bluuebunny/crossref_metadata_2025_split huggingface dataset:
Measurement of Resistance to Flow of Fluids in Natural Gas Wells
Authors: Smith R.V. , Williams R.H. , Dewees E.J. 
Published: December 2007

Abstract
Transmission factors for the flow strings of gas wells were determined by tests on wells in six fields of Oklahoma, Texas, and Louisiana. Data were collected on 14 gas wells while gas was flowing through 1¼, 2, 2½, and 3-in. tubing and 5½ and 7-in. casing. The transmission factors developed from these data were found to follow the resistance equation published by Nikuradse for turbulent flow in "rough" pipes with an average absolute roughness of 0.000,65 in. This average absolute roughness is believed to be representative generally of the flow strings of gas wells with the exception of those that have been exposed to corrosion or other conditions causing undue roughness. Also, use of an absolute roughness of 0.000,65 in. probably will result in transmission factors that are more representative of gas-well conditions than those in common use today, provided that the transmission factors are calculated by the methods outlined in this report. The authors believe that use of these transmission factors will permit calculation of more accurate subsurface pressures in gas wells than those in use today.

Introduction
Engineers use transmission factors in flow equations to compute subsurface pressures in flowing gas wells from measured wellhead pressures. These subsurface pressures are necessary for determining the productivity of gas wells from "back-pressure" tests. The methods of calculating pressures in flowing gas wells, as outlined by Rawlins and Schellhardt in Bureau of Mines Monograph 7, are based on the transmission factors in the well-known Weymouth formula. Natural gas engineers have realized that errors introduced by using transmission factors as given by the Weymouth formula are relatively unimportant in testing low-capacity gas wells; but they also know that such factors are important considerations in testing large-capacity wells. Accordingly, the research described in this report was undertaken to fulfill the need for more accurate means of calculating subsurface pressures in gas wells.
This report is part of the Bureau's study of the flow of natural gas through pipe and commercial pipelines. Several of the conclusions regarding flow in the flow strings of gas wells were influenced by the results of the study of flow in horizontal pipelines. These instances are mentioned in the text of this report.
Coping with Nature Offshore An SPE-AIME Distinguished Lecture
Authors: Blenkarn Kenneth A. 
Published: December 2007

Introduction
The distinguishing feature of development for offshore petroleum is the need to provide a dry, stable working space from which personnel can operate in the conduct of conventional petroleum drilling and production. The industry has devoted substantial production. The industry has devoted substantial effort and money to meet the need for working platforms, in the form of either fixed or floating platforms, in the form of either fixed or floating structures. The design of these structures obviously requites expertise in structural engineering. Moreover, there is an accompanying need for competence in oceanography to understand the environmental forces in the ocean. Both structural engineering and oceanography are outside the traditional petroleum or mining engineering activity. Nevertheless, the offshore industry must employ, and in many cases contribute to advancements in, these technologies. Consequently, petroleum engineers are increasingly being called upon to direct work in these unfamiliar subjects. This conceptual introduction to offshore structures and the governing ocean environment is directed at those engineers.

Fixed Platforms
The basic element of offshore development is the fixed, bottom-supported structure or platform. While some platforms afford only minimal walkway area around a single well, many platforms support all the equipment and needs for both the drilling and the production operations. Early offshore platforms were production operations. Early offshore platforms were ordinarily pile-supported piers, such as are commonly observed in harbor installations. However, to meet the special needs of the offshore conditions, the industry has developed a "template" or "jacket-type" structure. There are three distinct components to these structures: the jacket itself, the piling, and the deck structure. The cross-braced jacket must extend from the ocean floor to above the water surface. It is generally assembled from tubular structural members in a fabrication yard. Subsequently, the jacket is moved onto a barge and transported to the off shore location. There it is launched or lifted into the water for placement at the prescribed site. (See Fig. 1.) Once the jacket is prescribed site. (See Fig. 1.) Once the jacket is in place, piling are lowered down through the tubular legs of the jacket and driven or otherwise installed deep into the ocean floor. The jacket and piling are then secured together, and the deck is raised to rest on top of the piles. (See Fig. 2.) Platform concepts and installation are discussed in Refs. 1 and 2. To install offshore platforms, which are very large structures, special construction equipment is necessary. Most impressive is the fleet of derrick barges serving mainly the offshore industry.
JPT
P. 257
Buy, Build, Beg or Borrow: Delivering Applications in the New Age of Software Development
Authors: Little Todd , Webb Steve 
Published: December 2007

SummaryIn the last decade, changes in the oil and computer industries have complicated the process of delivering software applications significantly. Although the oil industry has gone through extensive downsizing, computing advances have forced users to demand more complete and integrated computing solutions. Several oil companies responded to this problem with a policy of "buy, don't build." Although useful, this mindset does not address directly the real question of how to maximize and leverage limited resources to deliver the necessary applications to the user community efficiently. This paper delves beyond the bipolar buy vs. build question to present experiences with various approaches that have been used for delivering software. Among the methods we discuss are software tools, research institutions, vendor consortium projects, alliances, and industry standards.
Reservoir Simulation: Past, Present, and Future
Authors: Watts J. W. 
Published: December 2007

SummaryReservoir simulation is a mature technology; simulation results guide most major reservoir-development decisions in some way. Despite this maturity, the technology is changing rapidly, and both providers and users of reservoir simulation software must understand the future of these changes. This paper takes a long-term view of reservoir simulation, describing where it has been and where it is now. It closes with a prediction of what the reservoir simulation state of the art will be in 2007 and speculation regarding certain aspects of simulation in 2017.
Big Mineral Field Exploitation - A Challenge to Engineers
Authors: Garlick J.M. 
Published: December 2007

Abstract
Exploitation of the Big Mineral field, located in North Central Texas, has been and continues to be a challenge to the engineer. The field is partially inundated by the waters of Lake Texoma. Multizone oil production ranging in depth from 3,600 to 10,200 ft is found in steeply dipping Pennsylvanian and Ordovician sediments. This paper brings into sharp focus the contributions of each branch of engineering to the solution of the major development and production problems.
Based on comprehensive data gathered on early development wells, it was determined that the drilling of separate wells to each of six production horizons was justifiable. To accommodate wells drilled in the lake bed 32 earthen drilling platforms with earthen access roadways were planned and constructed. Each platform was of sufficient size to allow the drilling of from one to three wells. In order to combat crooked hole conditions and stimulate drilling rates "large size drill collars" and "jet bit" programs were followed. Hydraulic artificial lifting methods, remote control of flowing wells, and semi-automatic centralized storage facilities were provided so that production would not be interrupted should the earthen platforms be inundated by the lake.

Introduction
As in most industries management in the petroleum industry is relying more and more upon engineers to plan development and production projects. Where in the early days perhaps one engineer handled all engineering problems, companies now employ a staff of 10 or more engineers, each with a different engineering background and responsible for a specific phase of engineering. It therefore follows that if an integrated engineering plan is to be accomplished, all of these engineers must be consulted, work together in an atmosphere of understanding, and contribute their part to the master plan. This paper has been written for the purpose of showing how these principles have been applied to the variety of problems involved in the exploitation of the Big Mineral field. Consequently, no attempt is made to present a complete history of the field. Instead, only the major problems are highlighted. Special emphasis is placed on each engineer's contribution to the solution of these problems.
Variable Flow Rate Reservoir Limit Testing (includes associated paper 4262 )
Authors: Earlougher Robert C. 
Published: December 2007

With this technique, reservoir size can be estimated from pressure data taken from either production or injection wells operating on a cyclic rate schedule. So long as the requirement is satisfied that the flow rate vary cyclically rather than increasing or decreasing montonically, reservoir limit testing is quite simple and an engineer can accomplish it without computer aid.

Introduction
The conventional reservoir limit test1-4can be used to estimate reservoir size if the test well operates at a constant flow rate during the test. Unfortunately, it is not always feasible to perform a test at a constant rate, at least for more than a few hours. This is particularly true when flow rate varies cyclically as in oil wells that are pumped cylically, water supply wells, and waste-disposal wells.
This paper shows how to estimate reservoir size from pressure data in wells operating with a cyclic rate schedule. The method applies to both injection and production wells. The important requirement is the cyclic rate: rate must oscillate about a mean value within some relatively regular period. When this condition is satisfied, reservoir limit testing is fairly simple. This requirement can be relaxed, in which case there will be a corresponding reduction in the accuracy of the calculated result. This is an important consideration when the engineer has no control over the quality of data - for instance, when the engineer has several years of historical data from a well. If he knows only rate and pressure at several points in time, he cannot apply a very accurate, sophisticated analysis technique. The method of this paper allows him to estimate reservoir size from such data, although the accuracy may be less than desired. This method should not be used if a better approach is available. Its value lies in providing reasonable engineering estimates when conditions prevent testing and analysis under more ideal conditions.
We shall present here a theoretically sound reservoir limit testing procedure for a cyclic two-flow-rate situation. Simulated pressure-time data for more complicated rate schedules experimentally extend the analysis technique to more realistic situations. The analysis techniques and suggestions for its use are presented, and an example using data from an existing industrial waste-disposal well, is included for illustration.

Reservoir Limit Test Analysis
The familiar reservoir limit test1–4 requires that a well be operated at constant rate until pseudosteady-state-flow conditions have existed for some time. Then, reservoir size can be calculated fromEquation 1
where: q=flow rate for the well, STB/D
q&gt;0 for production, q&lt;0 for injection
m*=slope of the linear portion of the pressure vs flowing-time plot, psi/hr
The slope, m*, is the constant rate of pressure change during pseudosteady-state flow; m* is negative for production, positive for injection.
Asphaltenes, Water Films, and Wettability Reversal
Authors: Kaminsky R. , Radke C. J. 
Published: December 2007

Abstract
We present a transport model for asphaltene diffusion from an oil/water interface through a water film followed by adsorption at a solid/water interface. Using a Langmuir adsorption isotherm, the effects of asphaltene aqueous solubility and adsorption constant K on equilibration time are established. For K greater than 1 nm and for asphaltene solubilities down to 0.1 ppb, adsorption equilibrium, taken to be 1 mg/m2, occurs within a few hours. Negligible asphaltene solubility does not explain why a water film prevents asphaltene adsorption and wettability alteration in reservoir rock.
Lignosulfonate Stabilized Emulsions in Oil Well Drilling Fluids
Authors: Browning W.C. 
Published: December 2007

Abstract
Oil in water emulsions have become important in oil well drilling fluids. Lignosulfonates, prominent among various stabilizing agents, have been used successfully for several years in both lime-base and brine-based fluids. This paper is concerned with the surface active properties of the lignosulfonates, the characteristics of lignosulfonate stabilized emulsions, and their application to oil well drilling.
Lignosulfonates in solution may be regarded as subcolloidal, high molecular weight polyelectroyltes. They do not possess the hydrophobic-hydrophilic molecular structure or other attributes of the McBain "colloidal electrolyte." In general, lignosulfonates are not effective in lowering surface or interfacial tension of water solutions, but certain sodium lignosulfonates when used in combination with alkaline brines may lower interfacial tension.
Lignosulfonates stabilize emulsions because the lignosulfonate molecule is adsorbed at the oil-water interface, establishing a high order electrokinetic charge and also a semi-rigid film. Lignosulfonate stabilized emulsions are stable in high concentrations of inorganic electrolytes, stable to heat, freezing, and to mechanical action.
Drilling fluids with lignosulfonate stabilized emulsions may be prepared to control water loss independent of bentonite or organic colloids such as starch. Such fluids may possess low viscosity, low weight, and low water loss simultaneously. These fluids have low mud-making properties and are unaffected by the usual inorganic contaminants, yet if desired may be adjusted to raise viscosity and gel to form high weight muds.
A more complete understanding of the lignosulfonate and their potentialities may well aid in the development of drilling fluids designed to cope with certain of the many problems encountered in oil well drilling.

Introduction
Emulsion muds may be defined as water-base drilling fluids to which oil had been added and subsequently emulsified. These muds are relatively new to oil well drilling, the literature being rather meager until about 1949. Field use in recent years has brought emulsion muds into prominence as important and useful drilling fluids, but full knowledge of their potentialities is yet to be realized.
A New Tool for Perforating Casing Below Tubing
Authors: Caldwell Blake M. , Owen Harrold D. 
Published: December 2007

Abstract
The continued use of permanent-type well completion has pointed up the need for more powerful through-tubing perforating equipment. A new expendable shaped charge perforator has been developed in which the charges are run through the tubing in a vertical position and then opened out to a horizontal position when at the desired shooting zone. The performance of this new tool is comparable to that of conventional casing type perforators.
This paper describes the new tool and its applications. Performance data in targets and under various actual well conditions are presented.

Introduction
The general acceptance and increasing use of permanent-type well completion by the oil industry has indicated the need for through-tubing perforating equipment with performance comparable to that of conventional casing type perforators. To achieve the performance desired, a new, expendable, shaped charge perforator has been developed with adequate power for effectively perforating both 51/2 -in. and 7-in. casing below tubing. This has been accomplished without resulting severe damage to the casing and can be obtained under extremes of pressure and temperature. The design of this new tool is a radical departure from previous concepts of tubing guns since it was felt that the two major limitations imposed by previous designs severely handicapped performance.
The first of these limitations was the restriction imposed upon the length of the charges by the necessary small inside diameter of the carrier. This resulted from the necessity for compromises in designing a hermetically sealed gun small enough to allow free passage through 2-in. tubing, yet with sufficient wall thickness to withstand some minimum pressure. In an effort to overcome this limitation, the charges were in some cases placed at an angle with the axis of the well with resulting loss in effective depth of penetration.
Scheduling Gas Field Production for Maximum Profit
Authors: Huppler John D. 
Published: December 2007

Abstract
A mathematical procedure for finding the most profitable gas field production policy to meet a gas profitable gas field production policy to meet a gas sales contract has been developed. Results indicate profits can be increased through combinations of profits can be increased through combinations of earlier liquids production, increased gas recovery, and investment reduction. The optimal plan for operating a gas field is found by applying nonlinear programming to the over-all problem o production programming to the over-all problem o production rate scheduling. Risk is accounted for by specifying that any investment yield some minimum incremental profit-to-investment ratio. Computed results, an profit-to-investment ratio. Computed results, an illustrated by several example problems, include average and peak production rate schedules for each reservoir, well-drilling schedules in each reservoirs, a list of recompletions, and compression purchases for the field. Compression can be assigned purchases for the field. Compression can be assigned to each reservoir or it can be pooled in the field. Dynamic programming is used to find the best investment schedule in each reservoir. Each gas reservoir is assumed to have a uniform pressure distribution throughout. Water influx is described by the van Everdingen-Hurst analytic solution for a radial aquifer. In each reservoir, one set of gas-well deliverability curves for production to four delivery pressures is employed, and in-place facilities are always operated to minimize compression requirements.

The Single-Reservoir Problem
We shall solve the following optimization problem for a single gas reservoir: Given a desired gas delivery schedule and a specified peak delivery capability, find the optimal schedule for drilling new wells, the optimal plan for installing compressor horsepower, a detailed operating plan, and the total discounted profit for the best policy. We make the following assumptions in the analysis. 1. Pressure is uniform throughout the reservoir. This implies that well location is immaterial. 2. A single set of well deliverability curves is adequate. 3. The unsteady-state water influx equations satisfactorily describe aquifer behavior. 4. The optimum policy can be broken into two stages. In the first period, desired peak delivery capability is maintained through the addition of wells and compressive horsepower In the second period no new wells are drilled and no compression period no new wells are drilled and no compression is added; the reservoir flow rate declines.
Unsteady-State Pressure Distributions Created by a Well With a Single Infinite-Conductivity Vertical Fracture
Authors: Gringarten Alain C. , Ramey Henry J. , Raghavan R. 
Published: December 2007

Introduction
During the last few years, there has been an explostion of information in the field of well-test analysis. Because of increased physical understanding of transient fluid flow, it is possible to analyze the entire pressure history of a well test, not just long-time data as in conventional analysis.1 It is now often possible to specify the time of beginning of the correct semilog straight line and determine whether the correct straight lie has been properly identified. It is also possible to identify wellbore storage effects, and the nature of wellbore stimulation as to permeability improvement, or fracturing, and to quantitatively analyze those effects.
Such accomplishments have been augmented by attempts to understand the short-time pressure data from well testing - data that were often classified as too complex for analysis. One recent study of short-time pressure behavior2 showed that it was important to specify the physical nature of the stimulation in considering the behavior of a stimulated well. That is, stating that the van Everdingen-Hurst infinitesimal skin effect was negative was not sufficient to define short-time well behavior. For instance, acidized (but not acid-fractured) and hydraulically fractured wells might not necessarily exhibit the same behavior at early times, even though they could possess the same value of negative skin effect.
In the same manner, hydraulic fracturing leading to horizontal or vertical fractures could produce the same skin effect, but with possibly different short-time pressure data. This could then provide a way to determine the orientation of fractures created by this type of well stimulation. In fact, it is generally agreed that hydraulic fracturing usually results in one vertical fracture, the plane of which includes the wellbore. Most studies of the flow behavior for a fractured well consider vertical fractures only.3–11
Yet it is also agreed that horizontal fractures could occur in shallow formations. Furthermore, it would appear that notch-fracturing would lead to horizontal fractures. Surprisingly, no detailed study of the horizontal fracture case had been performed until recently.12 A solution to this problem was presented by Gringarten and Ramey.13 In the course of their study, it was found that a large variety of new transient pressure behavior solutions useful in well and reservoir analysis could be constructed from instantaneous Green's functions.14 Possibilities included a well with a single vertical fracture in an infinite reservoir, or at any location in a rectangle.