidelines. Additionally, equipment selection and various types of workover operations are reviewed.
Fluid Mechanics of the Drilling String
Authors: Koch William M. 
Published: December 2007

To help field men select the proper nozzle and pump liner size, a pocket calculator has been designed which will predict the performance of the hydraulic system.
Although the use of the drilling fluid to control and condition the hole is well known, the present use of high jet velocities has brought purely hydraulic problems to much wider attention. To help the field man, the design of a simple pocket calculator to solve some of these problems on the drilling rig was undertaken.
Calculation of the output of the slush pumps was straightforward; but experience has shown that a direct reading flowmeter would be much more satisfactory.
The energy losses in the down string were calculated by the Hazen-Williams equations with the Hazen-Williams roughness coefficient adjusted to allow for the restrictions in various types of tool joints.
Losses in the drill bit nozzle were found to vary as the 1.96 power of the flow and, inversely, as the 2.19 power of the exit area. A presently accepted production nozzle exhibited an efficiency of 70 per cent.
Losses in the return annulus are difficult to account for accurately; and, in this case, a rough estimate was used. This is practicable since these losses are a minor part of the total.
In view of these assumptions, the overall accuracy of the calculator is of interest. Based on a comparison of calculated values and actual mud pressure gauge readings, the average error was +4 per cent; and 70 per cent of the examples were in the ±15 per cent error bracket. This accuracy is sufficient to give useful answers to the field man.

Introduction
The importance of the drilling mud as a medium to control formation pressure and the stability of the walls of the hole is well appreciated. However, the present widespread use of high rates of flow has focused attention on the drilling mud as a conveyor of energy to the drilling bit. In an effort to use this energy efficiently, field men have been clamoring for information that would enable them to select a bit nozzle properly matched to their hydraulic systems. It became apparent that some quick method of estimating the performance of the hydraulic system was necessary.
Diverless Flowline Tie-In Techniques for the DISPS Project
Authors: Bruton D. A. S. , McKeehan D. S. , Metcalf Peter 
Published: December 2007

Summary
This paper describes the Diverless Subsea Product System (DISPS) project design, development, and dry prototype testing of three diverless tie-in systems for application to 4- to 12-in.-diameter flowlines in water depths of 1, 200 to 2, 500 ft. Full-scale simulation of direct pull-in, lateral deflection, and vertical stab techniques with two tools for flowline pull-in and connection was undertaken and design limits were established.
History and Performance Prediction of Umm Farud Field, Libya
Authors: Allen W.W. , Herriot H.P. , Stiehler R.D. 
Published: December 2007

Libya's Umm Farud field is unique in that it will have been discovered, developed, and depleted within 10 years. Computer simulation, used to select optimum injection and production rates, predicted a 21-percent recovery of original oil in place, and field data indicate that performance is reflecting the prediction.

Introduction
The purpose of this paper is to present a summary of the engineering data relating to the Umm Farud field. The production history of the reservoir is sufficient to allow at least a partial evaluation of the reservoir during the primary depletion and early injection phases. phases. In recent years, there has been an increasing interest in reservoir simulation techniques utilizing computers. In this study, the water injection distribution during secondary recovery operations has been predicted by computer simulation. The predictive predicted by computer simulation. The predictive portion of the simulation covers a relatively short portion of the simulation covers a relatively short period of 3 to 5 years. This short field fife lends itself period of 3 to 5 years. This short field fife lends itself to an economic re-evaluation of the reservoir mechanism and the simulation procedures.

Field Development
The Umm Farud field was discovered by Phillips Petroleum Co. in Nov., 1962. Fig. 1 shows the field's Petroleum Co. in Nov., 1962. Fig. 1 shows the field's location in North Central Libya on Concession 92. The discovery well, A-1, was drilled on a seismic closure about 17 miles from the nearest production. The well was completed in the Dahra "B" dolomite at 3,035 ft and the Mabruk "A" dolomite at 3,212 ft. Initial potential from both zones was 2,285 bbl oil.
Subsequent drilling established additional production from two zones in the Bu Charma "B" limestone production from two zones in the Bu Charma "B" limestone at 2,700 ft and 2,744 ft. All zones are commingled down hole. The field development was completed with the drilling of seven oil producers, six injection wells, and three water supply wells.
All wells are completed with casing set through the producing intervals. The producing wells are equipped producing intervals. The producing wells are equipped with submersible pumps capable of lifting 2,500 BFPD.
JPT
P. 570
Production Logging as an Integral Part of Horizontal-Well Transient-Pressure Test
Authors: Ahmed Usman , Badry Robert A. 
Published: December 2007

SummaryThis paper discusses a horizontal-well transient-pressure-test analysis method with emphasis on the use of production-interval and -profile data. The technique significantly enhances interpretation quality and answer uniqueness. The technique can be applied to specialized plots and to type-curve history-matching methods.
High Volume Pumping with Sucker Rods
Authors: Byrd J.P. 
Published: December 2007

Abstract
Recent studies have shown that often large fluid volumes can be lifted by sucker rods with great effectiveness from shallow to medium-depth wells. Wherever feasible, significant redaction in cost of elevating a barrel of fluid may be realized by the operator. The advent of longer stroke units with improved geometry, larger speed reducers and bottom-hole pumps, as well as the new high-strength sucker rods, make high volume rod pumping a practical and economical achievement. Past applications of this type generally have been considered only for bottom-hole centrifugal pumps. This paper reviews some field studies and emphasizes the practicality of high volume production with sucker rods.

Introduction
A century ago the almost universal mechanism for artificially lifting fluid in an oil well was the standard rig-front. A wooden walking beam drove a string of hickory sucker rods, often called "well poles", as many as ten 15-in.- strokes/minute with the maximum tensile stress of the rods about 12,800 psi. The bottom-hole pump was cast iron or brass with the barrel approximately 1 1/4-in. in diameter, and the well depth ranged from 500 to 1,000 ft. The torque capacity of the band wheel and flat-belt speed reducer ran only a few thousand inch-pounds, and the unit's structural capacity was from 1,000 to 1,500 lb.
Today, the structure of a modern pumping unit with its 240-in. maximum stroke reaches higher than the wooden drilling and servicing derricks of those early days. Its structural capacity exceeds 47,000 lb, with a torque rating greater than 2.5 million in. lb. The plunger diameter of some bottom-hole pumps (casing-type) runs as high as 5 3/4 -in. Perhaps the greatest improvement is in the sucker rod, which now has a tensile stress of some 140,000 psi. Today practice sucker rod pumping approaches 13,000 ft, and capacities of 5,000 and 6,000 B/D from shallow to medium depths are handled with ease. Volumes as high as 9,500 B/D are entirely practical with modern sucker rod pumping equipment.
Comparing the modern sucker-rod system with its counterpart of 100 years ago produces some startling figures. The structural capacity of the modern unit has increased nearly fifty-fold, the torque capacity perhaps a thousand-fold, the area of the bottom-hole pump over 20 times; the stroke length nearly twenty-fold; and maximum rod tensile stress nearly 12 times. With the increased stroke length, even the maximum rate of polished rod travel per minute has increased five or six times. Since all of these are compounding increases, the sucker-rod pumping unit of today has the capacity for producing massive fluid volumes from relatively great depths.
A Note on Pressure Buildup Curves
Authors: Ramey H.J. 
Published: December 2007

In 1954 Matthews, Brons and Hazebroek presented a method for correcting extrapolated buildup pressures on a Theis or Horner-type plot to static pressure. Matthews, Brons and Hazebroek considered buildup in a large number of geometric reservoir shapes with wells at various locations within a particular shape. In 1961 Brons and Miller pointed out that the presence of pseudo-steady state was indicated for the various shapes at long producing times, and that simple flow equations involving a producing times, and that simple flow equations involving a shape factor could be written for this condition. In 1965 Dietz extended this idea to show that static pressure could be found on the extension of the buildup straight line at a dimensionless time of
where A = drainage shape area, CA = shape factor and other symbols are SPE standard. Dietz work generalized the older Miller-Dyes-Hutchinson buildup method to geometric shapes other than circular. As stressed by Dietz, the method assumed that the well had been produced to pseudo-steady state prior to shut in. Neither pseudo-steady state prior to shut in. Neither Matthews-Brons-Hazebroek nor Dietz cataloged the actual buildup curves involved in the various shapes, although a few cases were shown as examples.
The purpose of this article is to present the Miller-Dyes-Hutchinson type of pressure buildup curves for most of the Matthews-Brons-Hazebroek shapes. As would be expected, assymetric location of a well in a particular drainage shape may lead to unusual bends in the pressure buildup curves. Because it is currently becoming practice to infer reservoir heterogeneities from the shape of the buildup curve, it appears useful to be aware of anomalies which may be a result of well location and drainage shape.
Figs. 1 through 4 present Miller-Dyes-Hutchinson pressure buildup curves for the rectangular shapes considered. pressure buildup curves for the rectangular shapes considered. Symbols used are SPE standard; It refers to elapsed time after shut-in. Fig. 1 shows buildup curves for a square reservoir shape with three different well locations. The heavy lines are the buildup curves. Curves 1 and 2 are similar; it would be impossible to detect the effect of movement of the well from an actual buildup curve. Curve 3, however, has a peculiar bend at a dimensionless buildup time of about 0.02. This bend could be misinterpreted as the result of a general fracturing in the reservoir as studied by Warren and Root.
Another interesting result is indicated by the dashed lines on Fig. 1. These lines represent the extrapolation of the initial straight line, and have the usual slope of 1.151. The intersection of the dashed lines with the ordinate at zero occurs at a dimensionless buildup time equal to the reciprocal of the shape factor Ca, for each shape. Note that the shape factors shown are the modified ones reported by Earlougher et al.
P. 119
Considering Wellbore Friction in Planning Horizontal Wells (includes associated papers 28646 and 29095 )
Authors: Seines Knut , Aavatsmark Ivak , Lien Svein Christian , Rushworth Philip 
Published: December 2007

Abstract
The importance of friction pressure loss within the completed section of horizontal wells, under some reservoir conditions, has been analyzed. The phenomena were studied both analytically and experimentally with sub sequent implementation in a commercially available 3-D,3-phase reservoir simulation model. Based on simulation studies, criteria for the selection of appropriated imensions for horizontal wells under different reservoir conditions are outlined. A field example from the Troll Field offshore Norway where these results were applied during the planning of a horizontal test well, is presented.

Introduction
The Troll field, located in 300m water depth offshore Norway (Fig. 1), contains 0–26 m thick oil rims sandwiched between a large gas cap and active aquifers. In the westernmost fault block of the field, the Troll WestOil Province, the oil zone is at its thickest; 22–26 m. The oil in place of this province is estimated at 121x10 6 Sm3.The reservoir contains several highly permeable, unconsolidated sands separated by low permeability micaceous sands. Impermeable calcite cemented horizons with imperfectly known spatial disposition and extensions occur within the high permeability sands. The oil production from Troll may be limited by gas coning, resulting in a limited available drawdown for the well. Since the oil rim is only 22–326 m thick, the drawdown can only be in the range of 1.5 to 2 bar in order to avoid the production of free gas-cap gas. The recoverable oil in the Troll West Oil Province is located in high-quality sands with permeabilities ranging from3000 to 10 000 md, so high liquid rates were expected(Fig. 2). With the combination of limited drawdown and high rates, wellbore friction pressure loss was considered to be of importance [1].The subject has been studied analytically by Dikken [1]. However, implementation of the effect of horizontal well friction in simulators with subsequent application for well planning and design purposes has previously not been reported. Horizontal well friction was given due attention during the planning of a 500 m horizontal well in the Troll field. The well was drilled and completed in late1989, and has been on production since January 10th 1990. The cumulative oil production as of early June1990 was 500 000 Sm [2].

Background
The Troll field covers an area of 700km2 . The estimated gas and oil in place is 1670x10 9 Sm3 and 615x10 6 Sm3respectively (Fig. 3). Two main north-south bound faults divide the field into three provinces: Troll West Oil Province, Troll West Gas Province and Troll East(Fig. 3).Concession Block 31/2 (Fig. 3), operated by A/SNorske Shell, was awarded in 1979. Blocks 31/3, 31/5, and 31/6 were awarded in 1983 with shared operatorship between Norsk Hydro a.s, Den norske stats oljeselskapa.s, and Saga Petroleum a.s.
The Use of Interpolation to Obtain Shape Factors for Pressure Buildup Calculations
Authors: Earlougher Robert C. 
Published: December 2007

As pointed out by Brons and Miller, it is convenient to use a shape factor to calculate drainage region static pressures from pressure buildup tests. If the well is produced pressures from pressure buildup tests. If the well is produced at a constant rate long enough for pseudo steady-state conditions to be reached prior to shut-in, the drainage region average pressure may be calculated from
..........................................(1)
where:
p = drainage region average pressure,
p* = shut-in pressure linearly extrapolated toinfinite shut-in time on a plot of p vs log[ ], A = drainage area of the well, and
CA = shape factor.
Shape factors have another useful significance. Brons and Miller showed that
..........................................(2)
where the constant y is the exponential of Euler's constant and has the value 1.781. Eq. 2 is the general flow equation that describes the pseudo steady-state flow for any bounded (closed) shape.
Both Brons and Miller, and Dietz have tabulated values for the shape factor C, for various drainage region shapes and well locations. Nevertheless, a value of C, often is needed for a system that is not included in the tabulations. In this case the techniques of Ramey and of Earlougher et al. can be used to calculate the needed shape factor. However a simpler method may be used in many instances. This method consists of making a plot of C, against some shape-determining quantity (such as well location or length to-width ratio of a rectangular system) and graphically interpolating.
Fig 1 And 2 are examples of such plots. Fig. 1 shows the shape factor plotted against well location for three rectangular systems. To assume the accuracy of this plot, values of C4 have been calculated for a few points not given in the Dietz table. Actually, the figure could be constructed without calculating these Ca values if slightly inaccurate results were acceptable, or if only well locations for 0.25 less than x less than 0.5 were of interest.
P. 449