bluuebunny/crossref_metadata_2025_split huggingface dataset:
Thoughts on Simulating the VAPEX Process
Authors: Cuthiell Dave , Edmunds Neil 
Published: June 2014

Summary
The vapour extraction (VAPEX) process and its many hybrid variants have attracted a great deal of attention as potentially lessenergy-intensive alternatives for exploiting heavy-oil and bitumen resources. However, despite significant work over the past 2 decades, uncertainty remains about the basic mechanisms, the scaling aspects, and the most appropriate methods of numerically simulating these processes. This paper offers some insights into several of these outstanding questions. The questions are examined in the context of an extensive and well-documented set of VAPEX experiments carried out by Maini and his colleagues over the past 10 years.
We have experimented with different methods of simulating these experiments using a physics-based reservoir simulator. Despite the high permeability (greater than 200 darcies in all of the experiments), we find that capillary pressure plays a significant role in the drainage. The simulations suggest that most of the drainage takes place in the capillary transition zone along the edge of the vapour chamber, rather than in the single-phase zone ahead of it which has not yet been contacted by vapour. It has been emphasized in the literature that the near-linear scaling of oil rate with height observed in the experiments is dramatically different from the square-root-of-height dependence predicted by the original analytic model of VAPEX. However, the experiments also show an increasing solvent fraction in the produced-oil phase as height increases. When this "solvent mixing" effect is separated from the rates, the remaining height dependence is less than linear, though still greater than square root of height. The relative roles of molecular diffusion and mechanical dispersion in VAPEX have been discussed widely in the literature.
Generally, mechanical dispersion is expected to play a larger role in these high-permeability experiments (compared with the field) because of larger fluid velocities. We present a method of inferring the diffusion/dispersion present in the simulations, despite a hidden component of numerical dispersion caused by the numerical method itself. We find that the experiments are well matched with values of diffusion and dispersion in line with literature correlations, and that the contribution of mechanical dispersion is perhaps not as large as might be expected relative to that of molecular diffusion.
The paper also provides some thoughts on questions we expect are still unanswered, including mechanisms behind the height dependent mixing phenomenon and the scaling of the experimental results to the significantly greater heights and lower permeability characteristic of the field.
Reduction of Friction Loss in Fracturing Operations
Authors: Ousterhout Ray S. , Hall Colby D. 
Published: June 2014

Abstract
In modern fracturing treatments, friction loss in pipe often has been the limiting factor in obtaining high injection rates desired for maximum effectiveness. Additives now available can reduce the friction loss of water by 70 per cent, permitting horsepower savings or higher injection rates, and completion of wells with smaller-size casing. The additives are used at very low concentrations for reducing friction loss. Higher concentrations give even lower friction loss, even though these fluids are viscous enough to give effective viscosity control of fracture leak-off. The friction-loss reduction is attributed to viscoelasticity of the solutions, which partially suppresses turbulence.

Introduction
The major trends in hydraulic fracturing during recent years have been the use ofhigher injection rates,more efficient fluids andengineering methods in designing the treatments.
These trends focus attention On the friction pressure-drop in pipe as a major factor in the operation. The cost of power used in overcoming friction does not contribute to increasing the fracture area achieved. A surface pressure limit, set by the strength of the pipe, often determines the maximum attainable injection rate. This rate may not be high enough to give the most efficient treatment in terms of fracture area per dollar spent.
The use of chemical additives to reduce friction loss in pipe significantly improves efficiency in fracturing treatments. It is known that the soap-gelled crude oils used in fracturing have lower friction losses than the same crude oils without gelling agents. In fracturing with brine or fresh water, still larger reductions of friction losses have been attained by two types of materials: a natural gum polymer and, more recently, a synthetic water-soluble polymer. Besides reducing friction loss, both additives are used to thicken fresh water, and the natural polymer thickens brine. Such "gelled water" has a low sand-falling rate and good viscous control of leak-off from the fracture.
Wanted Dead or Live: Crude-Cocktail Viscosity--A Pseudocomponent Method to Predict the Viscosity of Dead Oils, Live Oils, and Mixtures
Authors: Yarranton Harvey , van Dorp Johan , Verlaan Marco , Lastovka Vaclav 
Published: June 2014

Summary
A broadly applicable methodology is presented to reliably predict crude-oil-liquid viscosity from a gas-chromatographic (GC)-assay composition only (C30+ is recommended). The viscosity model employs a Walther-type correlation of double-log viscosity with log temperature to predict the viscosity of dead and live crude oils and mixtures. The model has three parameters: the slope and intercept of the Walther plot and a viscosibility factor to account for pressure effects. Simple mass-based mixing rules are applied on these three parameters to obtain mixture viscosity. The three parameters were correlated to component molecular weight (MW); therefore, a gas-chromatographic assay is the only required input apart from the temperature and pressure. The methodology was developed from a western Canadian (WC) data set of two bitumens, one heavy oil, and one condensate, and then tested on an independent data set of 10 conventional and heavy crude oils from the Gulf of Mexico, the Middle East, Asia, and Europe. The model provides untuned viscosity predictions within a factor of two of the measured values for dead and live crude oils ranging in viscosity from 0.5 to 500 000 mPa·s. A single multiplier is used to tune the model. Models tuned to dead-oil data predict live-oil viscosities and those of mixtures of oils with solvents to within 30% of the measured values. Models tuned to the viscosity at the saturation pressure predict the effect of temperature and pressure to within 20% of the measured values. The method retains its accuracy when components are lumped into a few pseudocomponents and is suited ideally for use in simulators for accurate liquid-phase viscosity predictions over a wide range of compositions, pressures, and temperatures. It would be necessary to include the proposed mixing rules in numerical simulators. An additional advantage of the method is the reduction in viscosity measurements needed to construct an accurate viscosity model.
Nabucco Gas Pipeline Project - A Challenging Project in the Prequalification Phase
Authors: Kuepper Michael , Roloff Joachim 
Published: June 2014

Abstract
The Nabucco Gas Pipeline is a transit and transport pipeline that will serve as a connection of several gas reserves in the Caspian Region as well as the Middle East to Europe. The Nabucco Gas Pipeline is one of the longest pipelines in the world. It has a length of approx. 3.300 km and will run from Turkey to Austria via Bulgaria, Romania and Hungary. Owner and operator of the Nabucco Gas Pipeline is the Nabucco Gas Pipeline International GmbH (hereafter: NIC). The company consists of the following 6 international shareholders: BOTAS (Turkey), Bulgarian Energie Holding (Bulgaria), Transgaz (Romania), MOL (Hungary), OMV (Austria) and RWE (Germany).
NIC has been supported by TUV Rheinland during the prequalification phase for suppliers of long lead items. Additionally TUV Rheinland assumed the task of reviewing and verifying material specifications prepared by the owner's engineer (hereafter: OE). NIC wished to identify the most capable suppliers for the Nabucco Gas Pipeline Project. TUV Rheinland very effectively implemented this project goal by evaluating suppliers’ technical competences, quality and performance ability.
On the basis of technical and commercial criteria companies have been preselected during the "desktop study". In the next step those preselected and found capable companies have been audited on site. In total, TUV Rheinland audited 73 vendor sites in 20 different countries for the Nabucco Gas Pipeline Project. This represented a huge challenge in both logistics and time. Due to its worldwide presence in 61 countries on all continents and its international network of inspectors TUV Rheinland mastered this challenge successfully and managed to provide NIC with the requested high quality results. TUV Rheinland prepared an absolutely traceable and non discriminating evaluation model to prevent any kind of claims in the course of the prequalification phase as the process’ traceability was of highest significance for NIC.
The result of TUV Rheinland's work has been the identification of the most capable suppliers of long lead items as well as the top performing companies and the detection of potential risks which might occur during the production process.
The prequalification process provides valuable information for both the procurement and the subsequent production process which shows TUV Rheinland's importance and relevance within the Nabucco Gas Pipeline Project.
An Engineer's View of Federal Income Taxes
Authors: Eggleston W.S. 
Published: June 2014

History of the Income Tax
Although income tax and income tax calculations are discussed, it is not intended that this analysis encourage a valuation engineer to become his own tax expert. Tax matters should be referred to a tax specialist whose field is as broad as that of a petroleum or valuation engineer.
Our income tax laws and regulations had their beginning with the Revenue Act of 1913 which levied the first income tax in the United States. Since that time, the revenue acts of 1916, 1918, 1921, 1924 and 1926 have changed or modified the ground rules of the income tax regulations as applied to oil and gas production and income.
Federal income tax legislation since 1926 has provided for two types of depletion allowance for oil and gas producers:percentage depletion at 27 per cent of gross income, not to exceed 50 per cent of net income; andcost depletion. For the purpose of computing the depletion allowance, percentage depletion is applied separately to the income from each oil and gas property.
Property, for Internal Revenue purposes, means each separate interest owned by the taxpayer in each mineral deposit in each separate tract or parcel of land (unless aggregated).
Until 1954, no specific statutory authority existed for the election to deduct intangible drilling costs as an expense. The revenue acts of 1918 and 1921 gave this election by implication but not specifically. The Internal Revenue Act of 1954 gave specific statutory expression to the taxpayer's first-year option of capitalizing or expensing intangible drilling costs.
A New Method To Predict the Performance of Gas-Condensate Reservoirs
Authors: Al-Shawaf Ali , Kelkar Mohan , Sharifi Mohammad 
Published: June 2014

Summary
Gas-condensate reservoirs differ from dry-gas reservoirs. The understanding of phase and fluid flow-behavior relationships is essential if we want to make accurate engineering computations for gas-condensate systems. Condensate dropout occurs in the reservoir as the pressure falls below the dewpoint, resulting in significant gas-phase production decreases.
The goal of this study is to understand the multiphase-flow behavior in gas-condensate reservoirs and, in particular, to focus on estimating gas-condensate-well deliverability. Our new method analytically generates the inflow-performance-relationship (IPR) curves of gas-condensate wells by incorporating the effect of condensate banking as the pressure near the wellbore drops below the dewpoint. The only information needed to generate the IPR is the rock relative permeability data and a constant-composition-expansion (CCE) experiment.
We have developed a concept of critical oil saturation near the wellbore by simulating both lean and rich condensate reservoirs and have observed that the loss in productivity caused by condensate accumulation can be closely tied to critical saturation. We are able to reasonably estimate re-evaporation of liquid accumulation by knowing the CCE data.
We validated our new method by comparing our analytical results with fine-scale-radial-simulation-model results. We demonstrated that our analytical tool can predict the IPR curve as a function of reservoir pressure. We also developed a method for generating an IPR curve with field data and demonstrated its application with field data. The method is easy to use and can be implemented quickly. Another advantage of this method is that it does not require the knowledge of accurate production data including the varying condensate/gas ratio (CGR).
Mud Analysis Logging
Authors: Pixler B.O. 
Published: June 2014

Abstract
Mud analysis logging is a direct method of detecting oil and gas in formations drilled. The factors that determine the hydrocarbon content of the drilling mud are discussed. The advantages and disadvantages of the various techniques for separation of gas from the mud and for gas detection are considered.
Examples included show field results of the latest mud logging development - the quantitative analysis of drilling mud for volatile hydrocarbons. Mud analysis provides the means for obtaining valuable formation information not otherwise available. Now, the system furnishes even greater diagnostic data for interpretation.

Introduction
Mud analysis well logging is not a recent development. Even before the introduction of rotary drilling, cable tool drillers logged their hole with ballings. The early rotary drillers kept a watchful eye on the mud returns for telltale gas bubbles. They continued to examine formation fragments - this time bit cuttings - removed from the mud by screens or by settling. The "feel" of the bit told them whether they were drilling in sand or shale, and changes in rates of penetration indicated changes in subsurface rock strata. Tops and thicknesses of formations were logged on the rotary drilling reports.
Mud logging technology has come a long way since 1939 when it was first introduced commercially. While all mud logging techniques have been continually improved, the greatest strides in development have been made in Mud gas separators and mud gas detectors.

Release of Hydrocarbons to Mud Flow
The most important diagnostic in mud analysis logging is the record of gas detected in the mud. Hydrocarbons in the formation drilled are released to the mud flow, first, at the instant the section is drilled and, second, by gas expansion in cuttings as the mud pressure decreases while the cuttings are carried to the surface. The relative concentration in mud of hydrocarbons released from the reservoir rock during drilling depends on the extent to which the rock is flushed by the mud filtrate and on the rate of mud circulation. The following three factors influence the amount of flushing.
Technology of High-Pressure Transport of Multicomponent Hydrocarbon Gases
Authors: Vykhodtsev A. V. , Panov R. A. 
Published: June 2014

Abstract
The main problem of pipeline transport of associated petroleum gas (APG) and natural gas – the need for transfer of a multicomponent hydrocarbon mixture. The purpose of this paper is the disclosure of technical, methodological, and economic aspects of a comprehensive approach to training, transportation and processing of gas through the use of supercritical states of multicomponent hydrocarbon mixtures for deposits of oil company OAO "Rosneft" in the Western and Eastern Siberia. The development of this technological approach allows oil and gas organizations to more effectively utilize resources and achieve routine associated gas utilization degree of the problem which, to date, is associated with a weak refinement and low cost-effectiveness of technologies proposed for utilization of associated gas. Of particular importance in this context takes the introduction of innovative technologies capable of solving many problems faced by the subsoil user during transportation of hydrocarbon gases.
Techniques of Electric Log Interpretation
Authors: Atkins E.R. 
Published: June 2014

Abstract
The generally used techniques of electric log interpretation are reviewed and discussed, including the determination offormation water resistivity from the SP curve,true resistivity values from log data,water saturation from electric logs, andformation porosity from resistivity data.
Particular emphasis is placed on the assumptions made in log interpretation. It is hoped that efforts will be stimulated which, in the future, will make it possible to reduce the number of assumptions necessary for log interpretation.

Introduction
Petroleum engineering and geology can be said to be based upon both facts and assumptions. So too, are the various techniques of electric log interpretation. For the last few years, some assumptions which have been made in developing log interpretation methods have been repeated so often that they are now accepted by many persons as facts. In reviewing the principles of resistivity and potential curve interpretations, many of the assumptions (and how they affect the results of interpretation) will be considered.
Because this is a review, the purpose of this paper is not to present new methods of interpretation. However, the reader of this review should be stimulated to consider whether he should accept these assumptions as they are made now or whether he would prefer to explore possible ways to reduce the number of assumptions required for log interpretation.

Assumptions
To emphasize the assumptions used in most interpretations of electric logs, they will be tabulated here and then referred to as each technique of interpretation is discussed. No particular emphasis is inferred by the order of tabulation.
Use of Liner Drilling Technology as a Mitigation to Lost Circulation in The Faja De Oro (Golden Lane) Oil Fields Offshore Veracruz, Mexico
Authors: Aguilera Naveja L. F. , Fermin G. R. , Ramos R. Gamiño , Rosenberg Steven M. , Dominguez M Marco A. 
Published: June 2014

Abstract
This paper will demonstrate the benefit of liner drilling technology to drill and cement an operator's 9-5/8" and 7" liners in place allowing for the continued development of oil reserves from the naturally fractured El Abra formation in the Carpa and Bagre fields of the Faja de Oro area. Prior to the introduction of liner drilling, two previous wells drilled in the Carpa field encountered massive lost circulation and hole instability while drilling into the El Abra limestone resulting in a total of 55 days of NPT (non productive time) for the two wells. An estimated 2,700 bbls of fluid were lost in these wells with both wells having to be sidetracked to reach their El Abra objective. The total economic impact related to this NPT was estimated at USD$ 5.68 MM.
Liner drilling technology has been identified as the most suitable solution to isolate the loss and hole instability intervals because:
Documented lost circulation problems have been mitigated through use of liner drilling technology due to the "smear effect" phenomenon, especially in shale fractured zones, before reaching chalk intervals. Also the narrow annular geometry characteristic of liner drilling allows for management of the annular fluid level. The hydraulic liner system selected provided for high torsional capacity as well as excellent cyclic fatigue resistance, key criteria for liner drilling operations. Additionally this system had been proven in multiple liner drilling operations. The drillable PDC casing bit was capable of drilling the respective required hole sections.
The nine wells portrayed in this paper incorporated liner drilling in their respective basis of design allowing the operator to reach the intended liner setting depths, eliminating contingency liners, and ultimately meeting well construction objectives. The equipment selection, operation, results, and lessons learned will be presented, also have been optimized due to the numbers of well drilled consecuently.
Comparing Soft-String and Stiff-String Methods Used to Compute Casing Centralization
Authors: Gorokhova Lidia , Parry Andrew , Flamant Nicolas 
Published: June 2014

Summary
Good casing centralization during cementing operations is a key factor for achieving proper mud displacement and obtaining hydraulic isolation in the annulus. To this end, centralizers are often placed along the casing to position it centrally in the borehole. The optimal number of centralizers and their spacing are determined with simulation software.
Until now, the industry has typically used calculation methods derived from American Petroleum Institute (API) Spec. 10D (2002, 2004) to predict casing eccentricity in the wellbore. The calculations are based on an analytical soft-string method, which models an element of casing string between two centralizers as a bifixed-ends beam.
However, in drilling operations, the use of a numerical stiff-string method to compute torque-and-drag forces is now becoming widespread. It accounts for tubular bending stiffness and provides a more realistic analysis of the stresses and loads acting upon the drillstring and the borehole. The stiff-string technique that is based on the finite-element method is thus proposed as an alternative and more effective solution for computing casing centralization for cementing operations.
Measured and calculated casing centralizations were compared in several field cases. The casing eccentricity was measured after the cement placement by use of recently developed ultrasonic logging tools and diagnostics. Discrepancies between analytical and numerical calculation methods were analyzed; then, advantages and disadvantages to each method were assessed. The results of the calculation methods were used to formulate an optimal approach to casing centralization.