bluuebunny/crossref_metadata_2025_split huggingface dataset:
How to Drill Mature, Depleted Reservoirs Without Downhole Losses Using Engineered Drilling Fluids
Authors: Calder Alan , Fitzgerald Barry , Lonca Matthieu , Gregoire Michel 
Published: December 2009

Abstract
Invert emulsion drilling fluids designed with an optimised range of pre-determined sized particulates have been used successfully to eliminate or minimise losses to the formation while drilling depleted reservoirs. Sands can be penetrated with up to 600 bar overbalance without encountering losses or differential sticking. Further, the wells have been drilled at pressures above their natural gradient. Selectively designing these fluids has also made it possible to successfully drill high-angle step-out sections through mature, depleted reservoirs.
This paper describes the development and implementation of this technology.
Fluid Design Phase – The selection and optimization of type, size and amount of particulates required takes place during the planning stage of the well based on the rock mechanics of the formations to be drilled, drilling fluid properties and the practicalities at the rig site. Execution Phase – Once the fluid design has been finalized, processes and procedures are developed to help ensure that during the project the fluid functions are designed taking account of the practicalities of the actual drilling phase.
Recent case histories of the application of this technology are discussed in detail: the first case highlights a severely depleted reservoir in an extreme high-pressure, high-temperature (HPHT) field and the second case relates to extended reach wells drilled through mature reservoirs which can be segmentally depleted.
Increased Earnings: Adding More Functions and Knowledge into Subsea Instrumentation to Increase Production, Keeping Safety Issues in the Driver Seat!
Authors: Brakstad Olav , Instanes Geir 
Published: December 2009

Abstract
The paper will give an introduction to sand problems and management in the oil & gas industry, and describe the challenges to overcome them. A major part of the presentation will be directed to deepwater and ultra deepwater applications with respect to sand management, subsea design and how the sand monitoring systems should be used with respect to sand production. The contractors are designing the subsea equipment more and more compact than ever and that adds challenges to designing and operation subsea sand monitoring equipment, ClampOn will address this, and show how this can be overcome by applying correct design to the project and operator.
It will be discussed why sand monitoring systems should be installed subsea and not at the surface since surface appears to be more cost-effective (and it is a fact that the operator have open access to the sensor, e.g. for tie back installations). An example from field will be shown to see the distinguished difference between a subsea installation and a topside installation. The example will explain the difference in quality of the measurement and the danger of filling up the production line with sand due to missing information about the nature of the sand production. It will be shown how an offshore operator can get real time information by installing the sand monitoring system subsea.
Part of the presentation will demonstrate how operators, by using a real life example, optimize the oil & gas production by the use of sand monitoring systems and the savings they make, in actual figures after installing sand monitors. Operators own experience with the sand control system will also be discussed – field data will be shown on several of these topics.
The paper will show the latest in development of ultrasonic sand monitoring systems – both for deepwater and ultradeep water installations. Further on it will show the development of a retrofit system that can be installed subsea on an existing flow line without any disturbance of the oil & gas production itself.
Also, the paper will discuss the probable future aspects of sand management and monitoring for subsea installations.
Sub-basalt Plays in the Rockall and Faroes-Shetlands Basins
Authors: Davison I. , Stasiuk Stefan , Nutall Peter , Keane Paul 
Published: December 2009

Abstract
The sub-basalt plays of the Faroes-Shetland and Rockall Basins are virtually untested. The seismic imaging below the basalts is generally poor and the thickness of the basalts is difficult to predict. Two recent wells (William and Brugdon) drilled in Faroes waters were suspended before reaching sub-basalt targets because the basalts were thicker than expected. New deep tow seismic reflection data shot by ION/GX Technology in 2008 has allowed imaging of the sub-basalt Mesozoic strata. The base basalt is non-reflective and is probably a transitional contact with a small acoustic impedance, but the underlying Mesozoic strata produce coherent reflectivity. Large structural closures produced by Cretaceous rifting and Cenozoic folding have been imaged in the Faroes-Shetland Basin and these may contain reasonable Mesozoic clastic reservoirs at drillable depths of about 4 km.
Some areas of the Rockall Trough are not covered by basalts and large Cenozoic age folded structures are present which produce potential traps at Late Cretaceous level where sandstones equivalent to the Nise Formation may occur. The Rockall Trough contains 4-6 km of Mesozoic strata and appears to be floored by stretched continental crust throughout. The lower section may contain Jurassic source rocks similar to the areas to the south and north of the basin. These are some of the largest undrilled structures in NW Europe and deserve a more dedicated exploration effort in the future.
A Novel Correlation for Estimation of Economic Thickness of Insulation for Process Piping and Equipments
Authors: Bahadori A. , Vuthaluru H. B. 
Published: December 2009

Abstract
Where the sole object of applying insulation to a portion of plant is to achieve the minimum total cost during a specific period (evaluation period), the appropriate thickness is usually termed as the economic thickness. The principle is to find at what thickness further expenditure on insulation would not be justified by the additional financial saving on heat to be anticipated during the evaluation period. Although an increase in the amount of insulation applied will raise the initial installed cost, but it will reduce the rate of heat loss through the insulation. Therefore it is necessary to reduce the total cost during the evaluation period. In this work, simple-to-use novel correlation is formulated to arrive at the economic thickness of hot insulation suitable for process piping and equipments. The correlation is a function of pipe diameter and thermal conductivity of insulation for hot surface temperatures at 100°C, 300°C, 500°C and 700°C. A simple interpolation formula generalizes this correlation for wide range of hot surface temperatures. The proposed correlation covers pipeline diameter and hot surface temperature up to 0.5 m and 700°C respectively. The average absolute deviation percent of proposed correlation for estimating the economic thickness of the hot insulator is 2.12% demonstrating the excellent performance of proposed correlation. Simple-to-use approach can be of immense practical value for the engineers and scientists to have a quick check on the optimum insulation thickness for wide range of conditions. In particular, practice engineers would find the proposed approach to be user friendly involving no complex expressions with transparent calculations.
Estimation of Static Bottom Hole Pressure from Well-Head Shut-in Pressure for a Supercritical Fluid in a Depleted HP/HT Reservoir
Authors: Nurafza Peyman R. , Fernagu Jeremie 
Published: December 2009

Abstract
A periodic measurement of static bottom-hole pressure to monitor the reservoir depletion is an essential reservoir management practice. In an HP/HT offshore environment, the unavailability of qualified permanent down-hole monitoring technologies and the risks and costs of occasional operations make gradient surveys very difficult to acquire on a routine basis.
On Elgin-Franklin (HP/HT gas condensate fields, North Sea, UKCS), the typical approach is to use an average fluid density to estimate the static bottom-hole pressure from the well-head shut-in pressure. This estimation is valid as long as there is only one phase present inside the well-bore. As soon as the pressure drops below dew point in the tubing, the vertical phase distribution changes and the bottom-hole pressure can not be accurately estimated using one single average density. Fluid segregation mechanisms involve complex thermo-convective phenomenon, in association to gravity, which are strongly related to the temperature gradient in the well bore.
Segregated phase distribution has been observed on some available static pressure gradient surveys, where three gradients were identified. They correspond to three different phases, i.e. gas at the top, condensate in the middle and supercritical gas at the bottom of the well. This phenomenon of having a low density fluid below a higher density fluid was referred to as "gradient reversals" (Bender and Holden, 1984). At that time, it was assumed to be only due to the increasing temperature with increasing depth, but not explicitly related to the thermo-dynamical behaviour of the critical fluid.
In this case, we show that the fluid densities numerically estimated from each phase composition, at the corresponding pressure and temperature in the tubing, are comparable to the densities derived from the measured gradients. Based on this, a robust correlation methodology has been developed to derive the static bottom-hole pressure from the well-head shut-in pressure using thermodynamic modeling.
Curing Shallow Water Flow in a North Sea Exploration Well Exposed to Shallow Gas
Authors: Opseth T. Landbø , Ribesen B. T , Syrstad B. , Huse A. , Bolstad L. , Saasen A. 
Published: December 2009

Abstract
Shallow water flow was severely hindering further drilling in the North Sea exploration well 16/1-9, "Draupne". The water depth was 111.5m. The 20" casing was set at 590m; above a shallow gas zone. After mounting the Blow Out Preventer (BOP), drilling the 17 1/2" section started and continued for a few 100 meters. The wellhead was routinely inspected using an ROV (Remotely Operated Vessel). After some time, a tiny flow was observed around the wellhead. The flow increased in strength and later a large wash out area was observed, and further drilling had to be terminated. Most likely, the water flow originated from a zone at a depth of 172m MSL.
To cure the shallow water flow it was decided to grout cement on the outside of the casings. Regular well cements was not desirable to use since these cements are somewhat retarded in itself by mineralogical composition. It was decided to use standard construction industry cement with a very short curing time. Before the grouting could start the BOP had to be removed. Because of the shallow gas zone underneath the 20" casing, two barriers had to be included in the well for well control. Two packers were used, one drillable and one retrievable. The BOP was removed and the grouting operation was performed successfully. No water flow or gas flow were observed while the cement was setting. After the cement was cured drilling resumed, first by drilling and retrieving the packers, then continuing to drill the 12 1/4" section. The paper describes all aspects of these operations in detail. It also focuses on necessary cleaning operation of bulk systems and logistical tanks to hinder polluting well cements with construction cements, and thereby avoid complicating other cementing operations.
Mature Field Production Optimisation Through Standardisation of Operating Procedures for Reservoir Monitoring
Authors: Bhushan Vikas , Lee Robert , Mukerji Parijat 
Published: December 2009

Abstract
The ultimate goal of excellence in brownfield management is to increase the value of a field through maximising production and ultimate recovery within its remaining economic life. The ability to successfully apply reservoir management techniques is essential in meeting the challenges of optimising late life production, particularly given the high costs of well interventions in an offshore environment. Further, the standardisation of operating procedures yields benefits both in terms of optimising the use of technical resources and in successfully meeting well intervention objectives. It also facilitates and promotes an active collaboration between the operator and service provider, both during offshore operations and later when the log data is evaluated and interpreted.
We will describe the development and application of robust Standard Operating Procedures (SOP&Amp;apos;s) for cased hole reservoir monitoring. These will be illustrated with recent examples from the Brent Field in the North Sea. Developing these SOP&Amp;apos;s was not a simple process, and required a detailed understanding of the rock & fluid properties, reservoir production mechanisms and contact movements, topsides constraints, and reservoir behaviour coupled with experience in data acquisition & interpretation methods which are tailored to meet the specific challenges of the field. The SOPs have been applied to meet a range of specific challenges such as the identification and perforation of gas zones, differentiating reservoir fluid type (e.g. formation/injection water and oil) to access bypassed oil, contact monitoring, and identifying impairment to increase production rates.
Success in the development and application of SOPs requires service company involvement and cooperation in all aspects: programme design, data acquisition (including real time support and monitoring to ensure data quality), processing, presentation and interpretation. Examples will be provided of how this involvement has been essential to the successful outcome of several interventions in the Brent field.
Managing Drilling Risk in a Mature North Sea Field
Authors: McIntyre Brett , Hibbert Ted , Keir Donald , Dixon Rachel , Orourke Tom , Mohammed Farid , Donald Adam , Chang Liu , Syed Anzar , Biran Valerie 
Published: December 2009

Abstract
As fields mature, drilling can become more difficult. The likelihood of losses increases as reservoir pressures decline while higher mud weights are needed to prevent collapse of overburden shales as targets are pushed further from the platform. Drilling parameters for the Forties field have become fairly well established after years of experience yet 65% of the wells drilled between 2002 and 2007 experienced incidents attributed to instability. As field production declined, economic viability demanded a step change in performance.
Through a better understanding of the field geomechanics and past drilling events, the Apache drilling team has implemented fit for purpose drilling procedures that have significantly improved drilling efficiency.
This paper describes how geomechanics analysis has been used to assist well planning. Incorporating the experience of recent wells, the Forties mechanical earth model has been refined and provides key inputs needed to optimise well plans and adapt drilling practices to changing conditions.
The adverse effects of anisotropy is a key reason for wellbore instability in the overburden. A joint Apache-Schlumberger team has been working to integrate geomechanics and geophysics knowledge of the field to quantify the effects of anisotropy related to bedding planes and weak shales.
It can be difficult to predict drilling and completion risks during well planning, often due to the lack of distinction between events caused by formation instability and those which are drilling induced (drilling practices, hole cleaning). Capturing and classifying historic drilling events is a fundamental key process in understanding the mechanism and causes of well bore failures.
Drilling performance in this mature field has been improved through the collaborative effort of Apache staff and key service providers. The refinement of the wellbore stability model has enabled sound practices and procedures to be developed.
The Role of Economics on Well and Fracture Design Completions of Marcellus Shale Wells
Authors: Schweitzer R. , Bilgesu H. I. 
Published: December 2009

Abstract
The demand for energy is increasing exponentially in the U.S and internationally. As a clean source of energy, the natural gas production is gaining importance. Many potential sources exist for gas production in the Appalachian Basin with the Marcellus shale being the largest resource in the U.S. This covers several states in the Eastern U.S. and plays a vital role in the future of gas production.
One of the unknowns of the Marcellus shale is the lack of commercially available information. Information on well and completion designs for the Marcellus shale is rather vague and tightly lipped. This information plays a key role in the production of these shale wells and can determine whether or not these wells may or may not be economical.
In this study, simulations have been conducted with several wellbore configurations for gas production from the Marcellus shale. Some of the parameters studied include lateral wellbore length, propped half length and the amount of fracture stages along with others. Economic evaluations were performed to determine the most cost efficient configuration. The average present day completion costs and projected sale price of gas are used in the calculation process.
Latin Hypercube Sampling (LHS) for Gas Reserves
Authors: Ekeoma E. , Appah D. A. 
Published: December 2009

Abstract
Latin Hypercube Sampling (LHS), unlike other simulation methods such as Monte Carlo Simulation (MCS), has not enjoyed wide applications in determination of reserve despite its capability to realize same accuracy as with the latter even with much fewer simulation trials. The parameters used in these distributions are extracted using software ‘digitizer’ from different plot of values derived from measurements of reservoir and fluid properties. This work dwells on analysis of two depleted gas fields for which the ultimate recovery is known. The distribution of porosity, water saturation, reservoir thickness and reserve size are input to crystalbal software to generate cumulative distribution function (CDF) and Probability density function (PDF) of original gas in place (OGIP) for each of the fields. The accuracy of Latin Hypercube Sampling is analysed by comparing the actual ultimate recovery and the OGIP predicted by LHS. The calculated recovery factors of 68.7% and 93.3%, for water driven and depletion driven gas reservoirs respectively, compare favourably with those of known gas reservoirs. Therefore, LHS is a good estimator of gas reserve. It is recommended that similar study should be carried out on condensate and oil reservoir, particularly on Niger Delta fields.
Stochastic Mortality: The Impact on Target Capital
Authors: Olivieri Annamaria , Pitacco Ermanno 
Published: December 2009

AbstractIn this paper, we take the point of view of an insurer dealing with life annuities, which aims at building up a (partial) internal model in order to quantify the impact of mortality risks, namely process and longevity risk, in view of taking appropriate risk management actions. We assume that a life table, providing a best-estimate assessment of annuitants' future mortality is available to the insurer; conversely, the insurer has no access to data sets and the methodology underlying the construction of the life table. Nonetheless, the insurer is aware that, in the presence of mortality risks, a stochastic approach is required. The (projected) life table, which provides a deterministic description of future mortality, should then be used as the basic input of a stochastic model.The model we propose focuses on the annual number of deaths in a given cohort, which we represent allowing for a random mortality rate. To this purpose, we adopt the widely used Poisson model, first assuming a Gamma-distributed random parameter, and second introducing time-dependence in the parameter itself. Further, we define a Bayesian-inferential procedure for updating the parameters to experience in some situations. The setting we define does not demand advanced analytical tools, while allowing for process and longevity risk in a rigorous way.The model is then implemented for capital allocation purposes. We investigate the amount of the required capital for a given life annuity portfolio, based on solvency targets which could be adopted within internal models. The outcomes of such an investigation are compared with the capital required according to some standard rules, in particular those proposed within the Solvency 2 project.
Neurons Preferentially Respond to Self-MHC Class I Allele Products Regardless of Peptide Presented
Authors: Escande-Beillard Nathalie , Washburn Lorraine , Zekzer Dan , Wu Zhongqi-Phyllis , Eitan Shoshy , Ivkovic Sonja , Lu Yuxin , Dang Hoa , Middleton Blake , Bilousova Tina V. , Yoshimura Yoshitaka , Evans Christopher J. , Joyce Sebastian , Tian Jide , Kaufman Daniel L. 
Published: December 2009

Abstract
Studies of mice lacking MHC class I (MHC I)-associated proteins have demonstrated a role for MHC I in neurodevelopment. A central question arising from these observations is whether neuronal recognition of MHC I has specificity for the MHC I allele product and the peptide presented. Using a well-established embryonic retina explant system, we observed that picomolar levels of a recombinant self-MHC I molecule inhibited neurite outgrowth. We then assessed the neurobiological activity of a panel of recombinant soluble MHC Is, consisting of different MHC I heavy chains with a defined self- or nonself-peptide presented, on cultured embryonic retinas from mice with different MHC I haplotypes. We observed that self-MHC I allele products had greater inhibitory neuroactivity than nonself-MHC I molecules, regardless of the nature of the peptide presented, a pattern akin to MHC I recognition by some innate immune system receptors. However, self-MHC I molecules had no effect on retinas from MHC I-deficient mice. These observations suggest that neuronal recognition of MHC I may be coordinated with the inherited MHC I alleles, as occurs in the innate immune system. Consistent with this notion, we show that MHC I and MHC I receptors are coexpressed by precursor cells at the earliest stages of retina development, which could enable such coordination.
Differential Regulation of IL-4Rα Expression by Antigen versus Cytokine Stimulation Characterizes Th2 Progression In Vivo
Authors: Perona-Wright Georgia , Mohrs Katja , Mayer Katrin D. , Mohrs Markus 
Published: December 2009

Abstract
IL-4 promotes Th2 differentiation and provides immunity to helminth infections but is also associated with allergy and asthma. This suggests that precise adjustment of IL-4 responsiveness is needed to correctly balance immune responses. The IL-4Rα chain is an essential component of the IL-4 receptor and signals via STAT6. In this study, we show that infection with a helminth pathogen elicited broad upregulation of IL-4Rα on bystander CD4+ T cells in the draining lymph node, while simultaneously resulting in the loss of IL-4Rα expression on activated Th2 cells. IL-4Rα upregulation was restricted to the reactive lymph node, occurred within 4 d of infection, and was driven by an IL-4– and STAT6–dependent mechanism. Mice heterozygous for Stat6 exhibited reduced IL-4Rα upregulation and a correspondingly attenuated Th2 response. Indeed, the enhanced IL-4Rα upregulation in BALB/c mice, compared with that in C57BL6 mice, predicted their stronger Th2 response. The selective downregulation of IL-4Rα on highly activated Th cells was triggered by antigenic stimulation, was accompanied by loss of IL-7Rα, and rendered the cells unresponsive to IL-4. Together these data reveal a tightly controlled program of changing IL-4 responsiveness that characterizes the initiation, amplification, and restriction of a Th2 response in vivo.