Search

The vacuum chamber inside the cryogenic magnets in the LHC Long Straight Sections will have a beam screen at a temperature between 5 and 20 K to protect the cold bore against the synchrotron radiation, electron and ion exposure. The desorbed molecules of H 2 will leave the inner part of the beam screen through the pumping slots on the beam screen and eventually condense on the cryosorber, which is mounted on the shadowed (outer) part of the beam screen for magnets operating at 4.5 K. The design of the experimental set-up, the results of the adsorption capacity measurements for charcoal, the pumping speed and the capture factor of the beam screen with charcoal for a proposed LHC vacuum chamber configuration are described in this paper.

In a cryogenic proton accelerator, such as the LHC, the creation of an electron cloud and generated heat loads resulting from electron bombardment are strongly dependent on the azimuthal distribution of created photoelectrons. In this context, photon reflection and photoelectron yield measurements have been performed using a beam line on the VEPP-2M storage ring. Six electrodes, covering the complete vacuum chamber perimeter, were mounted such that they could be suitably biased, and while one electrode was irradiated with synchrotron radiation the resulting electron current of all the others could be measured. A detailed description of the experimental apparatus and the results of the measurements of photon reflection and the azimuthal distribution of generated photoelectrons are presented.

Summary Barium sulfate scale deposition in the near wellbore, perforations, or production tubing has severely affected well productivity in many North Sea Fields. This is due to the co-mingling of the sulfate-rich seawater used for reservoir sweep with formation water containing high concentrations of barium ions. Mitigation of this problem is generally achieved by regular "squeeze" deployment of scale inhibitor chemicals which retard scale precipitate formation and deposition. However, in some instances, the scale inhibitor is poorly retained within the reservoir rock matrix and short squeeze lifetimes are experienced. The net result in these cases is frequent well interventions which impact on both well productivity and field profitability. To solve this problem, a scale squeeze enhancer has been developed which acts to enhance retention and subsequent release of scale inhibitor in the reservoir. The first field deployment of this technology was in BP's Magnus asset. The trial demonstrated a more than doubling of the squeeze lifetime of an adsorption chemical.

The risks and uncertainties associated with scale control in new field developments can often have a significant impact on the field economics. This can be especially true for marginal subsea fields producing from areas with high barium concentrations in their formation waters. Other aspects such as completion design, reservoir formation and heterogeneity also have a significant impact both on the severity of the scaling potential and also the ability to effectively treat production wells via conventional bullhead squeeze treatments. In this paper we describe an analysis that was conducted during the Pre-Front End Engineering and Design (FEED) stage of a field in the Norwegian sector of the North Sea. The field was expected to produce hydrocarbons from two subsea templates located 1.6km and 6.3km from a floating production system over a field life of ~ 10 years. Seawater injection was preferred over gas injection for pressure support owing to the higher predicted hydrocarbon recoveries. Of particular concern was the high barium concentration of > 700 ppm recorded from an appraisal well water sample, indicating a very severe barium sulphate scaling potential with raw sea water injection. For this field, in addition to the very severe potential barium sulphate scaling regime, a number of factors combined to present an exceptionally severe risk to the fields net present value. This related to: subsea completions with multiple production wells co-mingling at the wellheads (although dual production lines were incorporated into the design plan partially to assist in scale management); and long (500 - 700m) horizontal production wells and completion designs involving open hole screens served to increase the risks associated with scale formation and effective chemical placement. A range of alternative options were examined together with the associated risks and uncertainties. In summary, the most significant risks and uncertainties associated with the economic viability for seawater injection in this field related to: Uncertainties associated with the initial formation water composition.The ability to squeeze treat wells without inducing fines mobilization and plugging sand control screens as observed in analogue fields.The ability to effectively place scale inhibitor treatments along the length of the horizontal producers by bullhead treatments rather than coil tubing operations.The potential for changes in the base case field production scenario This work therefore allowed the design team to make informed decisions at the pre-FEED stage in a field where scale control had a significant impact on the fields economic viability.

Oilfield scale formation is dependent upon the production of water and as a result most scale inhibitors are water soluble and deployed using an aqueous phase. For treatment of wells that produce only small amounts of water and/or have water sensitive matrices and wells with high water cuts with lifting problems the use of an aqueous inhibitor can cause many problems. Even with the development of oil miscible and emulsified scale inhibitors the same problem can be encountered when the incorrect screening procedure has been used in the laboratory. This study describes the development of a range of truly oil soluble scale inhibitors for squeeze application. A particular feature of these materials is that they preclude aqueous phases and are soluble in crude oil and diesels. The products have been designed so that is possible to deploy calcium sensitive scale inhibitors in a non-aqueous medium. Upon contact with formation water passing the near wellbore the scale inhibitor will partition into the water phase and undergo a precipitation reaction. This provides a mechanism for potentially increasing treatment lifetime. In addition, the scale inhibitor precipitation can be further controlled and enhanced through emulsification with a calcium loaded aqueous medium also containing organic additives to aid and enhance the precipitation process. Although this involves incorporating water into the product package the invert emulsion provides an oil continuous matrix and is still considered to be significantly less damaging to water sensitive formations than standard oil dispersible and emulsified scale inhibitor packages. A detailed investigation into the properties of selected oil soluble and emulsified products has been performed. Experimental data on compatibility with production fluids, thermal ageing, oil/water partitioning, inhibitor performance, extent of precipitation and core flood studies to evaluate formation damage potential and retention and release characteristics will be presented. This paper will also highlight how the use of the oil soluble precipitation process can increase squeeze lifetimes when compared to traditional aqueous squeeze treatments. In addition, a new core flood procedure for the screening and evaluation of non-aqueous chemical treatments will be described and the implications this has for field application of these products will be discussed.

The control of inorganic scale deposition within the reservoir under both natural depletion and injection water support has been a challenge to the oil industry for a number of decades. The challenge has remained identifying the location of water breakthrough within the production interval and the subsequent injection of scale inhibitor into these zones to prevent scale formation within the near welbore and production tubing. As completion technology has advanced, and more complicated completions have been developed and installed to increase the rate of oil recovery, the challenges of water management and scale control have become significant factors if long term production from these wells is to be maintained.This paper will outline the challenges of chemical deployment via bullheading into subsea wells completed in high permeability reservoirs with sand control technology. The factors considered when designing a self-diverting scale inhibitor system will be outlined in terms of viscosity profile of the chemical and overflush fluid, impact of temperature on fluid viscosity, pump rate, shear effects, tubing diameter vs. wellbore friction and the impact of radial flow on viscosity. Modelling data from vertical and horizontal production wells will be used to illustrate the challenges that pump rate changes and a self-diverting scale inhibitor system has to overcome to allow effective deployed of scale inhibitor without the need for coiled tubing in long (500ft to 3,000 ft) wells in 2 Darcy reservoirs.The value of this technology in terms of the economic factors will be outlined with field examples where coiled tubing and bullhead applications will be compared and contrasted to illustrate the value in terms of total cost of operation that the self-diverting technology can offer.

In particle accelerators with intense positively charged bunched beams, an electron cloud may induce beam instabilities and the related beam induced electron multipacting (BIEM) can result in an undesired pressure rise. In a cryogenic machine such as the large hadron collider (LHC), the BIEM will introduce additional heat load. When present, synchrotron radiation (SR) may generate a significant number of photoelectrons, that may play a role in determining the onset and the detailed properties of the electron cloud related instability. Since electrons are constrained to move along field lines, those created on the accelerator equator in a strong vertical (dipole) field cannot participate in the e-cloud build-up. Therefore, for the LHC there has been a continuous effort to find solutions to absorb the photons on the equator. The solution adopted for the LHC dipole beam screens is a saw-tooth structure on the illuminated equator. SR from a bending magnet beamline at ELETTRA, Italy (BEAR) has been used to measure the reflectivities (forward, back-scattered and diffuse), for a flat and a saw-tooth structured Cu co-laminated surface using both white light SR, similar to the one emitted by LHC, and monochromatic light. Our data show that the saw-tooth structure does reduce the total reflectivity and modifies the photon energy distribution of the reflected photons. The implications of these results on the LHC arc vacuum system are discussed. © 2004 Elsevier B.V. All rights reserved.

In this paper we describe the development of a novel water-in-oil emulsion system for the deployment of aqueous-based production chemicals. The non-aqueous nature of the emulsion system potentially allows ingress of the chemical into parts of the reservoir normally denied access to an aqueous-based formulation and so can improve contact between the chemical and the reservoir fluids on production. Furthermore, the whole treatment can be deployed as a non-aqueous package allowing oil continuity to be maintained during the treatment. This can (i) prevent changes in the near well-bore relative permeability arising from the influence of the injected fluids; (ii) prevent water becoming trapped in oil-bearing zones reducing permeability to oil; and (iii) improve production chemical penetration depths (the water-wet nature of sandstone reservoirs means that the penetration depth of, for example, scale inhibitor solutions can be low). Moreover, for poor pressure support reservoirs, the reduced density of a non-aqueous treatment can obviate the need for artificial lift to restart the well. Originally developed for scale inhibitor deployment, this technology has been advanced by developing slowly degrading emulsion systems, which provide a means of trapping the aqueous production chemical within the porous media and allowing subsequent controlled release of the chemical. This advanced scale control technology has been proven in the laboratory for the encapsulation of corrosion inhibitors, biocides, hydrogen sulphide scavengers, and chemicals for the control of reservoir souring. Encapsulated scale inhibitors have been field deployed in two locations (in the UK sector of the North Sea and in the demanding environment of onshore Alaska under both high water cut and very low water cut conditions). This paper describes laboratory testing, including coretests, and describes the planning, the execution, and the results of the field treatments.

Production chemicals being discharged into the natural environment are increasingly becoming scrutinized for their impact on the environment. New and existing chemicals for scale and corrosion control are likely to be impacted by the developing legislation and regulatory control. Therefore, there exists an urgent need to bring the marketplace new chemistry that is able to reduce the environmental impact while still retaining its excellent efficiency. This paper describes the development of novel polymeric chemistry, which has a dual functionality acting as both a scale and corrosion inhibitor under oil field conditions. This chemistry can be readily biodegradable and has achieved the stringent standards required for its use in the North Sea. Laboratory studies demonstrate that this chemistry can inhibit both carbonate and sulfate based scales. Corrosion experiments with or without flow suggest that greater than 90% of inhibition in a carbon dioxide rich environment can be achieved. The calcium compatibility of this chemistry far exceeds the performance of most commercially available scale inhibitors. The impact on oil and water separation, and subsequent oil in water content, is minimal.

This paper describes the experimental studies of the effect of a dipole field on photoelectron emission and on the photon reflectivities from LHC beam screen material. These studies were performed using synchrotron radiation from the VEPP-2M storage ring at BINP (Novosibirsk). The particular surface roughness and geometry of the prototype LHC beam screen material requires dedicated experimental measurements. The experiments were performed under conditions close to those expected in the LHC. An important result obtained is that a dipole magnetic field attenuates the photoelectron emission from the surface by more than two orders of magnitude with the magnetic field aligned parallel to the surface. The measurements of photon reflectivities, forward scattered and diffuse, and the azimuthal distribution of emitted photoelectrons from the same material are reported. These experimental results are important input for the final design of the LHC beam screen.

Chemical inhibitors that prevent the formation of sulphate and carbonate mineral scale formation are used in field squeeze treatments. The demand for competent evaluation of all issues associated with mineral scaling in wells and pipelines is continuous throughout the lifetime of any producing asset and the cost implications are very large. It is therefore important that the chemical inhibitor species can be accurately assayed so that the end of the squeeze lifetime can be determined. Previous work by others has reported the development of accurate detection and assay techniques for oilfield scale inhibitors1,2. For PVS and VS-Co type inhibitors, these methods involve pre-treatment/purification stages that allow the application of standard wet chemical techniques, in particular the separation of the inhibitor chemical from interfering brine salts. However the typical size of samples from experimental core floods are so small that they render these methods impractical. In this paper we detail the development of a turbidimetric method without the need for pre-treatment/purification stages for the determination of a sulphonated-polyacrylate co-polymer using Hyamine 1622. The applicability of this technique is illustrated with coreflood samples having small volume size and with real field post-scale inhibitor squeeze produced water samples. It is also shown that the method developed allows the determination of scale inhibitors in produced waters with up to 55,000ppm total chloride concentration and 100ppm crude oil in water. Finally we report the potential interferences caused by the inhibitor carrier, crude oil and displacement fluid which may arise as a result of both typical and atypical squeeze treatments.

An adequate dose of photoelectrons, accelerated by low-intensity proton bunches and hitting the LHC beam screen wall, will substantially reduce secondary emission and avoid the fast build-up of an electron cloud for the nominal LHC beam. The conditioning period of the liner surface can be considerably shortened thanks to secondary electrons, provided heat load and beam stability can be kept under control; for example this may be possible using a special proton beam, including satellite bunches with an intensity of 15-20% of the nominal bunch intensity and a spacing of one or two RF wavelengths. Based on recent measurements of secondary electron emission, on multi-pacting tests and simulation results, we discuss possible 'beam scrubbing' scenarios in the LHC and present an update of electron cloud effects.

Abstract The deposition of scale, such as carbonates and sulphates, in production facilities represents a serious operational problem that can result in significant well productivity decline. Currently implemented scale control strategies can involve significant capital and operational expenditure. Development work, involving laboratory testing and a field trial, has demonstrated the technical benefits of a revolutionary method of downhole scale inhibitor delivery. Economic analysis indicates that significant benefits can be derived for a variety of field development and well completion types. The greatest economic benefits would be realized for subsea and minimum facility installations with high intervention costs, where squeeze delivery of scale inhibitor or mechanical workover are used for scale control. In addition, major economic benefits can be realized for horizontal wells with unfavourable pressure regimes, multi- lateral type completions, multiple fractured wells, and many conventional completion types. The new chemical delivery method offers cost reduction through reduced deferred oil, efficiency of chemical usage, and elimination of coil tubing and intervention vessel use. Economic analysis has indicated that fracturing a well and deploying proppant impregnated with scale inhibitor, is economically preferable to a strategy of squeeze treatment for some conventionally unfractured wells with high intervention costs, for example subsea wells. An additional economic benefit of proppant impregnated with scale inhibitor (Chemflow) is increased well productivity. The benefit is derived from the combined effect of improved gel breaking, and scale inhibition during well clean-up. This has been demonstrated in laboratory testing and would appear to be confirmed by field observations. A further benefit of applying scale inhibitor as chemically impregnated proppant is the instantaneous treatment of produced water when water breakthrough occurs. This feature avoids the formation damage that can occur before squeeze treatment mobilization. In addition, for some applications involving large fractures there is the potential for lifetime well treatment. P. 323

Abstract Barium Sulfate scale deposition in the near-well-bore, perforations or production tubing has severely affected well productivity in many North Sea Fields. This is due to the commingling of the sulfate-rich seawater used for reservoir sweep with formation water containing high concentrations of barium ions. Mitigation of this problem is generally achieved by regular 'squeeze' deployment of scale inhibitor chemicals which retard scale precipitate formation and deposition. In the squeeze procedure, scale inhibitor is injected several feet radially into the production well where it is retained by adsorption and/or formation of a sparingly soluble precipitate. The inhibitor slowly leaches into the produced water over a period of time and protects the well from scale deposition. However, in some instances, the scale inhibitor is poorly retained within the reservoir rock matrix and short squeeze lifetimes are experienced. The net result in these cases is frequent well interventions which impact on both well productivity and field profitability. To solve this problem, a scale squeeze enhancer has been developed (jointly by BP Exploration and BP Chemicals) which acts to enhance retention and subsequent release of scale inhibitor in the reservoir. The first field deployment of this technology was in BP's Magnus asset. The trial demonstrated a more than doubling of the squeeze lifetime of an adsorption chemical and has subsequently led to considerable cost savings for the Magnus asset by reducing well intervention frequency and subsequent well downtime. Introduction Magnus Field History. The Magnus oilfield lies approximately 160 km north east of the Shetland Islands in the UK Sector of the North Sea. The field is located in blocks 211/7a and 211/12a, and is producing through the most northerly platform on the UKCS. The Magnus oilfield was discovered by BP in 1974 and first production commenced in August 1983, reaching a peak annual average production rate of 144,301 stb/day in 1994. Reservoir Description. The Magnus field is divided into three producing intervals, the Turonian Reworked Sandstone, which overlays the Magnus Sandstone Member (MSM), which overlays the Lower Kimmeridge Clay Formation. The producing interval initially contained an estimated volume of 1,650 mmstb of oil in place. The MSM lies at a sub-sea depth of approximately 3000m and is currently the main producing formation, having originally held 77% of the initial oil in place. The MSM is the most well defined of the Magnus formations, and can be broken down into several discrete sandstone zones or lobes, separated by shale mudstone units, which act as vertical permeability barriers. The typical MSM permeability is in the range 200–500 mD, with an average porosity of 21% and a maximum net pay of 108 m. Reservoir Management. The Magnus reservoir is currently being drained by 15 producing wells, while 9 further wells, including 3 sub-sea tie-ins, are injecting seawater to support the reservoir pressure. However, off-take from the field to date has exceeded the volume injected, resulting in a significant drop in reservoir pressure from an original value of 6650 psi to a current average of approximately 3000 psi. In addition, a significant pressure gradient exists across the field, with a maximum of 7500 psi observed in certain injectors, compared with 2750 psi measured in several crestal producers. The field is now produced on a voidage replacement basis, however, significant differential pressure exists between lobes as a result of divergent pressure depletion through the MSM. Nature of Scale Problem. An analysis of the ionic composition of the formation waters produced from the various lobes or zones reveals subtle differences in their chemistry; however, in each case the produced water has a salinity almost identical to sea water. In addition, the barium concentration in Magnus formation water is in the range 160–220 mg/l. P. 161^

Economic and Technical Advantages of Revolutionary New Chemical Delivery System for Fractured and Gravel Packed Wells P.J.C. Webb, AEA Technology plc, T.A. Nistad, Saga Petroleum ASA, B. Knapstad, Norsk Hydro ASA, and P.D. Ravenscroft and I.R. Collins, BP Exploration Operating Company Limited Copyright 1997, Society of Petroleum Engineers, Inc. Abstract The deposition of scale, such as carbonates and sulphates, in production facilities represents a serious operational problem that can result in significant well productivity decline. Current scale control strategies can involve significant capital and operational expenditure. Development work, involving laboratory testing and a field trial, has demonstrated the technical benefits of a revolutionary method of downhole scale inhibitor delivery that can prevent scale deposition for a significant proportion of a wells lifetime. The method involves the slow release of scale inhibitor from porous proppants. Economic analysis indicates that significant benefits can be derived for a variety of field development and well completion types. The greatest economic benefits would be realised for subsea and minimum facility installations with high intervention costs, where squeeze delivery of inhibitor or mechanical workover are used for scale control. In addition, major economic benefits can be realised for horizontal wells with unfavourable pressure regimes, multi-lateral type completions, multiply fractured wells, and many conventional completion types. The new chemical delivery method offers cost reduction through reduced deferred oil, efficiency of chemical usage, and reduction workovers using coil tubing and intervention vessels. Economic analysis has indicated that for some conventional and advanced well types, fracturing a well and deploying proppant impregnated with scale inhibitor, is economically preferable to a conventional strategy of squeeze treatment in a unfractured well. An additional economic benefit of proppant impregnated with scale inhibitor is increased well productivity. The benefit is derived from the combined effect of improved gel breaking, and scale inhibition during well clean-up. This has been demonstrated in laboratory testing and would appear to be confirmed by field observations. A further benefit of applying scale inhibitor as chemically impregnated proppant is the immediate treatment of produced water when water breakthrough occurs. This feature avoids the formation damage that can occur before squeeze treatment mobilisation. In addition, for some applications involving large fractures there is the potential for lifetime well treatment. This paper describes the laboratory work, the field trial and the economic benefits of the new product. Introduction Production of hydrocarbons is often associated with the deposition of mineral scales from co-produced water. Mixing of incompatible waters, and changes of temperature and pressure can cause deposition of carbonate (CaCO3) and sulphate (Ba/SrSO4) scales in the near wellbore and tubing of production wells. Scale deposition is a recurring operational problem for many conventional and advanced wells worldwide. Preventative and remedial scale control operations often involve significant cost to an operator through equipment and personnel, and deferred oil costs. This paper presents details of the technical and economic features of a revolutionary method of scale inhibitor delivery developed by AEA Technology with the support of Saga Petroleum ASA, Norsk Hydro ASA, and BP Exploration Operating Company Ltd. The delivery concept has many advantages when compared to conventional scale management strategies, as applied to advanced and conventional well completions. The current status of the technology allows simple application in fractured and gravel packed field developments. The considerable potential for applying other types of oilfield chemical is briefly discussed. P. 523^