bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cable Suspended Submersible Pumps And Their Related Operational And Safety Systems
Authors: Taylor D.F. 
Published: December 2007

Abstract
A unique installation of an electrical submersible pump together with its associated ancillary equipment provides attractive economic logistics when considering crude oil production either for offshore platforms, or in field locations remote from normal sources of supply and service.
The equipment considered here covers the surface and subsurface equipment employed on an offshore, remote platform where an "enhanced" system of recovery of crude may be exploited. The system employed permits greater volumes of production than would be realized if the well's production than would be realized if the well's natural flowing ability were relied upon.
This paper touches upon the problems inherent in such a scheme, some of the solutions encountered in specific installations and improvements incorporated in the subsurface equipment for future installations.

Introduction
The cost of producing oil is a matter of vital importance to those of us who are in the business of producing it. Additionally there are certain factors that affect this cost. The less cost per unit of energy sold, the more profit. This is the reason for this paper.
In certain remote areas, normally requiring large work-over costs, an electric Cable Suspended Pumping System may prove to be a very economical Pumping System may prove to be a very economical method of Production. This may be particularly true for producing satelite fields at considerable distance from other larger producing areas. The most "cost reduction", or "savings" may be ultimately achieved by considering early in the field development dulling phase, the use of the cable suspended pumping system in "enhanced production" mode. By this we mean that the pump and its ancillary equipment is installed during the flowing phase of each well. We will speak only of "enhanced production" systems in this paper.
When contemplating the use of this system on-shore the advantages are:The electrical cable is attached to, and rims, and pulls all of the equipment attached to the pump assembly (Cable Group).A relatively small cable - mast unit is required to service (run and pull) the pump and its associated equipment.Round trip time is held to a minimum.
When contemplating the use of this system offshore, additional advantages are:The surface platform to support the weight of a work-over unit plus pipe pulled from the well is considerably reduced. This means less dollars invested in platform support.Less surface area is required and therefore this also reduces the cost of the platform.Multiple wells may be produced from one platform.The well, or wells, on the platform may be completed in such a way that the well is suspended from the ocean floor, not the platform, this too, results in a reduced strength requirement for the platform.The system is readily adaptable to deviated holes.The cable mast unit may service all the wells on one platform.
Microseismic Response of Well Casing Failures at a Thermal Heavy Oil Operation
Authors: Smith R. J. , Alinsangan N. S. , Talebi S. 
Published: December 2007

Abstract
Imperial Oil's heavy oil operation in northern Alberta utilizes Cyclic Steam Stimulation (CSS) to extract bitumen from the oilsand reservoir (∼400 mKB). The operation currently produces over 120,000 bpd from approximately 3000 deviated wells.
During CSS, the well casings are subjected to thermal stresses due to the cyclic, high-pressure, high-temperature nature of the process. In addition, shear stresses develop in the overburden due to volumetric dilation of the reservoir during steam injection. The combination of thermal fatigue and shear deformations can occasionally result in casing failures at some location along the wellbore, but typically at the top of the oilsand reservoir.
Imperial Oil and CANMET developed the application of passive seismic systems to monitor a volume of the overburden shale for casing failures, as well as for other events. As a result of this monitoring, a model for the seismic signature of well casing failures was developed. The seismic energy and radiation pattern of casing failure events has enabled the passive seismic systems to detect the occurrence of casing failures at the reservoir top, beyond the intended monitoring zone in the overburden shale. Subsequent casing checks have identified that the model detection is correct 88% of the time. In addition, event source location accuracy can be established based on the location of the actual casing failures determined from well workovers. This tool has allowed Imperial Oil to decrease well downtime and develop steaming strategies to reduce the occurrence of casing failures at the top of the reservoir.
Geomechanical Uncertainties and Exploratory Drilling Costs
Authors: Proehl Thomas Strenger 
Published: December 2007

Abstract
This paper presents an investigation of pore pressure interpretation, fracture gradient analysis, and the impact of uncertainties on drilling costs and capital allocation to a well in West Cameron Block 249 in the Gulf of Mexico. Geomechanical uncertainties lead to a range of cost estimates. There is currently no deterministic way of knowing the appropriate empiricism to apply in the analysis of geomechanical conditions that control well designs and cost estimates.
An Oil Selective Inflow Control System
Authors: Freyer Rune , Fejerskov Morten , Huse Arve 
Published: December 2007

Abstract
A system has been developed and tested that reduces the production from zones producing high water cut in open hole screen completions. By use of flotation balls with neutral density in formation water, the system automatically reduces a nozzle area on each joint with increasing water cut. The oil selective inflow control system (OS) is used to reduce flow from zones that significantly contribute to the water cut in a well.
A reservoir simulation tool has been configured to incorporate the OS functionality.
Application of Distributed Electrical Measurements and Inflow Control in Horizontal Wells under Bottom-Water Drive
Authors: Kharghoria A. , Zhang F. , Li R. , Jalali Y. 
Published: December 2007

Abstract
We assess the impact of control enabled by far-field monitoring of bottom-water encroachment on the production performance of horizontal wells. Monitoring can be achieved by electrical measurements distributed along well length against the formation. We assess the depth of investigation resulting from such measurements. Inflow control is achieved by means of downhole valves in a segmented horizontal completion. We examine the impact of valve placement, inflow configuration, and mode of operation on production performance. The combined monitoring and control problem is illustrated by means of synthetic examples.
VES Fluid Allows Minimized Pad Volumes and Viscosity to Optimize Frac-Pack Geometry: Completion Type Evolution in Barbara Field, Central Adriatic Sea
Authors: Mathis S. P. , Pitoni Enzo , Ripa Giuseppe , Ferrara Giovanni , Conte Antonio , Ruzic Mladen 
Published: December 2007

Abstract
When frac-packing near contacts with undesirable fluids, fracture height growth must be minimized. Likewise, when fracturing relatively low-permeability gas sands, the required tip-screenout event may be difficult to obtain due to excessive fluid efficiency leading to excessive fracture growth. One technique to address both of these problems is the use of non-viscosified brine as a fracturing fluid (i.e., water-fracturing).
Water-fracturing limits fracture growth due to its high leakoff, and allows pad volumes to be minimized because proppant concentrations are maintained at low levels throughout the treatment. However, the technique does suffer in that the proppant carrying ability of water does not allow proppant concentration to exceed about 2.5 – 3 PPA. This constraint can lead to reduced near-wellbore fracture conductivity as compared to a properly executed frac-pack using crosslinked fluids. A fluid that has good leakoff and good proppant carrying capacity will provide the opportunity to bridge the gap between water-fracturing and crosslinked gel frac-pack operations. A new generation visco-elastic surfactant (VES) fluid provides this opportunity.
The Barbara field in the Adriatic Sea is a shallow dry gas field and formation sand has to be controlled with gravel pack. It was originally completed with standard gravel packing procedures, which were migrated to water-fracturing techniques during the mid-1990's. While this completion method proved successful, it was desired to increase fracture conductivity while continuing to control fracture geometry. The use of a low-concentration VES fluid allowed such optimization of the frac-pack process, leading to significant productivity improvements. This paper reviews the evolution of completion techniques in the Barbara field that has led to these productivity improvements.
Heather Field: Management of a Mature Offshore Oilfield
Authors: Morel E H 
Published: December 2007

Abstract
Heather field, currently producing about 5,000 bopd, is one of the most mature North Sea oilfields being produced from a large fixed platform. Production from Heather field over much of its life has been marginally economic as revenue and operating costs are finely balanced.
Over the last five years a change of Operator of the field, and simplified ownership, has energised the management of the asset. The new Operator has brought new investment in the field, the platform and exploration of neighbouring satellites. The extra production from infield drilling and well intervention activity has prolonged field life and increased oil reserves. It has also deferred the eventual decommissioning of the Heather facilities.
This paper describes the Operator's approach to managing the asset, and its rationale for the investment in four new platform wells, an active well intervention campaign, and exploration of the greater Heather area. The acquisition of new seismic data has improved the reservoir description of the field and satellites, leading to appraisal drilling of the West Heather area. It reviews the successes and failures of these projects, and describes the main lessons learned, which may be applicable to other fields in a similar economic situation.
The principal factors affecting the company's willingness to invest have been its view of the overall economic outlook, the performance of existing wells and the ability to maximise production from them, the potential of new infield drilling targets to achieve rapid payback, and most importantly, the maintenance of a safe low-cost offshore and onshore operation. Contrary to popular belief the uncertainty in predicting future production from mature fields such as Heather is as great, or greater than predicting future production in younger assets.
The gains to be had from mature assets such as Heather are significant enough to attract the interest of specialist producers. Given favourable tax regimes further investment in other mature fields could yield significant quantities of oil and gas which would otherwise be lost because of premature decommissioning.
A Novel Approach to Identify Reservoir Analogues
Authors: Bhushan Vikas , Hopkinson Simon Christopher 
Published: December 2007

Abstract
The identification of reservoir analogues if often an important step in planning the development of a new play, particularly when it poses difficult technical challenges or when appraisal information is limited. One of the strengths of an E&P company with a large and diverse portfolio is its potential to utilize a broad base of knowledge gained from past experience to aid in future development and decision-making. A critical enabler in being able to leverage this knowledge effectively is the ability to access relevant information quickly and efficiently. This paper presents a new approach to identifying analogues systematically through the novel application of an artificial intelligence technique called case-based reasoning.
The key lies in characterising each reservoir by a set of attributes which describe the reservoir and can be used to differentiate it from other reservoirs. Case-based reasoning is then applied to search for reservoirs which are similar (i.e. are potentially good analogues), but that do not necessarily match up exactly on any individual attribute. Further, this method quantifies the degree of similarity and permits users to focus their search on any specified set of reservoir attributes. These characteristics differentiate this method from others currently in use.
The implementation of this method to create a versatile knowledge sharing tool, called the "Smart Reservoir Prospector", will be described. Recently developed artificial intelligence technology incorporating case-based reasoning algorithms within a flexible java-based architecture has been applied. The result is a web-based system that permits users in any Shell operating unit to search through thousands of reservoirs in milli-seconds to locate reservoir analogues, and then to access additional detailed information about the reservoirs of interest. The application of this tool within Shell to address important business issues, including scope for recovery and reserves justification, recovery factor benchmarking, and reservoir knowledge sharing, will be discussed.
Dual Flow Well Technique for Produced Water Management
Authors: Davis L. , Frorup M. , Farias L. 
Published: December 2007

Abstract
The Dacion field, located in the eastern Venezuelan basin, came on production about 50 years ago. In the early years of development, more than 300 wells were drilled and production reached a peak of 45000 bbl/D of oil around 1958. Subsequently, the field was operated on a rate maintenance basis, with a drastic reduction in drilling activity. By 1997 the rate had fallen to approximately 10000 stb/D, and the field was included in the Venezuelan third licensing round. Lasmo Venezuela was awarded the management of the Dacion asset, and started an aggressive drilling program of additional replacement and infill wells. This led to production tripling in 2 years, associated, however, with increasing water production. Unconventional treatment options had to be considered for managing the water, due to the reservoir complexity.
The Dual Flow concept is one of such techniques. It is based on perforating both oil and water layers and producing from each set of perforations separately. Reservoir simulations showed the viability of the technique by allowing an increase in the critical production rates. Controlling the cone leads to a reduction in water production from the upper set of perforations and hence the water processing requirement. The implementation and the results from the first pilot well are presented, including the lessons learned. A comparison with predicted performance is provided. The pilot study highlighted a number of critical issues for produced water management, including the impact of permanent monitoring and control.
Chemical Flooding: A Comparison Between Alkaline And Soft Saline Preflush Systems For Removal Of Hardness Ions From Reservoir Brines
Authors: Campbell Thomas C. 
Published: December 2007

Abstract
Brine displacement studies using Berea sandstone cores were undertaken to compare the effects of alkaline and soft saline preflush systems on an equivalent basis. The alkaline chemicals used were sodium orthosilicate, sodium hydroxide, sodium silicate (2.0 ratio of SiO2/Na2O) and sodium carbonate. The soft saline solutions used ranged in concentration from 3% NaCl to 10% NaCl. The effects of the various preflush systems were measured by titration of the effluent for hardness ion levels. In some of the experiments dilute surfactant was injected following the preflush to determine the effect of surfactant on elution of hardness ions.
Results are presented which show that the highly alkaline chemicals, sodium orthosilicate and sodium hydroxide, were very effective in removing the hardness ions from connate brine. Further elution with soft brine following the highly alkaline preflush showed that essentially no ion-exchange occurred and the hardness ion level remained at zero in the effluent. This same effect was observed with the 2.0 ratio sodium silicate, but higher volumes of solution were required to reduce the hardness ion levels to zero in the effluent. With high salinity and sodium carbonate preflushes a high ion exchange peak was observed. Continued elution reduced the hardness ion levels considerably, but not to zero.
Wellbore Sinuosity and Its Effect on Production and Recovery from Horizontal Wells Along the Cummings/Dina Channel Trend in Senlac and Winter Saskatchewan
Authors: Miller Karl A. , Cameron Bill , Qing Lu , Hayes Lew A. 
Published: December 2007

Abstract
Over 500 horizontal wells have been drilled into the Cummings/Dina channel trend between Senlac and Winter since 1990. These wells produce 13 – 14 API oil with a gas free viscosity of 3600 cp from a depth of 700 meters. Production peaks at about 20 to 60 m3/d oil with 10% water and 1.5% sand. Oil production eventually declines as water cut increases. Sanding events can limit oil production rates and recovery.
Wellbore trajectory control has improved significantly in the last 10 years, the latest improvement being ‘inclination at the bit.’ Selected wells were analyzed to determine the key factors between sinuosity and production rate and ultimate recovery, and the changes in the effect of these key factors over the last 10 years. Incentive and methodology for development of current flatter wells is discussed, and predictions for production from current flatter wells are given.
Magnetic Ranging Technologies for Drilling Steam Assisted Gravity Drainage Well Pairs and Unique Well Geometries - A Comparison of Technologies
Authors: Grills Tracy L. 
Published: December 2007

Abstract
Magnetic ranging refers to the determination of the relative position of one well with respect to another using magnetic measurements. Magnetic ranging is used for several oil field applications including positioning blow-out relief wells, steam- assisted gravity drainage and heavy oil applications, and planned intersection of one well with another. The procedure is also applicable to horizontal distance measurement and TVD correlation between observation wells and nearby horizontal wells. This paper is a discussion of the theories, methodologies, and pro’s and con’s of both "active" and "passive" magnetic ranging.
A comparison of a number of specific technologies currently available in the marketplace will be presented. The paper will discuss the following trademarked and proprietary items: Magnetic Guidance Tool™, Single Wire Guidance™, Rotating Magnet Ranging Service™, MagTraC , and Parallel Well Tracker™. The paper also includes a discussion of potential future directions in magnetic ranging.
Field experience and history will be presented as well as methodology for each technology. The paper will focus mainly on technologies that are currently available with discussions of the theory of operation of each technology, operation parameters, specifications, experience with drilling different types of wells with the various technologies, and finally, the advantages and disadvantages of each technology will also be discussed.
New Insights into Water Control - A Review of the State of the Art – Part II
Authors: Di Lullo Gino , Rae Phil , Curtis James 
Published: December 2007

Abstract
It could be argued today that oil companies would be better described as water companies. Total worldwide oil production averages some 75 million barrels per day and, while estimates vary, this is associated with the production of 300 – 400 million barrels of water per day. These values of approximately 5 – 6 barrels of water for every barrel of oil are quite conservative. In the United States, where many fields are depleted, the ratio of water-to-oil production is closer to 9 to 1. In some areas around the world, fields remain on production when the ratio is as high as 50 to 1.
Water production is a harbinger of problems in an oil well. It can cause scaling problems in susceptible wells, induce fines migration or sandface failure, increase corrosion of tubulars, and kill wells by hydrostatic loading, amongst other things. Thus, while water production is an inevitable consequence of oil production, it is usually desirable to defer its onset, or its rise, for as long as possible.
Numerous strategies, both mechanical and chemical, have been employed over the years in attempts to achieve this. Simple shut-off techniques, using cement, mechanical plugs and cross-linked gels have been widely used. Exotic concepts, like relative permeability modification (RPM), have also been applied with varying degrees of success.
This paper is a continuation of a previous one, which reviewed the traditional techniques and proposed some new methodologies and technologies that can be used in the design of RPM treatments, in particular.1 Additional new insights offered in this paper include the extension of matrix RPM treatments to more extreme well conditions, such as heavy (viscous) oil and low pH environments. It also introduces the concept and reviews several case histories of the usage of RPM systems to perform hydraulic fracturing treatments to simultaneously stimulate oil and control water. This conformance-fracture technique could significantly impact the development strategies of many fields worldwide.
PVT and Viscosity Measurements for Lloydminster-Aberfeldy and Cold Lake Blended Oil Systems
Authors: Frauenfeld Ted W. J. , Kissel Gerald , Zhou Shibing (Wendy) 
Published: December 2007

Abstract
A solvent-assisted gravity drainage process (Vapex) for recovery of heavy oil or bitumen offers high recoveries and promising rates of oil production. In order to predict process performance, data on solvent-oil solubility and on the viscosity of solvent-oil mixtures must be obtained.
The solubility of selected gasses in Lloydminster Aberfeldy oil and in a Cold Lake oil was measured. The gasses used were: CH4, C2H6, C3H8 and CO2. Measurements were done at reservoir temperature. The data were regressed using the Peng-Robinson equation of state, which was used to generate k-values expressing the solubility of the gas-oil systems. Regressing the Peng-Robinson equation to the measured data generated interaction coefficients for the systems measured. These coefficients were used with the equation to generate k-value or solubility tables at other conditions. Measured viscosity data were used to confirm the usefulness of the Puttagunta viscosity correlation for propane-based heavy oil systems. The work confirmed the formation of two liquid phases in the oil-propane system at high solvent loading. The measurements also confirmed the large viscosity reductions available (100:1 – 200:1) by saturating oil with light hydrocarbons. A viscosity increase in one oil-propane system was observed at high solvent loading, suggesting possible asphaltene precipitation and/or deposition on the walls of the capillary viscometer tube.
These observations confirmed the need to study phase behaviour and asphaltene deposition in the oils at high solvent loading, as well as obtaining solubility and viscosity measurements. The data have been used to perform numerical simulations of Vapex and other solvent-based processes, and to perform predictions of field process performance.