bluuebunny/crossref_metadata_2025_split huggingface dataset:
Wellsite Diagnosis of Pumping Problems Using Minicomputers
Authors: Gibbs S.G. , Nolen K.B. 
Published: December 2007

The truck-mounted computer system described here greatly enhances the efficiency of the sucker rod diagnosis technique. Using an example well, the paper shows how the method and the equipment can be used to increase production and decrease lifting costs. With this system, more definitive production and decrease lifting costs. With this system, more definitive and timely results can be obtained more efficiently, thus lowering the cost of applying the technique.

Introduction
The Sucker Rod Diagnostic Technique was perfected by Shell during the 1960's. Its concept was suggested by the work of British physicians who wanted to analyze human electrocardiograms more accurately and definitively. To do this, they subjected cardiograms to Fourier analysis, hoping to reveal subtle indications of heart disease that might be overlooked if only visual interpretations were made. Similarly the sucker rod method was designed to derive the maximum amount of information from a pumping-well dynamometer card and to make the analysis of the card a science rather than an art. This paper describes a portable computer system for implementing the sucker rod method.

Brief Theoretical Review
The basis for the diagnostic technique is a stress wave propagation problem based on the one-dimensional propagation problem based on the one-dimensional wave equation
(1)
The wave equation models the rod string and permits the use of surface data to deduce down-hole conditions in pumping wells. This is directly analogous to the human cardiogram where easy-to-measure surface data are used to infer conditions within the body. The boundary conditions measured at the surface are time histories of the load and position of the polished rod. These are expressed as truncated polished rod. These are expressed as truncated Fourier series of the following type:
(2)
(3)
Solutions to the wave equation that satisfy the measured boundary conditions give operating conditions in a given well at a particular time in its producing life. The basic diagnostic solutions give producing life. The basic diagnostic solutions give displacement and load at arbitrary depths in the rod string. These are
(4)
and (5)
The procedure for solving and generalizing for the case of tapered strings is detailed in Refs. 1 and 2. By cross-plotting the solution for displacement (Eq. 4) vs load (Eq. 5) at a given depth, a dynamometer card at that depth is obtained, This is equivalent to the card that would be measured with a dynamometer instrument placed at that depth.
JPT
P. 1319
A Hydrothermal Setting Cement for Cementing Ultradeep, Hot Wells
Authors: Maravilla S. 
Published: December 2007

Laboratory data show that a unique hydrothermal setting cement can be used as manufactured-without the addition of high-temperature field retarders-to cement oil and gas wells where the bottom-hole static temperature is in the range of 260 deg. to 320 deg. F. If necessary, the retarders and other field additives can be used to extend that range when wells must reach 18,000 to 24,000 ft.

Introduction
In 1969, oil company representatives of API Committee 10 on Standardization of Oil Well Cements expressed concern that difficulties were still being encountered in retarding marketed Class H cements for wells deeper than 14,000 ft.The Committee appointed a task group that not only confirmed the need for a new cement, but adopted, in 1972, a set of tentative specifications based on a specific marketed high-temperature cement. The cement was designated Class J.This paper describes a unique hydrothermal setting cement based on a new concept for oilwell cements, the theory for which is documented in the literature.

Chemical Composition
A natural question that immediately comes to mind is "What is hydrothermal setting cement?" Depending on the starting materials, the product may consist of any mixture of compounds - for example, port-land cement; portland cement and silica flours or silica, lime, and waters that react to form crystalline silicate hydrates under hydrothermal conditions. These reactions take place in the presence of water above 212 deg. F at pressures exceeding atmospheric pressure. pressure. The hydrothermal setting cement composition described here is composed essentially of a binder, quartz sand, and calcium hydroxide. The binder is beta dicalcium silicate (beta- 2CaOSiO.), one of the main mineral constituents of portland cement.Table 1 shows typical chemical analysis, fineness, and specific gravity of hydrothermal setting cement (henceforth referred to as HTS cement) vs Class H plus 60 percent silica flour. plus 60 percent silica flour. It appears from results of chemical analyses shown in Table 1 that the typical HTS cement discussed here is virtually the same as a typical Class H cement to which 60 percent silica flour (SiO.) has been added. However, it must be understood that the HTS cement contains different compounds. Obviously, the thermal history of the hydrothermal cement binder and the fineness of the cement are essential considerations.Data shown in Table 2 clearly show that HTS cement exhibits better thickening time and compressive strength characteristics than unretarded Class H plus 60 percent silica flour. Under ordinary temperatures HTS cement is relatively unreactive. ASTM C109 strength results show that 2-in. mortar cubes cured at 73 deg. - 3deg.F did not set in 9 days. Despite extended curing periods of 28 days and 180 days under comparable conditions, the strength of the specimens developed quite slowly; i.e., 200 psi and 1,000 psi, respectively.
JPT
P. 1087
Production of Water-Driven Reservoirs Below Their Bubblepoint
Authors: Dyes A.B. 
Published: December 2007

Abstract
In the operation of a water-driven reservoir, a free gas saturation can be established by maintaining production rates fast enough to cause the reservoir pressure to decline below the bubble point. The benefit of such a procedure on the displacement efficiency of the oil by water is illustrated for two types of sandstone samples from one reservoir. Those rock samples showing the poorest recovery to water drive in the absence of a free gas saturation give the most improvement in the presence of a free gas saturation. Employing one type of reservoir fluid (low shrinkage) the benefit of evolved gas on oil displacement is calculated at several reservoir pressures below the bubble point. This demonstrates the presence of an optimum pressure for water displacement which is several hundred pounds per square inch below the bubble point. Displacement of oil at the optimum pressures results in the removal of 7 to 12 per cent more oil than would be obtained by displacement at the bubble point pressure. In some instances this magnitude of increase may be worthy of consideration in establishing the maximum efficient rate of production from many water-driven fields.

Introduction
For many years the belief that the use of gas could be combined with that of water to result in a better recovery operation than the use of either of these phases alone has been prevalent in the oil industry. This is evidenced by the several field trials which have employed the injection of gas and water in combination. In most cases the small amount of any additional recovery, in combination with the limited knowledge available on the older reservoirs, has left uncertain the influence of gas on recovery in these earlier attempts to combine the use of gas with water.
Research studies in recent years have demonstrated through laboratory floods the magnitude of the benefit of the presence of gas on the displacement of oil from sandstones by water. In addition, studies of the distributions of the phases which are present during the displacement process have developed concepts concerning the mechanism by which this benefit is obtained. It now remains for the engineer to incorporate these findings into the general technology of reservoir operations.
Secondary Recovery Operations in the Tijerina No. 3 Unit Reservoir
Authors: Olansen N.A. 
Published: December 2007

Introduction
The purpose of this paper is to present the production history of the Tijerina No. 3 Reservoir from its initial development in April, 1945, through April. 1954, including primary development, unitization, and secondary recovery by high pressure gas injection. Particular attention is given reservoir performance as influenced by the migration of fluids in a continuous but erratic sand of low permeability. It is interesting to note that, from material balance calculations, apparently little or no injected gas goes into solution with the remaining reservoir oil, even though reservoir pressure has been increased an average of 700 psi.

Location and Geology
The Tijerina No. 3 Reservoir is located in the southwest portion of the Tijerina-Canales-Blucher field, approximately 2 miles northeast of the town of Premont. Jim Wells County, Tex. It is the deepest member of a series of lower Oligocene (Frio) Sands productive in the field, lying at an approximate depth of 7,200 ft subsea. Structurally, the reservoir is a permeability trap lying on an erratic monocline, with an average southeast dip of 170 ft per mile. There is no faulting present to break the continuity of the sand. A structure map drawn on the top of the sand is shown in Fig. 1. The productive limits of the reservoir are defined by shale outs and dry tests except in an area to the northwest; where, due to the lack of geological control, the location of the strand line is assumed. The oil column is bounded in this area by a small gas cap, the original gas-oil contact having been established at 7,058 ft subsea by drill stem and production tests run during development. There is no evidence of a water-oil contact in the reservoir. The sand is described as being firm, fine-grained, medium to hard, with scattered shale streaks occurring near the strand line. It possesses a low and erratic permeability as substantiated by PI's which ranged from 0.020 to 0.114 in five wells when measured in April, 1948. A typical electric log is shown in Fig. 2.
Correlation of Steam Stimulation Performance
Authors: Boberg T.C. , West R.C. 
Published: December 2007

An approximate correlation has been observed of steam stimulation field results with the product of oil transmissibility and static pressure. This correlation may have application as a rough screening tool for identifying potential candidates for steam stimulation. Theoretical support for this correlation is obtained by observing that the incremental oil-steam ratio (OSR) may be expressed as
........................................(1)
where theta is the time at the end of the injection-soak period, and theta is the time at the end of the production period, and theta is the time at the end of the production phase when the stimulation effect is essentially nil. It phase when the stimulation effect is essentially nil. It constant average values for Jc and Delta p can be assumed,
........................................(2)
Note that for theta greater than, greater than that and J greater than, greater than 1, this simplifies to the approximate equation,
......................(3)
From an earlier paper it follows for the case of steady-state flow that
and
Eq. 3 becomes
The OSR will be a strong function of, where Delta P is the average pressure drawdown over the producing cycle. For pe greater than, greater than pw, producing cycle. For pe greater than, greater than pw, then Delta p can be approximated with pe, and it can be seen that the incremental OSR will be a strong function of the product (koh/mu o) pe. This would suggest a correlation product (koh/mu o) pe. This would suggest a correlation between the incremental OSR and the product of transmissibility and static pressure. The relationship would not be linear, however. As (koh/mu o) pe increases, the prestimulation rate would be expected to increase. prestimulation rate would be expected to increase. For a given treatment size, the stimulated rate would likewise increase, and consequently, the energy withdrawal rate from the formation would increase. Thus, theta p, the stimulation producing time, will be inversely affected by an increased (koh/mu o) pe. The effect will become more pronounced for highly productive wells.
P. 1367
A Graph for Determining Reserves and Spacing
Authors: Sloan R.L. 
Published: December 2007

The graph (Fig. 1) accompanying this article presents a quick method to determine reserves under presents a quick method to determine reserves under varying conditions. It can also be used to estimate minimum spacing for an economic recovery.
Example 1 - Recoverable Reserves Reservoir Data Porosity, percent 20 Water saturation (Sw), percent 40 Formation volume factor (FVF) 1.2 Recovery factor, percent 20 Spacing, acres 20 Net pay, ft 50 The solution route is shown on Fig. 1.
Solution Oil originally in place, STB/acre-ft 776 Recovery, STB/acre-ft 155 Recovery, bbl 155,000
Example 2 - Spacing

Assumptions
A recovery of 400,000 bbl is required for an economic return on your investment. Net pay is 100 ft. 3. Recovery is 270 bbl/acre-ft.

Solution
Draw line from 270 BPAF recovery through all spacing curves. Start at 400,000 bbl recovery and go up to the 100-ft net pay line. Go left until you intersect the 270 BPAF recovery line.
This intersection is the spacing required (15 acres). The chart is a simple solution and it will permit on-site analysis. Additional charts can be developed for gas reserve determinations.
P. 1470
Drag Reduction Does Not Always Increase with Increased Flow Velocity
Authors: Sarem A.M. 
Published: December 2007

In view of industry's current thinking about drag reduction, an article by Avnapov et al., "The Effect of Adding Polyisobutylene on the Capacity of Pipelines," is of considerable interest. Their Fig. Pipelines," is of considerable interest. Their Fig. 2, when replotted (see Fig. 1) reveals that drag reduction is not a continuously increasing function of the flow velocity as has been postulated by others working in this field. This was revealed by the calculation of drag reduction for 50 ppm polyisobutylene (PIB) in gas condensate based on Curves 1 and 2 of Fig. 2 of the Russian article (see Table 1). These data, plotted in Fig. 1, show that the drag reduction increases as velocity increases up to a "critical" velocity of 9.8 ft/sec. As the velocity is increased beyond 9.8 ft/sec, the drag reduction gradually decreases. To my knowledge, this has not been shown elsewhere, perhaps because no one had tested for drag reduction at perhaps because no one had tested for drag reduction at such high velocities. The Reynolds number for a 0.8-cp, 0.8-gm/cc fluid flowing at 16 ft/sec in a 6-in pipe about 700,000 which is rather high. We have obtained experimental results similar to the above in a drag reduction test in which diesel fuel and gasoline were flowed through a 6-in.-diameter conduit at 8.7 and 11.4 ft/sec, respectively.
TABLE 1 - DATA FROM AVNAPOV ET AL.*
/1 (units unknown) Velocity Drag No PIB 50 ppm PIB Reduction cm/sec ft/sec (Curve 1) (Curve 2) (percent) 200 6.55 3.5 2.5 28.5 250 8.2 6.5 4.0 38.4 300 9.8 11.1 6.0 45.9 400 13.1 19.5 11.0 43.6 500 16.4 28.5 16.5 42.1
P. 673
Sea-Floor Scour Protection for a Semisubmersible Drilling Rig on The Nova Scotian Shelf
Authors: Wilson N.D. , Abel Wesley 
Published: December 2007

Suppose you had a modest little upholstery shop in Halifax. How would you feel if someone asked you to slipcover the pontoons of a semisubmersible rig? After 7,500 yards of material, your old Singer would never be the same again.

Introduction
Scour protection is often required to prevent scour from occurring around marine structures. This was the concern when it was proposed to set the semisubmersible drilling rig Sedco H on the sea floor to drill the Mobil-Tetco Thebaud P-84 well in 90 ft of water 6 miles southwest of Sable Island. Fig. 1 shows the location of the well. Normal tidal currents in the area reach a maximum of about 1.5 knots. Scour was expected since it was known that the sea floor was fine sand and that the 80-ft-diameter Sedco H pontoons would cause the current velocities around the pontoons to be accelerated considerably. However, it was impossible from existing information to predict the amount of scour that would occur or the amount of scour protection that would be required. This is mainly protection that would be required. This is mainly because the relationship of current velocity, rate of scour, scour depth, and grain-size distribution is not yet well defined. Also, the geometry, spacing, and size of the Sedco H pontoons are such that correlations from other experimental work could not be made. It was therefore decided to analyze the problem with model tests in a hydraulic tank model basin. Delft Hydraulics Laboratory of The Netherlands, who had previously performed similar scour studies, was selected for the model work. The results from the tests were used to design the scour protection and to plan a successful field installation.

The Scour Process
A sand bed exposed to ocean currents in a sea-floor environment is usually in a condition of equilibrium. In this condition the bottom material is transported but no net deposition or erosion occurs. However, when an object is placed on the sea-bed, current velocities near the object increase and this equilibrium condition is disturbed. Additional turbulence results and there is an increase in the transport capacity of the fluid near the object. The sea bed around the object starts to erode. This erosion is known as scour. The magnitude of scour depends onthe geometry of the object,the characteristics of the seabed material, andhydrodynamic conditions. Current velocity influences both the rate and depth of scour.
The influence of current velocity on the depth of scour around structural piles, bridge piers, and abutments has been studied by Delft Hydraulics Laboratory, among others. The influence of the combination of wave-induced currents and tidal current on scour around structural piles was studied by Abou-Seida and by Delft Hydraulics Laboratory. The above references indicate that scour can be predicted for simple cases such as for a predicted for simple cases such as for a small-diameter isolated circular pile. The Sedco H pontoons, however, are 80-ft in diameter. pontoons, however, are 80-ft in diameter. JPT
P. 381
Canal Field Gas Injection Project
Authors: Pings C.J. , Tempelaar-Lietz W. 
Published: December 2007

Abstract
For the history of the performance of the Canal field gas injection project reference is made to two publications. In the present paper a critical examination has been made of the pressure measurements and of the pressure-volume-temperature data for the reservoir fluid. Material balance calculations were employed to determine the oil in place, the size of the oil reservoir, the size of the aquifer, the amount of water inflow, and the migration of hydrocarbons within the reservoir. The effectiveness of the gas-injection program is discussed.

Introduction
The gas injection project in the Canal field, San Joaquin Valley, Calif., has now a history of 14 years. The performance was discussed in a paper presented by R. P. Mangold before the Pacific Coast District API meeting in Los Angeles, April 11, 1946. This paper was not published, but the pertinent data have been recapitulated by Muskat. In July, 1952, the Bureau of Mines published their Report of Investigations No. 4886 in which an excellent review of the history up to that time is presented, and the reader is referred to that publication. In the present paper a short resume of the history is shown in Figs. 1 through 4. In the last paragraph of the Bureau of Mines' publication reference is made to the gas injection in Well E-11. The additional information on this localized injection now available is presented in the next section. The remainder of the present paper will deal with the technical methods used in a detailed analysis of the various aspects of this project.

A Localized Injection Experiment
Wells A47-14, E-11, and E-14 are located on the southern flank of the field. In the 24 months preceding April, 1948, E-11 flowed 7,541 bbl of oil at an average rate of 12 B/D.
Report of Operations, 1945 Through 1954, Naval Petroleum Reserve No. 1, Elk Hills
Authors: Gooch F.W. , Adams R.H. 
Published: December 2007

Abstract
This paper presents the progress of operations within the Elk Hills field for the period 1945 to 1954. Since World War II and the subsequent shut-in of this field, many projects were initiated to determine the best method of protecting the various reservoirs. All of the Shallow Oil Zone programs were predicated around a reservoir which was in a state of pressure unbalance caused by heavy withdrawals of fluid in relatively short periods of time. The basic studies centered around: the use of gas injection, evaluation of an unrestricted water encroachment and its opposite heavy downdip withdrawals to utilize gravitational drainage, general studies of movement of reservoir fluids, and the protection of surface equipment. These programs have been changed from time to time, depending upon results obtained. Some of the results are unique. Currently the programs involve controlling encroachment through production from invaded areas and remedial measures to stop or minimize the downdip migration of oil. A primary objective of all programs is to maintain the Reserve in a state of readiness whereby it will be able to produce oil in substantial quantities whenever the strategic situation of the United States so requires.
An active drilling program has resulted in further development of the Shallow Oil Zone, the exploration and development of the Stevens Zone, and adding a new and as yet untested pool, the Carneros.

History and Stratigraphy
This paper is intended to supplement an original technical publication titled "Experimental Production Projects and Exploratory Drilling at Elk Hills" by M. C. Eastman and F. L. Ruhlman, which was presented at the Petroleum Branch, AIME, Fall Meeting of 1947. It will report the progress of operations made since January of that year.
An Evaluation of Critical Multiphase Flow Performance Through Wellhead Chokes
Authors: Ashford F.E. 
Published: December 2007

_
A multiphase flow equation describing the behavior of orifice flow may be used directly to evaluate well performance as a function of choke size; upstream choke pressure; choke temperature; producing and solution GOR; gas, oil, and water gravities; and a discharge coefficient. The coefficient compensates for nonideal factors excluded in the development of the equation and relates theoretical oil production rates through chokes to field-measured rates.

Discussion
Various developments have been published 1-3 that present theory and correlations for describing simultaneous liquid and gas flow through a restrictive orifice.
The correlations of Poettmann and Beck3 were intended to aid in the prediction of gas-liquid flow through chokes. Their development followed the original presentation by Ros1 and was derived for an average orifice discharge coefficient.
Poettmann and Beck considered the polytropic expansion of the gaseous phase of the fluid expanding through the choke. The polytropic expansion theory was used successfully by Ros and is perhaps the most rigorous development in the application of orifice flow theory to oilfield conditions. Basically, the derivation of any orifice relationship is dependent on two main criteria. First, an expression must be written relating the flowing fluid specific volume and velocity to the mass flow rate. Second, an independent equation must be written incorporating the behavior of the gaseous phase of the fluid with pressure. The above stipulations are met by the following relationships.