bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Behavior of Polymers in Porous Media
Authors: Hill H.J. , Brew J.R. , Claridge E.L. , Hite J.R. , Pope G.A. 
Published: December 2007

This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., April 22–24, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
A partially hydrolyzed polyacrylamide and a biopolysaccharide are being investigated for use as mobility control agents in water flooding and in chemical flooding. Both polymers have functioned satisfactorily in some of our laboratory experiments and unsatisfactorily in others.
The polyacrylamide has given adequate mobility control in moderate permeability rocks when it is injected under conditions which minimize shear degradation. In bead pack flow experiments, we found that degradation occurs at shear rates of about 1000 sec-1. The polysaccharide solution was only slightly degraded by exposure to shear rates of about 30,000 sec-1. These observations, if applicable to field injection situations, limit injection rates severely in wells with restricted entry completions.
Mobility control with the polyacrylamide results from an increase in fluid viscosity and a reduction in permeability. The viscosity effect can be measured in permeability. The viscosity effect can be measured in laboratory viscometers but the permeability reduction must be determined from a series of core floods. As the polysaccharide functions only to increase fluid viscosity, estimation of mobility control for a given system is simplified. Viscosity of fluids containing either polymer can be reduced by shear degradation and, in the case of the polyacrylamide permeability reduction for a given fluid-core system can be severely lowered by shear degradation of the polymer.
The polysaccharide solutions compared with polyacrylamide solutions are less sensitive to shear polyacrylamide solutions are less sensitive to shear degradation, less sensitive to viscosity reduction by increasing salt concentration and are amenable to the use of simplified mobility design procedures.
The Potential "Energy Crisis" in Banking
Authors: Blanchard Robert H. 
Published: December 2007

This paper was prepared for the Second Midwest Oil and Gas Industry Symposium of the Society of Petroleum Engineers of AIME, to be held in Indianapolis, Ind., March 28–29, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.
In recent months, our eyes and ears have been bombarded with differing accounts of the energy "crisis". From the halls of Congress to the front page of our newspapers, from the public relations offices of the major energy companies to the "white papers" of the television networks, we have heard version after version of the causes and the effects of our current problem. All offer convincing explanations of the causes, and most have a proposal or two to get to the solution. It is generally agreed that new sources of energy must be found. "Self-sufficiency" has become a national, and even a state goal. Exploration and development must be increased, capital spending must be greater, lead times for plant construction must be reduced. We have a bevy of unanimous conclusions on what should be done. But few seem interested in tackling a more fundamental problem. How do we finance these ambitious goals? This is the question I would like to address today, and my initial premise is that money is really the raw material that will set the solution to the energy "crisis" "in motion". So, in that sense we both are in the energy business.
If you work for a utility, the days of financing the largest part of your company's capital expenditures from internal cash flow are gone. The days of investors eagerly receptive to utility bonds and equity issues have changed. For the oil industry, politicians are demanding taxes on "windfall profits" - not understanding or not wishing to understand the role of profit in our economy. The situation in the remainder of the seventies and the first half of the eighties will be one in which all industry and all levels of government will be clamouring for capital and you in the gas and oil industries had best begin to make your plans now, to assure that you get your needed share.
To try to place this in perspective, let's look at a few historical numbers. In the twelve years since 1960, capital expenditures of all industry increased by a factor of more than 2.4, from $37 billion to $88 billion.
Gas Lift Jet Applications Offshore Lake Maracaibo
Authors: Faustinelli Juan , Briceño Wilfredo , Padron Aaron 
Published: December 2007

Abstract
Production optimization in continuous gas-lift flow is achieved once the correct amount of gas has been injected through the operating valve, under stable flow condition. More than 80% of the active wells offshore Lake Maracaibo operates with artificial gas-lift methods. For this reason and because of the need to increase oil production, PDVSA E&P decided to carry out field tests using the gas jet pump concept. The pump is wireline retrievable, installed as deep as 12000 feet, with crude oil gravity ranging from 25 °API to 35 °API and for 23/8″ to 31/2″ tubing.
The need to increase the pressure drawdown in the wellbore, which increases the liquid production in already optimized continuous gas-lift wells, was done by installing a gas-lift jet pump in the circulating sliding sleeve or in the operating mandrel. The gas injected (power fluid) from the annulus to the jet orifice converts the energy, from potential to kinetic by lowering its pressure due to the area change, and creating a suction force at the throat. The production fluid and the gas injected are mixed in the throat, recovering its potential energy in the diffuser section.
The results obtained showed that this new technology could increase the pressure drawdown or liquid production up to 30% of its original oil production in some wells. It also performed successfully when a gas-lift jet pump is installed in a high gas/oil ratio sand near the production zone, having the capability to produce without gas injection (autolift). There is no field data information available on gas-lift jet pumps. It is the objective of this article to present the results and the experiences gained during the test field. Selection criteria used for well candidates are also highlighted.
Horizontal Well Performance Evaluation Tools and Techniques
Authors: Kuchuk Fikri J. , Lenn Chris , Hook Peter , Fjerstad Paul 
Published: December 2007

Abstract
In this paper, the use of various measurements for performance evaluation of horizontal wells is presented. First, determining formation pressure and permeability distributions along the wellbore by using the Multiprobe Formation Tester Packer-Probe Module pressure transient interval tests are investigated. It is shown that reservoir pressure measurements along the wellbore give local as well as reservoir scale information about how the reservoir is being depleted and how cleanup takes place. A few interval pressure transient test examples are presented for both formation pressure and permeability distributions. Second, a horizontal well test interpretation is presented utilizing two buildup tests from the same well conducted at different times. It is shown that uniquely determining the reservoir parameters from short buildup tests is impossible. It is also shown that minimizing the wellbore storage effect is crucial for system identification as well as for parameter estimation. Third, the productivity of horizontal wells is explored because it has been difficult to determine the horizontal well productivity due to their long length in the formation compared with vertical wells and inadequacy of measurements during drilling and production. Using field examples, we show that the new integrated production logging measurements can be used to assess horizontal well productivity by identifying productive zones, fluid entries, and determining the fluid distribution (oil, gas, and water) in the wellbore. We also show how reservoir heterogeneity affects the reservoir pressure distribution. The field examples indicate that horizontal wells have permanent water sumps, regardless of whether they produce water. In these wells, we show that when a large percentage of the wellbore cross section is filled with water, reduced oil entry occurs. Performance simulations for these horizontal well indicate 30 to 50 percent productivity reduction when they are compared with their full potential.
A Control Volume Method for Flow Simulation in Well Vicinity for Arbitrary Well Configurations
Authors: Ding Y. , Lemonnier P. , Estebenet T. , Magras J-F. 
Published: December 2007

Abstract
Complex wells are getting more and more used in reservoir engineering to increase the oil recovery. However, accurate modelling of these kinds of wells is still a challenge due to the scaling problem related to the large gridblocks used in the simulation and the small wellbore diameter. In this paper, a control volume method is proposed, which is suitable for the well singularity flow modelling. Both the well performance and the flux calculation in the well vicinity can be accurately handled with this method. The use of this control volume approach for complex well modelling with distorted gridblocks is particularly addressed. Some examples are presented to illustrate the efficiency of the approach.
Hydrajet Fracturing: An Effective Method for Placing Many Fractures in Openhole Horizontal Wells
Authors: Surjaatmadja J. B. , Grundmann S. R. , McDaniel B. , Deeg W. F. J. , Brumley J. L. , Swor L. C. 
Published: December 2007

Abstract
To date, the art of effective openhole horizontal well fracturing is not well defined. Difficulties in regional sealing hamper the fracturing task, and results are generally suspect. Without proper isolation methods, the use of openhole horizontal well fracturing is limited. During many fracturing processes, including fracture acidizing, fracture or acid placement often occurs where fluid first contacts the borehole, often at the heel of the well.
A new method is now available that combines hydrajetting and fracturing techniques. By using this new method, operators can position a jetting tool at the exact point where the fracture is required without using sealing elements. Unlike other techniques, this new method allows operators to place multiple fractures in the same well; these fractures can be spaced evenly or unevenly as prescribed by the fracture design program. Largesized fractures can be placed with this method.
Because the method is simple, operators can economically bypass damage by placing hundreds of small fractures in a long horizontal section. To enhance the process even more, operators can use acid and/or propped sand techniques to place a combination of the two fracture types in the well.
This paper discusses the basic principles of horizontal hydrajet fracturing and how Bernoulli's theorem was used to design a hydraj et fracturing technique. Laboratory test results for the new technique are provided on Page 4.
Xijiang 30-2 and 24-3 Caisson Guide Failure Analysis and Repair
Authors: Thomas Roger L. , Tai Anthony , Litton R. W. , Rodgers James , Huang Rico 
Published: December 2007

Abstract
On December 6, 1996, two seawater lift guides (one at the +19 foot level and one at the −40 foot level on the same caisson) and one firewater caisson guide (at −40 foot level) on the Xijiang 30-2 (XJ30-2) platform offshore South China Sea failed at the connection between the guide bucket and the standoff brace. The failed guides were missing and later retrieved from the seabed. Subsequent inspection detected cracks in other guides supporting the 24-inch caissons on both the XJ30-2 and Xijiang 24-3 (XJ24-3) platforms. Five temporary clamps (two firewater and two seawater on XJ30-2, and one firewater on XJ24-3) were installed to support the caissons at the −40 foot level to allow production to continue during the winter months. Analyses were undertaken to determine the cause of the failures and design of the final repair/strengthening to support the remaining caissons.
Analyses showed that the fatigue failure occurred due to dynamic loading caused by movement of the caissons inside the guides. Initially, wet welding permanent support members at the −40 foot level for the caissons was considered, but detailed FEA analyses of the proposed wet welded doubler plates showed high stresses in the wet welds that could cause future fatigue problems. Permanently installed clamps were designed and installed on all 24-inch caissons at the −40 foot level to replace the original guides. The +19 guides were also replaced by welding supports between the structure and the caissons. This paper will cover the conclusions drawn from the analyses of the failure, analysis of proposed repair options, the decision making process that led to the final repair solution, and the fabrication and installation of the repairs.
Application of Rock Mechanics to HPHT and Horizontal Well Drilling and Completion: A Case Study
Authors: Ray P. L. , Goodman H. E. , Perrin V. P. 
Published: December 2007

Abstract
An analytical technique that integrates core-based rock mechanics with openhole geophysical logs has proven valuable for Chevron's worldwide drilling and completion operations, especially for HPHT wells, horizontal wells and openhole completions. The Rock Mechanics Algorithm (RMA) uses log-derived mechanical properties for drilling and production engineering applications that include:
Formation drillability assessment for bit optimization and performance prediction Wellbore stability for horizontal and extended reach wells Sand production prediction for completion design Formation stress profile and elastic properties for hydraulic stimulation design
This study introduces the RMA program's mechanical property estimation technique and its application to drilling and completion design. Two case histories from the South China Sea will be presented. The first history involves a horizontal drilling and completion design project that includes hole stability and sand prediction and the second history involves optimal bit program and wellbore stability analyses for a HPHT well.
In the horizontal drilling and completion design project, wellbore stability was characterized in the build and horizontal sections. The appropriate mud weight to maintain hole stability was recommended. Horizontal wells were drilled successfully using the recommendation. Sanding tendency for openhole completion design was characterized over the life of the well. This analysis resulted in different completion designs for two different zones, one with an openhole gravel-pack completion and the other with an openhole completion. Up to this time, lack of sand production has confirmed the RMA prediction.
The optimal bit program and wellbore stability analysis on a HPHT well revealed that overburden, frac gradient, and pore pressure are nearly equal under the high pressure and high temperature conditions. Consequently, the safe drilling window is significantly narrowed. RMA takes into account the thermal effect and pressure effect, providing the drilling engineer with proper mud weight guidance.
A Comprehensive Practical Approach for Wellbore Instability Management
Authors: Chen X. , Tan C. P. , Haberfield C. M. 
Published: December 2007

Abstract
In the North West Shelf, a region of growing importance in oil and gas production in Australia, drilling delays and suspension of wells prior to reaching the targets due to wellbore instability have occurred frequently. As a result, economic benefits through the use of new drilling technologies are significantly reduced due to high additional drilling costs. In order to improve drilling efficiency and minimise drilling costs, it is crucial to develop and apply a practical approach to optimise wellbore instability management.
This paper initially presents guidelines, in the form of design charts, for efficient wellbore stability analysis and wellbore profile design. A comprehensive practical approach of using the design charts for wellbore profile design is subsequently described. The application of the design charts is demonstrated through field case studies for a range of in-situ stress regimes.
Biodegradability of Venezuelan Crude Oils
Authors: León N. , Infante C. , Arias M. , Marquez M. , Gorrín A. , McMillen S. J. , Smart D. R. 
Published: December 2007

Abstract
Bioremediation represents one of the most promising, cost-effective, and safest technologies to be used for the restoration of crude oil contaminated soils. However, some previous studies have shown that bioremediation is less effective for heavy, low API gravity crude oils. INTEVEP and CHEVRON have independently conducted laboratory studies to evaluate the feasibility of using bioremediation technologies for crude oils (ranging from 9 to 32° API gravity) produced by MARAVEN in Venezuela. The composition of the hydrocarbons in each crude oil was first characterized by Iatroscan, gas chromatography (GC) and gas chromatography/mass spectrometry (GC/MS) in order to better understand the potential relationship between API gravity, hydrocarbon composition, and biodegradability. Five percent (w/w) of each oil was applied to a Venezuelan loam soil and fertilizers and organic material (used as bulking agents to improve soil conditions such as moisture holding capacity, tilth, and texture) were added to the oily soil to optimize conditions for biodegradation. Abiotic controls (containing 2% v/w HgCl2 to ensure no microbial activity) and a positive control containing fertilizer, but no crude oil, were also prepared. Biodegradation was measured directly by monitoring the decreases in the percentages of saturated, aromatic, resins and asphaltene fractions via Iatroscan throughout the 4 month incubation time. The initial and final samples were also monitored for losses of total petroleum hydrocarbons by GC and polyaromatic hydrocarbons by GC/MS. Biodegradation was monitored indirectly by measuring the production of CO2, a final breakdown product of hydrocarbon metabolism. Higher microbial activity (c.a. CO2 evolution) was observed in the soil amended with light crude oils (120 mg CO2/h/m2) than in soil amended with heavy crude oils (85 mg CO2/h/m2). Iatroscan, GC, and GC/MS analyses confirmed that the light Venezuelan crude oils (&gt;30°API) were readily biodegraded. The biodegradation potential of each of the crude oils and recommendations for which oil types are most amenable to bioremediation technologies are presented.
NMR Relaxation of Clay-Brine Mixtures
Authors: Matteson A. , Tomanic J.P. , Herron M.M. , Allen D.F. , Kenyon W.E. 
Published: December 2007

Abstract
Effective interpretation of nuclear magnetic resonance (NMR) logs in shaly sands requires an understanding of the NMR contribution of clays. Of particular importance is the role of clays in the rapidly relaxing part of the NMR signal.
In this study we measured the transverse relaxation time spectrum (T2) of brine mixed with four clays (illite, smectite, kaolinite and glauconite) as a function of compaction. The Larmor frequency was 2 MHz and the echo spacing 0.16 msec. Mild compaction was achieved by centrifuging the clay slurry at three successive pressures ranging from 1 to 125 psi. Highly compacted samples were produced in a uniaxial press at six sequential pressures ranging from 500 to 16,000 psi.
Each clay-brine slurry and its associated compacted sample showed a single peak in the T2 distribution spectrum. A second peak, which could be interpreted as the "clay-bound water," was never observed. The T2 peak position shifted to faster relaxation times as compaction increased, in proportion to the pore volume-to-surface ratio, V/S. The single peak and VP'S proportionality are consistent with fast diffusion between the pore water and the monolayer of water on the clay surface. Surface relaxivity varied among the four clay minerals; glauconite, the clay with the highest magnetic susceptibility and iron content had the largest surface relaxivity.
These results have important implications for the interpretation of NMR logs in shaly sands. Because of the effects of compaction and to a lesser extent the iron content on a clay's T2 peak position, it is not possible to independently determine clay type from some characteristic relaxation time. These data also imply that it is not feasible to estimate the cation exchange capacity from a single time cutoff of the T2 distribution without additional information such as laboratory measurements or other log data.
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Computational Hydraulic Analysis of a Deepwater Well Drilled With Synthetic-Based Mud in a Riserless Drilling Configuration
Authors: Lima H.R. , Juvkam-Wold H.C. 
Published: December 2007

Abstract
This paper presents an analysis of the temperatures and dynamic pressures occuring in a riserless-drilling-configuration deep water well by circulating a synthetic-based mud and also discusses some aspects of the effects of gas solubility on kick detection in this new configuration.
A numerical model has been developed to simulate the mud flow through the drillstring-riserless/return line system. The simulator is based on the numerical solution for the system of flow equations using finite-difference approximations. The model accounts for the pressure and temperature dependence of mud viscosity and mud density.
Through a sensitivity analysis, the effects of pertinent parameters - specially the circulation rate - on the pressures generated in the system are examined.
P. 347
Well Control Aspects of Riserless Drilling
Authors: Choe Jonggeun , Juvkam-Wold Hans C. 
Published: December 2007

Abstract
Riserless drilling is a term used to describe an unconventional technique using a relatively small diameter pipe as a mud return line from the sea floor instead of a large diameter marine riser. The scheme also balances internal and external pressures at the sea floor by reducing the internal pressure to make a dual pressure gradient possible.
This paper presents basic concepts of riserless drilling and a brief review of problems associated with conventional marine riser drilling for deep water applications. The paper also presents hydraulics, kick detection methods, and well control aspects of riserless drilling with comparison to conventional riser drilling. Other operational considerations are given briefly.
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