bluuebunny/crossref_metadata_2025_split huggingface dataset:
Laboratory Drilling Performance of the Full-Scale Rock Bit
Authors: Rowley D.S. , Howe R.J. , Deily F.H. 
Published: June 2014

Abstract
Laboratory drilling tests with 4 3/4-in. hard-formation rock bits were made under rock pressure and borehole fluid pressures simulating a 3,000-ft borehole. The effects of bit weight and rotary speed on drilling rate and bit rotary power were determined in a hard, impermeable dolomite. With added bit weight, the drilling rate and rotary power both increased at an increasing rate; but, with added rotary speed, the rate and power both increased at a decreasing rate. The rock volume removed per unit of energy increased as weight was raised or as rotary speed was reduced. Empiric quadratic equations for drilling rate and rotary power were obtained and bit mechanical efficiency was calculated.

Introduction
During the past three years, Jersey Production Research Co. has performed an extensive series of tests using roller cone, drag and diamond bits varying in size from 3 3/4 to 9 7/8 in. These tests have been made under a wide range of drilling conditions in several types of rocks at both atmospheric pressure and elevated pressures simulating depths to 3,000 ft. This paper reports the effects of bit weight and rotary speed on the penetration rate of and power consumed by a 4 3/4-in. hard-formation rock bit drilling in impermeable dolomite.
The laboratory work reported here supplements and extends previously published data describing the effects of bit weight and rotary speed on drilling rate from tests made at atmospheric pressure. Similarly, the effects of pressure have been previously investigated, using 114-in. "microbits", and the effects on drilling rate of pressure and fluid environments have been reported. Several investigators have also studied certain theoretical aspects of the roller-cone rock bit performance problem. Despite this work, however, there are no published data available on the performance of field sized bits under controlled laboratory conditions which simulate the down-hole pressure environment. There also is very little information in the referenced papers on the amount of power consumed by the bit. Therefore, the purposes of this paper areto present laboratory performance data on a field-sized bit to aid in the interpretation of field test results, andto make data available on the rotary power at the bit.
It is hoped that this information will stimulate industry studies of energy consumption in rotary drilling and lead to the improvement of drill-bit efficiency.
New Correlations for Dew-Point Pressure for Gas Condensate
Authors: Al-Dhamen Mohammad , Al-Marhoun Muhammad 
Published: June 2014

AbstractNew Models with three different techniques have been developed to predict the dew-point pressure for gas condensate reservoirs. Traditional correlations, non-parametric approaches and artificial neural networks have been utilized in this study. The new models are function of easily obtained parameters (reservoir temperature, gas specific gravity, condensate specific gravity and gas-oil ratio). A total number of 113 data sets obtained from Constant Mass Expansion experiment (CME) were collected from Middle East fields; has been used in developing the models. The data used for developing the models covers a reservoir temperature from 100 to 309 oF, gas oil ratios from 3,321 to 103,536 SCF/STB, gas specific gravity from 0.64 to 0.82 and condensate specific gravity from 0.73 to 0.81. The artificial neural network developed in this study has the best results among all other models with an average absolute error of 6.5%. Graphical and statistical tools have been utilized for the sake of comparing the performance of the new models and empirical models available in literature.
The Evaluation of Vertical-Lift Performance in Producing Wells
Authors: McAfee R.V. 
Published: June 2014

Abstract
The fundamentals of vertical-lift performance are examined with the aid of computer-calculated flowing gradient charts. Flowing and gas-lift well performance characteristics are determined from available well test data. The effect of tubing size, gas-liquid ratio and wellhead pressure is discussed for both flowing and gas-lift wells. The effect of gas-injection pressure, formation gas, bottom-hole pressure and valve spacing is also discussed for gas lift wells. From these studies conclusions may be reached for improving or prolonging natural flow, obtaining optimum lift efficiency when natural flow ceases and improving existing gas-lift systems. The techniques perfected satisfy the requirement that the time involved to conduct an evaluation be practical for operating personnel.

Introduction
Flowing pressure gradients furnish the key to successful evaluation of vertical-lift performance in producing wells. Command of multiphase flow gradients in some readily usable form is a necessity before operating personnel can competently include vertical-lift performance evaluation of both flowing and artificial-lift wells in their over-all consideration of production efficiency. A readily usable form cannot be overemphasized since most of the decisions which confront the production engineer with a problem well must be made quickly. In moving a barrel of oil from the reservoir to the stock tank, the major portion of energy generally is expended in the vertical-lift phase. This may or may not be of concern during the flowing life of a well, depending upon the production requirements. It becomes of some concern when the flow performance of the well becomes erratic, and a conscious effort must be made to maintain natural flow. It is at this time that the first steps may be taken to modify existing conditions to relieve unnecessary limitations to proper flow.
When natural flow ceases and some form of artificial lift must be installed, the amount of energy expended in lifting liquids becomes quite obvious. It is at this time, if no other, that lifting efficiency becomes important because that part which must be supplied from an outside source is now related directly as a cost per barrel of oil produced.
Influence of Property Modeling Practices on Estimated Hydrocarbon Pore Volume
Authors: Bust Vivian K. , Worthington Paul F. 
Published: June 2014

SummaryThe emergence in geoscience of 3D geocellular modeling has raised questions about the correspondence of hydrocarbon volumetric deliverables with those derived from 2D zonal modeling. These differences of approach are compounded because the contemporary 3D methods use net-reservoir volumetric algorithms whereas the more established 2D methods have traditionally used net-pay volumetric algorithms. Both methods are initialized using 1D “along-wellbore” datasets. Key parameters for comparison are initial hydrocarbon pore volume (IHPV) for 2D and 3D modeling and equivalent hydrocarbon column (EHC) for 1D along-wellbore modeling.The focus is twofold. The first objective has been to generate a functional petrophysical model as a basis for volumetric comparisons. The reservoir notionally comprises an oil accumulation within a water-wet, lithologically-clean sandstone that is partially saturated with high-salinity brine. The sandstone comprises five rock types (RTs), each of which has a defined set of interpretive algorithms. The second objective has been to compare static volumetric estimates of EHC and/or IHPV for a range of case models. This objective was approached using three workflows. Initially, 1D along-wellbore screening studies used different case models representing various stratigraphic sequences. These allowed a preliminary assessment of results arising from the use of net-reservoir and net-pay volumetric algorithms without the influence of mapping practices. The findings were corroborated by field studies. Second, 2D zonal modeling led to values of IHPV based on both net-reservoir and net-pay algorithmic protocols. Third, 3D geocellular modeling also led to values of IHPV based on both protocols. These data allowed equitable comparisons of 2D zonal deliverables with those from 3D geocellular models because a consistent inter-well interpolation methodology was used for all 2D and 3D cases.The analysis incorporated the influence of stratigraphic sequences of the five RTs with their different petrophysical characteristics. Comparisons of 2D and 3D models showed that IHPV values delivered by established 2D zonal models with net-pay algorithmic protocols are mostly lower than those values delivered by contemporary 3D geocellular models with net-reservoir protocols by approximately 4% on average, but the differences are highly variable. These outcomes, which have implications for reserves estimation, are strongly governed by the stratigraphic distribution of the RTs. They re-emphasize that each case must be investigated separately and thoroughly.
Chlorine Logging in Cased Holes
Authors: Dewan J.T. , Stone O.L. , Morris R.L. 
Published: June 2014

Abstract
A new chlorine logging tool, developed primarily for the detection of oil saturation behind casing, is described. The principle involved is the selective detection of gamma radiation from neutron capture in chlorine. The tool is relatively insensitive to porosity, responding mainly to the concentration of chlorine in the interstitial liquid rather than to the total chlorine content in the formation.
A brief review of the fundamentals of chlorine logging is given. This includes a discussion of the partition of neutron captures in clean sand and limestone formations, and the spectra of gamma rays obtained. The effect of neutron capture in iron is shown to be important.
Following a short description of the logging tool, the laboratory-determined response of the instrument in cased sandstone formations is presented. It is shown that better results can be obtained by logging in empty casing than in casing filled with oil, fresh water, or salt water. Effects of neutron capture in the casing, casing liquid, cement annulus and formation matrix are discussed.
A method of interpreting the Chlorine log, based on the use of the response curves, is explained. This is illustrated with several field examples which also show comparisons of electrical and Chlorine logs. In Gulf Coast formations, the Chlorine log often bears a marked resemblance to the SP curve, and in some cases water-oil contacts have been identified by a visual comparison of the two curves. Comparison of the Chlorine log with a neutron log is also valuable in interpretation. The role of the neutron log is to give a porosity (which need be approximate only), to indicate formation shaliness and, most important, to identify gas which is generally indistinguishable from oil on the Chlorine log.
The Chlorine log should prove most useful in old wells where adequate open-hole logs do not exist, or where saturation conditions in the producing zone have changed. The combination of the Chlorine log with a Cement Bond log and the wireline formation tester should aid materially in successful reworking of such wells.
Natural Gas Hydrates at Pressures to 10,000 psia
Authors: McLeod Harry O. , Campbell John M. 
Published: June 2014

Abstract
This paper presents the results of the data obtained in the first stage of a long-range study at high pressures of the system, vapor-hydrate-water rich liquid-hydrocarbon rich liquid. The data presented are for the three-phase systems in which no hydrocarbon liquid exists. Tests were performed on 10 gases at pressures from 1,000 to 10,000 psia. One of these was substantially pure methane, and the remainder were binary mixtures of methane with ethane, propane, iso-butane and normal butane.
Several conclusions may be drawn from the data.Contrary to previous extrapolations, the hydrocarbon mixtures tested form straight lines in the range of 6,000 to 10,000 psia which are parallel to the curves for pure methane, when the log of pressure is plotted vs hydrate formation temperature.The hydrate formation temperature may be predicted accurately at pressures from 6,000 to 10,000 psia by using a modified form of the Clapeyron equation. The total hydrate curve may be predicted by using the vapor-solid equilibrium constants of Carson and Katz to 4,000 psia and joining the two segments with a smooth continuous curve between 4,000 and 6,000 psia.The use of gas specific gravity as a parameter in hydrate correlations is unsatisfactory at elevated pressures.The hydrate crystal lattice is pressure sensitive at elevated pressures.

Introduction
Prior to 1950 many studies had been made of the hydrate forming conditions for typical natural gases to pressures of 4,000 psia. Most of these attempted to correlate the log of system pressure vs hydrate formation temperature, with gas specific gravity as a parameter. One of the more promising correlations was made by Katz, et al, which utilized vapor-solid equilibrium constants. The only published data above 4,000 psia are those of Kobayashi and Katz for pure methane to a pressure of 11,240 psia. In the intervening years, most published charts for the high-pressure range have represented nothing more than extrapolations of the low-pressure data, with the methane line serving as a general guide. The reliability of these charts has become increasingly doubtful (and critical) in our present technology as we handle more high-pressure systems.
Theory of Formation Cutting Using the Sand Erosion Process
Authors: Brown Robert Wade , Loper Jack L. 
Published: June 2014

Abstract
The process of sand erosion has been harnessed to perform a useful function-the directed perforating of oilfield tubular goods and formation rock. In this process the sand is carried by a liquid medium and the resulting slurry is forced through a nozzle at an extremely high velocity. Upon impingement against casing or formation, the fast-moving sand particles erode a perforation in the casing followed by cavity formation in the medium behind the casing. The many factors influencing the rate and extent of this penetration are inherently difficult to establish experimentally. Equations describing submerged jet behavior have been applied to these conditions. The following paper develops the equations for predicting the performance of the perforating jet.

Introduction
The cutting power of high-velocity sand has been well known in the petroleum industry for many years. Sand carried by a high-velocity gas stream causes severe erosion. This effect has been the cause of numerous production problems in certain areas.
It was logical to expect that this phenomenon would one day be adapted to useful industrial applications. Development of mobile, high-pressure, high-horsepower pumping equipment in the last decade has made this possible.
The sand erosion process involves pumping a fluid containing abrasive solids through a set of nozzles at a high differential pressure (2,000 to 4,000 psi). The pressure conversion into kinetic energy imparts high velocity to the sand particles which, upon impact with the formation face or casing wall, erode the material in an organized pattern.
This paper attempts to establish the effects of the various parameters and to predict the performance and limitations of the process. The following factors will be considered: nozzle differential pressure, perforation size, sand concentration, nozzle stand-off distance and back-pressure. In general, this discussion is presented along theoretical lines and is substantiated by field results and data where reliable field data exists.
Characterization of the San Miguel Sandstone by A Coordinated Logging and Coring Program
Authors: Knutson C.F. , Conley F.R. , Bohor B.F. , Timko D.J. 
Published: June 2014

Abstract
Analyses of the cores and logs from 12 core test wells randomly spaced about a producing well showed that the average producing-zone rock properties are rather uniform within a single well's drainage area.
The dense zones have a limited horizontal continuity. They form barriers to vertical fluid migration which generally are not effective areally over distances greater than 50 ft.

Introduction
The petroleum engineer is frequently faced with the problem of characterizing a reservoir to aid in development or production operations. In general, two approaches are used -all the available data may be lumped and one specific "average" value obtained for each parameter, orthe datum points may be assigned coordinates and the system characterized by an array of values throughout a space frame.
In following this second course, the variation in the parameters is a critical factor.
Everyone is aware of the very small fraction of the reservoir which can be sampled. In this characterization of the San Miguel–1 sand, Sacatosa field, Maverick County, Tex. (see Fig. 1) with data obtained from a coordinated coring and logging program, this small sample limitation has been handled by dividing the apparent formation variation into four components:inherent measuring variations,wellbore variations,well drainage area variations, and (4) field-wide variations in rock properties.
Data on each of these components are presented in the following sections.
Validation of Predicted Cumulative Sand and Sand Rate Against Physical-Model Test
Authors: Rahmati Hossein , Nouri Alireza , Vaziri Hans , Chan Dave 
Published: June 2014

Summary
This paper presents a numerical model to study the onset and rate of sand production and compares its predictions against physical-model testing data on Salt Wash South (SWS) sandstone. A reliable sand-prediction tool is essential in sand-production management. It enables engineers to improve well-completion design, with the aim of maximizing well productivity without compromising well integrity.
A sanding test on a weakly consolidated sandstone sample was numerically simulated using a finite-difference-based numerical model. The model is based on erosional mechanics in which coupling between fluid flow and mechanical deformation captures some of the key mechanisms that are involved in sand production. Sand is assumed to be produced when the material is fully degraded and hydrodynamic forces are high enough to remove the particles.
The outcome of the numerical model shows a reasonable agreement against perforation-test results in terms of the onset and rate of sand production. The model shows that sand production initiates from the perforation tip and propagates to the top and sides of the perforation cavity. The sanding rate increases at higher flow rates. Furthermore, the model predicts external deformations of the sample, which are in close agreement with the experimental observations.
Pressure-Transient Behavior of Continuously and Discretely Fractured Reservoirs
Authors: Kuchuk Fikri , Biryukov Denis 
Published: June 2014

SummaryFractures are common features of many well-known reservoirs. Naturally fractured reservoirs contain fractures in igneous, metamorphic, and sedimentary formations. Faults in many naturally fractured carbonate reservoirs often have high-permeability zones, and are connected to many fractures with varying conductivities. Furthermore, in many naturally fractured reservoirs, faults and fractures can be discrete (i.e., not a connected-network fracture system). New semianalytical solutions are used to understand the pressure behavior of naturally fractured reservoirs containing a network of discrete and/or connected (continuous) finite- and infinite-conductivity fractures. We present an extensive literature review of the pressure-transient behavior of fractured reservoirs. First, we show that the Warren and Root (1963) dual-porosity model is a fictitious homogeneous porous medium because it does not contain any fractures. Second, by use of the new solutions, we show that for most naturally fractured reservoirs, the Warren and Root (1963) dual-porosity model is inappropriate and fundamentally incomplete for the interpretation of pressure-transient well tests because it does not capture the behavior of these reservoirs.We examined many field well tests published in the literature. With few exceptions, none of them shows the behavior of the Warren and Root (1963) dual-porosity model. These examples exhibit very diverse pressure behaviors of discretely and continuously fractured reservoirs. Unlike the single derivative shape of the Warren and Root (1963) model, the derivatives of these examples exhibit many different flow regimes depending on fracture distribution and on their intensity and conductivity. We show these flow regimes with our new model for discretely and continuously fractured reservoirs. Most well tests published in the literature do not exhibit the Warren and Root (1963) dual-porosity reservoir-model behavior. If we interpret them by use of this dual-porosity model, then the estimated permeability, skin factor, interporosity flow coefficient (λ), and storativity ratio (ω) will not represent the actual reservoir parameters.
Management Systems Approach to Managing Human Rights Issues
Authors: Nguyen Tam , Herzog Gabriella , Fokkema Bert , Vallat Julie , Cleland Roper 
Published: June 2014

Abstract
There has been a proliferation of external guidance and guidelines for managing human rights issues. While these are useful tools to inform the management of potential risk, at best they may offer abstract concepts or aspirations of performance. In many respects, existing management systems and processes have the requisite components to identify, assess, prevent and/or manage potential human rights issues. The paper will examine existing management systems in oil and gas companies for addressing potential human rights issues.
The purpose of the paper is to describe how IPIECA, the global oil and gas industry association for environmental and social issues, has responded to the emergence of external guidelines in connection to designing and implementing the due diligence process consistent with the United Nations (UN) Guiding Principles on Business and Human Rights.
Stability of In-Situ-Combustion Process to Stoppage of Air Injection
Authors: Turta Alexandru T. 
Published: June 2014

Summary
Unlike steam injection for heavy-oil recovery, the in-situ-combustion (ISC)process requires an extra step--namely, the initiation of the process, theso-called ignition operation. During ignition, an ISC front is generated nearthe air-injection well and, thereafter, this front is propagated towardproduction wells. Air-injection interruptions can be unintentional orintentional, including scheduled interruptions for 1 day per month for cleaningoil from air lines exiting the compressors. Regarding air-injectioninterruptions, one question arises: Can the process be resumed withoutinitiating a new ignition operation? This paper attempts to provide answers tothis question. The paper reviews information on 10 cases of air-injectionstoppage in the field, involving well-instrumented dry ISC projects, conductedeither in patterns or in a line-drive system. Most of the cases are from theSuplacu de Barcau (Romania) project, which is the world's largest ISCcommercial project. The duration of air-injection interruptions ranged from afew hours to 42 days. Performance before and after interruptions is analyzed interms of changes in air injectivity, effluent-gas composition, and oilproduction. To support various field observations, essential results fromsimulation of the dry ISC process are also included; temperature distributionsduring air-injection stoppage were determined analytically for a linear systemand numerically for a radial system. In both cases, a specific characteristicof the temperature redistribution was noted: the move/shift of the peaktemperature inside the former burned-out zone. Some additional conclusionsregarding the stability of the process as a function of elapsed time since theinitiation of the process were also formulated. Stability of the process wasinvestigated for air-injection interruptions lasting up to 40 days.