bluuebunny/crossref_metadata_2025_split huggingface dataset:
Influence of Wellbore Hydraulics on Pressure Behavior and Productivity of Horizontal Gas Wells
Authors: Sarica Cem , Ozkan Erdal , Haciislamoglu Mustafa , Raghavan Rajagopal , Brill J. P. 
Published: December 2007

Abstract
The objective of this study is to investigate the effect of wellbore hydraulics on the pressure behavior and productivity of horizontal gas-wells. The semi-analytical model used to investigate the effect of wellbore hydraulics, couples gas flow in the reservoir and in the wellbore by utilizing the real gas-pseudopressure function. Pressure and flux distributions along the well are investigated. Conditions under which wellbore hydraulics manifests its effect on the pressure behavior and the productivity of horizontal gas-wells are documented. It is shown that pressure losses in the horizontal section of the well are composed of friction and acceleration losses and the two constituents are interrelated. It is shown that most of the gas enters the wellbore around the heel (the producing end) of the horizontal well and therefore measures must be taken to reduce any flow-impediment around the heel of the well. Two examples are presented to show that the utility of the model developed in this study.
Development of Optimal Water Control Strategies
Authors: Chou S. I. , Bae J. H. , Friedmann Francois , Dolan J. D. 
Published: December 2007

ABSTRACT
A methodology for optimizing water control treatments presented here utilizes existing injection and production data and incorporates previous treatment results into a ranking process, which can be continuously refined as additional data becomes available. Essential sequences of this methodology are explained, and the ranking and design of producer and injector gel treatments at three midcontinental fields are illustrated. Gel treatments based on this methodology performed much better than previous ones.
A key element of the methodology is to assess the degree of communication between an injector and its offset producer. For reservoirs of significant gas saturation, such as those at early stages of waterflood, the correlation coefficient between water injection and production rates over appropriate time frames provides a quantitative estimate of such communication. Results show that offset producers having a high correlation coefficient with the pattern injector generally have positive response after gel treatments, and vice versa.
Surface Producing Equipment For Deep Gas Wells In The Delaware Basin
Authors: Martin F.H. 
Published: December 2007

Abstract
Operators of deep gas wells in West Texas have installed a wide variety of gas producing equipment to best utilize the productivity of specific wells and to meet gas contract requirements. Several installations are discussed, and the need for the Equipment Engineer to be familiar with gas contracts is emphasized.
TEXT
The discovery and development of the very deep natural gas reserves of the Delaware Basin of West Texas led to what has been described as the largest concentration of ultra-deep drilling rigs ever assembled in simultaneous operation. Due to the success of these operations, it may now be said that the basin also contains the largest concentration of high pressure gas producing, treating, and transmission facilities ever assembled. Fig. 1 indicates the location of some of the major gas fields of the Delaware Basin in Ward, Reeves, and Pecos Counties. This paper will attempt to illustrate and describe the producing equipment and various methods of making gas available to purchasers which have been developed by the working interest owners for some of the wells in these fields.
Fig. 2 is an example of split-flow of gas downstream from jointly owned producing equipment. The well, which producing equipment. The well, which is completed in the Ellenburger at approximately 20,000 ft, was initially tested at 23 MMCF/D at a flowing tubing pressure of 6600 psi. The producing equipment consists of a 48 in. x producing equipment consists of a 48 in. × 18 ft 2,000,000 BTU/hr steam generator and a 30 in. × 10 ft 1440 psi working pressure separator. Gas is delivered pressure separator. Gas is delivered into one owner's flow line at 1200 psi where it is transported to a flow psi where it is transported to a flow control center. Gas is delivered another owner to an on-the-site purchaser at 1200 psi by means of a purchaser at 1200 psi by means of a control valve on the separator outlet and a differential controller on the on-the-site sale meter.
History Matching Using the Method of Gradients: Two Case Studies
Authors: Bissell R. C. , Sharma Yogeshwar , Killough J. E. 
Published: December 2007

Abstract
We have successfully history matched two reservoirs using the method of gradients. This was achieved by defining an objective function which is the sum of the squares of the differences between calculated variables, such as a shut-in bottom hole pressures, from the reservoir simulator and their measured values. The objective function is minimised using a non-linear regression algorithm. This requires the derivative, or gradient, of the calculated variables with respect to the history matching parameters. Our reservoir simulator is able to calculate these derivatives efficiently during a simulation run. Both reservoirs had previously been matched by hand. Our results compare well with the hand matches.
Mechanism Of Inhibition Of Paraffin Deposition In Crude Oil Systems
Authors: Mendell John L. , Jessen F.W. 
Published: December 2007

Introduction
The accumulation of paraffin wax in petroleum reservoirs and production equipment petroleum reservoirs and production equipment remains a continuous problem and expense in the production of oil. The use of scrapers, production of oil. The use of scrapers, hot-oil treatments and solvents has eased the problem; however, with the advent of extremely problem; however, with the advent of extremely deep production, offshore drilling and ocean floor completions, the application of remedial measures becomes prohibitive economically. As a result, use of chemical additives as paraffin deposition inhibitors is becoming more prevalent. prevalent. Since no one additive has proved universally effective, the selection of an efficient additive for a specific application becomes important, and a better understanding of the mechanism of inhibition is necessary.
Patton and Chichakli showed that high molecular weight fractions from crude oil significantly affect paraffin crystal growth and retard or prevent paraffin deposition. Hanke and Birdwell also found these fractions were adsorbed preferentially to a metal surface. Other investigators attributed decreased deposition to modifying the paraffin wax crystals or changing the wetting characteristics of the pipe surface.
The purpose of this work was to develop a technique for studying the flow characteristics of crude oil at temperatures below the cloud point, examine the effect of various additives point, examine the effect of various additives on these flow characteristics, and to correlate any change in the flow characteristics with depositional tendency.
Hanke discussed thoroughly the ideas presented by several investigators concerning presented by several investigators concerning accumulation of paraffin waxes. Tronov used a micro-moving picture camera to record paraffin deposition in a flowing well and found nucleation of paraffin crystals occurred directly on the metal surface. Paraffin crystals already in suspension were usually deposited in quiescent parts of the equipment. parts of the equipment. Hunt and Jorda consider surface roughness the only factor controlling the amount and characteristics of paraffin deposits However, Jorda also found use of smooth plastic tubing of tetrafluorethylene, polyethylene and polypropylene still resulted in massive polypropylene still resulted in massive deposits. Patton found that the presence of an adsorbed crude film on a steel surface increased the surface energy of the metal and caused greater deposition.
The association of asphaltenes and paraffin wax in wax deposits has been mentioned paraffin wax in wax deposits has been mentioned by several investigators, and Preckshot found that bitumen deposits possibly were associated with an electro-depositional effect.
Horizontal Well Production Logging in Australia
Authors: Chauvel Yves , Anderson John , Aldred Rick , de Pledge Laurie 
Published: December 2007

Abstract
In 1993, Australia saw a surge in horizontal well drilling and completion. This surge was motivated by two main factors: the desire to produce oil from fewer wells per field at substantially higher production rates per well, and the necessity of draining the reservoirs with horizontal wells as dictated by local conditions of formation geometry and petrophysical characteristics.
One of the most efficient ways of evaluating the productivity of a horizontal drain is to run production logs in the recently completed well. The technique used is called CTL* Coiled Tubing Logging, which was first implemented in 1988 and has become routine since.
Applications of production logging in horizontal wells include: –initial completion evaluation,–in-situ measurement of the productivity index,–flow profile determination,–multiphase flow regime characterization,–determination of unwanted water and gas entries,–dynamic reservoir characterization by pressure transient testing.
Through-tubing formation evaluation tools can also be run together with the production logs to complement openhole evaluation.
More than ten wells have been successfully logged in approximately one year, in different oil and gas provinces of Australia and in a variety of completion configurations. The paper describes the data acquisition programs, the downhole sensors which have been used and their application to horizontal flows. The data interpretation methodology is presented, and a number of interpreted examples are shown.
The paper concludes with the relevance of production logging to the optimization of production engineering, and reservoir drainage by horizontal wells.
Hydraulic Fracturing Experiments in the Great Northern Coal Seam
Authors: Jeffrey R. G. , Weber C. R. , Vlahovic William , Enever J. R. 
Published: December 2007

Abstract
Two field-scale hydraulic fracturing experiments were performed in vertical boreholes on the lease of Munmorah Colliery located south of Newcastle, NSW. The treatments fractured the 3- metre thick, 220-metre deep Great Northern coal seam and were designed to provide a direct comparison between a borate-crosslinked gel and a water treatment. The fracture geometries were mapped during mining of the coal seam.
Geologic mapping disclosed a well-defined coal face cleat and systematic full-seam joints perpen-dicular to bedding and trending NW. The vertical hydraulic fractures extended along the joint and face cleat direction. Evidence that an early slurry stage of fine mesh proppant acted to block off one of two competing parallel fractures was found at one of the mineback sites.
Oilwell Batch Inhibition and Material Optimisation
Authors: Russ P. R. 
Published: December 2007

ABSTRACT
Weighted-batch inhibition is a technique used in Bass Strait oil wells to provide protection against corrosion. A new radiotracer Selenium-75 was attached to the inhibitor enabling the fall rates in gas, oil and water phases to be calculated. The radiotracer technique clearly showed the inability of the inhibitor to fall through the water-phase of a shut-in well and will provide a means of field testing new and better inhibitor formulations. The wear rates of the inhibitor were also calculated using the radiotracer. Laboratory tests were conducted to correlate the inhibitor concentration with minimum inhibitor film thickness required to give the maximum corrosion protection. A concentration of 5000 ppm gave a film thickness of 4.6 x 10-3 mm which corresponded to the optimum protection for the particular inhibitor and corrosion test used.
The lower sections of a number of wells were found to be protected not by inhibition but by tubing metallurgy. Caliper evidence is presented that clearly shows that metallurgy plays a significant role in controlling corrosion. The chemical composition and metallography of the well tubing is presented. As-rolled J55 material had superior corrosion performance than L80 material. The J55 material thermal history determines its corrosion behaviour.
Analysis of Limited-Entry Well Tests in Layered Reservoirs
Authors: Hayes M. R. , Naismith J. D. A. , Gunasekera D. L. , Fitzpatrick A. J. 
Published: December 2007

ABSTRACT
Vertical permeability, often a key parameter in reservoir engineering, can be calculated from the analysis of a limited entry pressure transient. Analytical solutions for limited entry welltests, where a fraction of the reservoir interval is perforated, have been available in the literature for some time. This paper considers the evaluation of limited entry welltests in heterogeneous layered formations. A number of field examples have been analysed using both conventional analytical techniques and a new general purpose numerical welltest analysis application. The examples show that in layered formations vertical permeability can be significantly under estimated by conventional analytical analysis.
Three-Phase Flow in Field-Scale Simulations of Gas and WAG Injections
Authors: Guzman R. E. , Domenico Giordano , Fayers F. J. , Aziz Khalid , Godi Antonella 
Published: December 2007

Abstract
Three-phase flow is present in many oil recovery processes of interest to the oil industry. It occurs in processes such as primary production below bubble point pressure in reservoirs with water drive, in gas or water alternating gas (WAG) injection into waterflooded reservoirs, in thermal oil recovery, and in surfactant flooding. Despite its common occurrence, our ability to reliably model three-phase flow using numerical simulation is questionable. This paper shows the importance of three-phase flow at typical oil field conditions. It also shows the uncertainties in the predictions of oil recovery due to the three-phase relative permeability model.
Numerical simulations of immiscible gas and WAG injection into a waterflooded one eighth of a five-spot were performed to determine the importance of the three-phase flow at conditions that are of interest to the oil industry. Consistent oil-water imbibition and oil-gas drainage relative permeability and capillary pressure were derived for this purpose, including a new form for imbibition capillary pressure.
Dimensionless scaling groups for three-dimensional three-phase flow in porous media were developed. The scaling groups were used to design simulations at various conditions of gravity, viscous and capillary force interactions. In addition, several simulations were made to determine the uncertainty of the results due to the model for three-phase relative permeabilities.
The results of this study show that there is a significant uncertainty associated with the selection of the three-phase relative permeability model for field scale simulations of gas and WAG injections. This uncertainty is translated into doubtful simulation results in terms of distribution of the fluids inside large volumes of the reservoir, total oil recovery, and fluids production rates. It is shown that additional oil recovery due to gas injection after a waterflood can be different by a factor of two depending on the model for three-phase relative permeability. It is also shown that the producing gas oil ratio (GOR) varies considerably depending on the model for three-phase relative permeability, while maintaining the same two-phase relative permeabilities. Accurate predictions of oil recovery in processes that exhibit three-phase flow need more rigorous models for three-phase relative permeability.
Large three-phase flow regions were present for most of the conditions simulated. The size of the three-phase flow regions ranged from 20% to 80% of the volume of the reservoir. The size of the three-phase flow region was a strong function of the kro model used. Thus, an argument asserting that only a small part of the reservoir is affected by the uncertainties in the three-phase relative permeability model is not supported by these results.
Use of High-Angle, Acid-Fractured Wells on the Machar Field Development
Authors: Gilchrist J. M. , Stephen A. D. , Lietard O. M. N. 
Published: December 2007

ABSTRACT
The Machar field, located in UKCS Block 23/26a, contains an estimated STOMP of 290 MMSTB, predominately found in high porosity, low permeability chalk formations. Draped over the flanks of a salt diapir, the chalk formation exhibits a variable degree of natural fracturing depending upon its position on the structure.
Following initial appraisal of the structure, it was clear that to optimise field development, a well designed to intersect with as many natural fractures as possible would offer high well rates while minimising drawdown to aid in reservoir management and recovery optimisation.
This paper describes the use of a stratigraphically high angle well which was drilled to fulfill these requirements. Following discussion of the well’s completion and stimulation design, the field implementation and evaluation will then be reviewed.
The successful high rate damage removal / acid fracturing treatment has led to this appraisal/development well being placed on long term production as part of a pilot scale development of the reservoir.
An Improved Model for Laboratory Measurement of Matrix to Fracture Transfer Function Parameters in Immiscible Displacement
Authors: Gupta Anuj , Civan Faruk 
Published: December 2007

Abstract
The recovery model proposed by Civan4,5 was extended to account for additional mechanism of mass transfer from matrix to fracture. This led to triple exponential functions that offered significant improvement in the agreement between experimental and predicted oil recovery during imbibition. Inclusion of contact angle in the time scaling group resulted in significantly improved correlation amongst the imbibition recovery for samples with varying shapes and sizes, flow boundary conditions, and fluid and rock properties. The analysis presented here allows the estimation of a representative contact angle. Three distinct exponential terms were identified for experimental data analyzed. Such functions matched the cumulative oil recovery for early as well as late time.
An Integrated Experimental Methodology for a Better Prediction of Gas-Condensate Flow Behavior
Authors: Bourbiaux B. J. , Limborg S. G. 
Published: December 2007

Abstract
This paper demonstrates the possibilities offered by an integrated experimental methodology to measure the critical condensate saturation (Sec) and relative permeabilities (kr) of gas-condensate fluid systems.
This methodology involves various procedures such as equilibrium gas injection and two-phase (steady-state) injection. The innovative aspects of the methodology are (1) a visual onstream control of fluid PVT behavior and (2) local condensate saturation measurements using gamma-ray attenuation technique with a specific method of calibration.
Experiments have been performed under two interfacial tension (IFT) conditions with a low-permeability sandstone and methane-propane (C1C3) binary fluid system in the presence of an interstitial water saturation. Sample results are given, mainly for the low IFT condition (0.03mN/m). For this IFT, a low Sec, 4 to 9%pore volume (PV), is found in the presence of an interstitial water saturation (Swi) of 17 to 22% PV. Sec value is linked to the value of Swi. A dependence of Sec on IFT seems to have been detected but requires further investigation. Under steady-state flow conditions, fairly high relative permeabilities to gas and low relative permeabilities to condensate were found with our rock-fluid system for both IFT values investigated. Measurements of condensate distribution within the core enabled real-time control of flow conditions and explained some literature discrepancies in Sec values.
This new multi-purpose experimental methodology enables a reliable determination of IFT-indexed kr curves required to predict the productivity of gas-condensate fields subjected to pressure depletion.
Gelling Behavior of 12-Hydroxystearic Acid in Organic Fluids and Dense CO2
Authors: Gullapalli Pratap , Tsau Jyun-Syung , Heller John P. 
Published: December 2007

Abstract
This paper presents the gelation results of a variety of organic fluids and supercritical carbon dioxide with 12-hydroxy stearic acid (HSA). At low concentration (0.75 wt%), HSA caused thermoreversible gelation of a variety of organic fluids such as aliphatic, alicyclic, aromatic hydrocarbon liquids, chlorinated fluids, and mixture such as Soltrol-130.
As low as 0.75 wt% of HSA also gelled high pressure solutions of dense CO2 and the selected organic fluids such as alcohols and chlorinated fluids. In the absence of any cosolvent, HSA was insoluble in dense CO2 at 1800 psig and 34°C. However, with 10-15% ethanol, HSA was found to be totally soluble in CO2 at the above experimental conditions. Results indicate the mixture of HSA/ethanol or chloroform gels CO2. The ungelled mixture of HSA/cosolvent and CO2 is clear whereas it turns to translucent or opaque when it gels. Viscosity measurements were made of mixtures of HSA with ethanol in dense CO2 at 1800 psig between 21 to 34°C, using a high pressure capillary viscometer equipped with a sapphire cell for visual observations. These showed that the gelation of CO2 with HSA depends on the temperature and concentration of both HSA and cosolvents, which affect the gel temperature (Tg) and viscosity of CO2. The presence of cosolvent enhances the solubility of HSA in CO2 and increases its viscosity.
Studies on Phenol-Formaldehyde Crosslinked Polymer Gels in Bulk and in Porous Media
Authors: Albonico Paola , Bartosek Martin , Malandrino Alberto , Bryant Steven , Lockhart T. P. 
Published: December 2007

ABSTRACT
The general conditions for gel formation by phenolformaldehyde polymer solutions have been examined in studies with three acrylamide polymers. Contrary to an earlier report, polymer crosslinking is found to take place over a wide interval of pH. While the gelation time is relatively insensitive to the concentrations of phenol and formaldehyde or pH, it is strongly influenced by the temperature and the nature of the polymer. These gelants display good injectivity in corefloods and slim-tube experiments at temperatures up to 140°C. On the other hand, the partitioning of phenol into crude oil is found to be a significant issue for the propagation of these gelants. The use of a phenol pre-flush of the formation is shown by numerical modeling to be a potentially viable solution for this problem.
Mechanistic Study and Modelling of Precipitation Scale Inhibitor Squeeze Processes
Authors: Malandrino Alberto , Yuan M. D. , Sorbie K. S. , Jordan M. M. 
Published: December 2007

Abstract
A scale inhibitor "precipitation" squeeze is one of the two main types of treatment for preventing downhole scale deposition; the other type is an adsorption squeeze. However, unlike for the adsorption squeeze process, the mechanism for inhibitor retention within the formation through precipitation/re-dissolution is not fully understood and it is this issue that is considered in this work. Here, our central objective is to consider a range of possible models of the precipitation squeeze process and to determine which of these are consistent with the available laboratory core flood and field data. Such models range from pure precipitation through to more complex models which couple the precipitation process with an adsorption process or with a "mechanical transport" phenomenon. The various models are explained in terms of the chemical processes which are observed. Results from two inhibitor precipitation core floods and one field squeeze treatment are presented along with the modelled inhibitor return curves. Based on certain model assumptions, our understanding of the process allows us to optimise the squeeze design of both inhibitor solution and operational parameters for extending the precipitation squeeze life time.