bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of Services and Equipment for Small Holes
Authors: Huber T.A. 
Published: December 2007

The New Proven Small-Hole Completion
As a result of slim-hole development, small holes can now be drilled and completed with 4½-in. OD casing at a savings up to 35 per cent over conventional well sizes. This economical completion is illustrated as the "1954" completion in Fig. 1. Important advances in drilling tools and techniques have resulted in drilling rates for these small holes which are comparable to rates for larger holes. Savings from employing smaller and more economical drilling equipment and reductions in casing tonnage, coupled with advances in completion technology, are effecting a size reduction such that 4½-in. OD casing set in holes from 5 5/8 in. to 6 1/8 in. in diameter and completed with 2-in. tubing is growing in acceptance.
Although certain calculated risks are taken, experience has indicated that the incidence of fishing operations should not exceed that experienced in holes of conventional size, provided the usual precautions are taken. Furthermore, fishing for such items as drill collars and bits should be limited in light of the economics of sidetracking and redrilling the inexpensive small hole. Savings in exploration and development costs adequately compensate for the slight risk involved. These holes for 4½-in. casing may be drilled, fished, logged, completed, produced, and reworked without undue difficulty.

Equipment for Drilling and Completing Wells with 4½-in. OD Casing
Recently, important improvements have been made in drilling tools and techniques for these small holes. Bearings in 5 5/8-in. and slightly larger rock bit sizes have been improved. This, coupled with the introduction of long-tooth, soft formation bits, has resulted in drilling rates for these holes being comparable to larger holes. In addition, diamond or similar type drilling and full-hole coring become increasingly effective with reduction in hole size.
Several good rig designs for this small-hole work are offered by manufacturers, but such rigs are not widely available for contract drilling. The universal rig design is as unattainable here as for larger holes; but in most cases, a unitized trailer-mounted slim-hole rig which does not require guy wires is very desirable because of portability and speed. In some areas available lightweight, large-hole rigs may be profitably used in slimhole drilling to greater depths; and in other areas, special design considerations for restricted highway loading may be desirable.
Some Experiments on the Flow of Miscible Fluids of Unequal Density Through Porous Media
Authors: Crane F.E. , Kendall H.A. , Gardner G.H.F. 
Published: December 2007

Introduction
Craig, et al investigated the effect of gravity on frontal displacements for circumstances in which the gravity forces were significant. Blackwell, et al, dealt with the other extreme in which gravity forces were negligible. The considerable difference between their results is illustrated in Fig. 1 where the breakthrough recoveries are plotted against the mobility ratio. The experiments described in the present paper were conducted to examine how the transition from the one extreme case to the other occurs when the gravity forces are gradually reduced.The transition is well illustrated by the production history after breakthrough. Fig. 2 shows how the number of pore volumes which must be injected at a constant rate to displace 98 per cent of the original fluid depends on the gravity force. For each mobility ratio there is a transition range, and a very significant change in the number of pore volumes occurs when this range is transversed. This range of the gravity force is physically linked withtheformationofviscousfingers.A single finger is predominant for larger gravity forces; a multiplicity of fingers is formed for smaller gravity forces. Improved recovery and the occurrence of multiple fingers is concomitant with a large increase in the amount by which the fluids are mixed within the porous medium.The transition range depends on all the dimensionless groups which characterize the problem; but this dependence has not been exhaustively studied as yet and only fragmentary results are discussed in this paper.
SPEJ
P. 277^
Effect of Pressure, Temperature and Wellstream Composition on the Quantity of Stabilized Separator Fluid
Authors: Portman W.E. , Campbell John M. 
Published: December 2007

A series of correlating charts have been prepared to enable the field engineer to predict the amount of stock tank fluid produced by stabilization of first stage separator fluid. The charts shown are particularly convenient for estimating the relative effect of temperature and pressure in economic studies. Further work is planned to investigate the factors affecting stage separation to supplement this preliminary work.
The direct correlation of separation variables is dictated as a convenience to eliminate the trial and error calculation necessary when using the standard flash vaporization equations. These are obtained by a material balance using the equilibrium vaporization ratio K, and have appeared in the following, or similar, form many times in the literature.
These equations may of course be effectively and accurately solved by use of digital and analog computers. However, these are not usually readily available in field offices and the need often arises for fast results during routine operational problems. Consequently, many methods have been devised in an attempt to simplify the basic calculation.
The methods proposed are generally satisfactory, but do not eliminate trial and error methods and the necessity of subsequent calculations to obtain the answer in volume terms. The purpose of this work, therefore, was to develop accurate charts that would give the result directly in gallons.
When using stage separation the recoveries would be lower than those shown, for stabilization usually gives about 95+ per cent recovery on the potential stock tank components in the separator liquid.
The recoveries are shown in terms of a 14 psi Reid Vapor Pressure product which has a true vapor pressure of 14.7 psia at 98°F. Consequently, this product represents a stable stock tank liquid under normal storage conditions.
To estimate natural gasoline recoveries by stabilization the volume shown may be multiplied by 1.20 for 18 lb RVP natural gasoline and 1.36 for 26 lb RVP natural gasoline.
Characterization of a Gas Well From One Flow-Test Sequence
Authors: Odeh A.S. , Moreland E.E. , Schueler S. 
Published: December 2007

Most acceptable methods of gas well characterization require a series of drawdown-buildup sequences. The method described here requires only one drawdown followed by a buildup, thus reducing testing time and associated costs.

Introduction
Many authors recognize that Darcy's law may not hold for flow of gas through porous media. The non-Darcy flow effect has been accounted for by a flow-rate-dependent skin. Thus, to adequately characterize and predict deliverability of a gas well, it is essential to resolve the skin calculated from a buildup or a drawdown into at least its two components: the physical or rate-independent component, and the nondarcy, or rate-dependent component. The total skin calculated from flow tests has been represented by the following equation.
st = s + Dq,................................(1)
where
st = total skin calculated from flow tests
s = skin caused by physical damage or improvement, plus pseudoskin effects caused by restricted entry to flow at the wellbore
D = nondarcy flow constant in 1/q
q = gas flow rate in any appropriate units.
Basically, there are two methods for estimating the non-Darcy flow constant, D. The first method calculates D by the following equation.
-15 2.715 × 10 M pbk D =, ...............(2) hr w T b
where 1 D = Mscf
M = molecular weight of gas, lb
P = base pressure, psi
k = permeability, md
mu = viscosity, cp
h = thickness, ft
r = wellbore radius, ft
T = base temperature, deg. R
beta = turbulence factor, 1/ft.
beta may be estimated theoretically by -5/4 -3/4 beta = (5.5 × 10) k (phi S),
where
phi = porosity, fraction
Sg = gas saturation, fraction.
The second method uses flow tests to calculate D. The literature reports that comparing values of D estimated by Eq. 2 with those obtained from flow-test data indicates that the theoretically determined values may be in error by as much as 100 percent. Because of this uncertainty, D should be obtained from flow tests when possible.
JPT
P. 1500
Development of a Local Grid-Refinement Technique for Accurate Representation of Cavity-Completed Wells in Reservoir Simulators
Authors: Göktas Baris , Ertekin Turgay 
Published: December 2007

Summary
In this paper the development of a three-dimensional, single-, and two-phase fluid flow model to study flow performances of cavity-completed wells is presented. A static local grid refinement (LGR) is embedded into the model in order to adequately capture the flow behavior around cavity completions using a reasonable number of grid cells. The model adopts an approach that is significantly different from the current practice in which cavity-completed wells are incorporated into computations by assigning large wellbore radii and/or large negative skin values to a conventional wellbore model.
The model utilizes the residual equation rather than a wellbore equation to determine the flow into cavity-completed wells. Cavity-completed wells are described as a collection of fine rectangular grid blocks. This representation is referred to as the cavity approach. The constructed fine grid lines are terminated at the coarse/fine grid block interfaces by implementing the LGR technique developed. The technique subdivides selected coarse grid blocks into fine rectangular grid blocks in all three dimensions that are known as window blocks. The flow equations generated for window and coarse grid cells are then solved simultaneously by using the preconditioned biconjugate gradient stabilized iterative method.
First, a radial-cylindrical wellbore is approximated using the cavity representation. The model results from single phase, slightly compressible fluid flow simulation with the cavity approach are, then, compared against the analytical solutions. In these comparisons, very good matches are obtained for both flow rate and sandface pressure specifications at the wellbore. The model is further extended to single phase, compressible, and two-phase fluid flow conditions in both conventional and coalbed reservoirs. The model results are, in this case, compared with the existing numerical models that utilize Peaceman's wellbore model. Again, close agreement in flow response is obtained for a series of comparisons. Finally, the cavity approach is tested by modeling flow performances of irregularly shaped, cavity-completed wells in conventional and coalbed reservoirs.
During the creation of cavity completions in coal seams, it is hypothesized that fracture networks in certain directions are generated around cavities. The effects of fractures are usually incorporated into a simulation study by modifying the permeability values around the wellbore. The cavity approach presented in this paper provides not only a better approximation to the shape of the cavity but also a better representation of the altered permeability values around the cavity since fine grid cells are already in place around cavity completions.
Field Application of a Scale Inhibitor Squeeze Enhancing Additive
Authors: Collins I. R. , Cowie L. G. , Nicol M. , Stewart N. J. 
Published: December 2007

Summary
Barium sulfate scale deposition in the near wellbore, perforations, or production tubing has severely affected well productivity in many North Sea Fields. This is due to the co-mingling of the sulfate-rich seawater used for reservoir sweep with formation water containing high concentrations of barium ions. Mitigation of this problem is generally achieved by regular "squeeze" deployment of scale inhibitor chemicals which retard scale precipitate formation and deposition. However, in some instances, the scale inhibitor is poorly retained within the reservoir rock matrix and short squeeze lifetimes are experienced. The net result in these cases is frequent well interventions which impact on both well productivity and field profitability. To solve this problem, a scale squeeze enhancer has been developed which acts to enhance retention and subsequent release of scale inhibitor in the reservoir. The first field deployment of this technology was in BP's Magnus asset. The trial demonstrated a more than doubling of the squeeze lifetime of an adsorption chemical.
Calibration of Casing/Tubing Design Criteria by Use of Structural Reliability Techniques
Authors: Adams A. J. , Hodgson T. 
Published: December 2007

SummaryThis paper reviews the state-of-the-art in casing/tubing structural reliability analysis, and the knowledge gained from it to date. Results are presented to show that, as previously suspected, burst design based on casing full of gas is over-conservative for non-critical wells. However, the risk-calibrated design criteria are strongly dependent on the design philosophy for underground blowout loads. It is demonstrated that well control is the largest single factor in reducing risk; gaps in current knowledge are identified, and recommendations made for future work.
Factors Influencing Optimum Ball Sealer Performance
Authors: Brown Robert W. , Neill George H. , Loper Raymond G. 
Published: December 2007

Introduction
The perforation sealing process has been proven highly successful and economical since it was introduced to the oil and gas industry in early 1956. Since it has proved so successful in multistage fracture treatments at a much lower cost than conventional packers, the ball sealer process has become a byword in well completions." Not only has it changed the design of fracture treatments, it has changed the concepts of selectively perforating and has greatly aided the success of the single-point and limited- entry techniques."Yet with all the advantages, there are still facets of ball sealer behavior that are not widely recognized. These must be known and understood to better design and execute the optimum ball sealer treatment.The down-hole behavior of ball sealers is influenced by a number of factors including an "inertial force", a "drag force" and a "holding force". These are considered in two phases-the initial seating of the ball and the forces tending to unseat the ball after contact has been made (see Fig. 1 ).This paper presents a theoretical study of these factors and formulas for predicting their influence. The authors acknowledge the fact that the flow equations presented herein describe the behavior of Newtonian fluids and do not cover the so-called power-law fluids. The assumptions made, however, are reasonable and well within practical limitations of the conditions encountered during field application. For example, it is assumed that the perforations are round with a discharge coefficient of 0.82. While this may not be exactly true, it has been verified within practical field limitations.' The discharge coefficient would not vary significantly even if the perforation size or configuration varied pronouncedly. The approach of assuming uniform perforation size is not as strained as it might first appear. Normally, a perforator contains charges equally spaced with the same number in each vertical (or horizontal) plane. If the perforating gun is not centralized, the holes in one plane will be smaller than average, while the holes in opposing planes will tend to be larger than average. The net result is that the two effects tend to balance.

FACTORS AFFECTING CONTACT WITH PERFORATION
Ball sealers are injected into well treating fluids for the purpose of contacting and sealing those perforations which are accepting the fluid flow. The efficiency of the sealers is primarily influenced by:the velocity of the balls down the pipe, andthe fluid velocity through the perforations.
To divert the sealer to the perforation, the inertial force of the ball must be overcome by the drag force created by the fluid velocity through the perforation.

BALL VELOCITY
The final, or stable, velocity of the ball is the sum of the actual fall velocity and the fluid velocity.
JPT
P. 450^
Analog Study of Water Coning
Authors: Meyer H.I. , Searcy D.F. 
Published: December 2007

Introduction
The analysis of our previous paper on the behavior of two immiscible fluids separated by gravity into two distinct saturated zones in the porous medium was shown to be theoretically valid only if one of the two fluids was immobile. The practical problems associated with flow of both phases have so far been impossible of solution by these analytic methods. We, therefore, decided to resort to a simulator study to answer the following pertinent questions:If the lighter fluid is produced from a point above the fluid-fluid interface, how long will it take for the heavier fluid to come up to the point where production of both fluids is taking place?After steady-state two-phase production is established, what is the relative production rate of each phase, on what physical variables does this depend, and what are the boundary conditions at the outflow face?A third question was at least partially answered in the course of this investigation: that of the shape of the interface under flow conditions. These questions are of fundamental importance in the fields of hydrology and the reservoir mechanics of oil and gas production.
In order to simplify equipment used and still retain a fair physical representation of these phenomena, it was decided to use a Hele-Shaw type of analogy in which the flow took place between two vertically mounted pieces of plate glass. The advantage of this system is that it eliminates any surface effects between the matrix of the porous medium (e.g. packed sand) and also allows equilibrium conditions to be established more quickly. The principle disadvantage (apart from the obvious one of being one more step removed from the prototype) is that our equipment limited us to two dimensional flow studies.
In spite of these limitations answers to the questions were obtained which seem adequate for our purposes. We would like to see more work of this nature done to verify and to improve our conclusions.
Analysis of Wireline Formation Test Data from Gas and Non-Darcy Flow Conditions
Authors: Kasap Ekrem , Lee Jaedong 
Published: December 2007

SummaryUnlike liquid formation tests, in a gas formation test, both compressibility and viscosity vary with pressure, and non-Darcy flow is more likely. In this study, the gas formation rate analysis technique is developed to analyze gas pressure tests. We calculated gas pseudopotentials, utilized the geometric factor concept, and replaced Darcy's equation with Forchheimer's equation to study non-Darcy flow effects. The technique is applied to a field test, and the results are verified by history matching it with a three- dimensional near wellbore simulator.
Targeting Horizontal Wells—Efficient Oil Capture and Fracture Insights
Authors: Tank W. J. , Curran B. C. , Wadleigh E. E. 
Published: December 2007

Summary
Horizontal well targeting is often a greater challenge in massive, fractured carbonates than in low-productivity, poorly connected, and relatively thin reservoirs. This paper discusses methods to target horizontal wellbores in three-dimensional space to both confirm the fracture interpretation and establish high-efficiency oil capture. Several well examples are presented to illustrate the targeting objectives and the resulting well performance. Early in the program, the horizontal drilling objectives sought to maximize the lateral length in a direction determined by offset well productivity; the sample philosophy as is used in matrix-dominated reservoirs. Analysis of these results and employment of methods presented in this paper indicate profit can be maximized by drilling to a specific target to intersect a fracture trend at an optimum elevation instead of concentrating on maximizing length of lateral. Intervals of rapid penetration, lost circulation, and/or bit slides, along with cutting sample compositions, provided insight for confirmation and extension of the fracture network interpretation. The width of disturbance and degree of fracturing observed along interpreted fracture trends are valuable data for improved fracture network interpretation and computer simulation. Both the elevation and number of fracture branches encountered are significant strategic planning issues for oil recovery from unconfined oil columns in a massive carbonate system. Results from a large number of horizontals indicate significant productivity increases are achieved by proper targeting of laterals into major fracture features.
The Shifting Center of Petroleum Production
Authors: Moody Graham B. 
Published: December 2007

Introduction
During the past 98 years the United States has produced annually more crude oil than any other country, except during one three-year period and another period of four years. Needless to say this nation has surpassed all others in cumulative production.
The United States for many years has produced a greater percentage of its proved reserves annually than has any other country with large reserves. The high annual withdrawal from reserves by this nation in the past may lead in the future to the loss of its status as center of crude oil production.

Center of Annual Production
Rumania, birthplace of the oil industry, was the center of crude oil production during the three-year period, 1857 to 1859 (Fig. 1 and Table 1). Actually, it had the only recorded output in 1857 and 1858 and 67 per cent of world production in 1859. Before continuing the citation of honors as center of world's production, it should be mentioned that there may have been small production from some spot before records were kept.
The United States was largest producer from 1860 through 1897. U.S.S.R. took the lead from this nation in 1898 and held it through 1901. However, the United States regained the front position in 1902 and has not been overtaken since then. Since the first year of its supremacy, 1860, the United States has produced 50 per cent or more of world's production every year with these exceptions: 1898 to 1902, inclusive, 1953 and 1954. During the period 1907 through 1947 thenation's output was over 60 per cent of world's production each year, and in six of the years it produced 70 per cent or more of world's total.
There are several countries that should not be ignored despite the fact that they have not led the world as yet in production any year. A comparison of the maximum annual production of each of nine countries and the same year's production of the other eight countries is shown in Table 2. (See Fig. 2 also.) Six of the cited countries registered their maximum annual production in 1954. Probably all of these could produce more than they did in 1954. The percentage of the world's 1954 production credited to Iraq, Kuwait, and Saudi Arabia - and the known potentialities of these countries and Iran - suggest the direction in which the center of production is moving.
Andrew Well-Engineering Alliance: A New Industry Model
Authors: Gomersall S. D. , Klein R. J. , Clark Graham , Sneddon Ian , Simpson Michael 
Published: December 2007

Summary
The BP Andrew field has been developed using a novel business solution which required the creation of a Well Engineering Alliance with shared objectives, a radically new behavioral approach and jointly developed targets.
The paper describes the structure of the Alliance, the development and implementation process and the success that has been achieved.
A project update provides a summary of subsequent progress.