bluuebunny/crossref_metadata_2025_split huggingface dataset:
Subsea TFL Systems - A Technology Update
Authors: Arendt H. , Brands K. 
Published: December 2007

This paper presents and analyzes equipment development and testing, completion procedures, and maintenance operations using through-flowline (TFL) methods on five subsea wells in 100 to 200 ft (30.5 to 61 m) of water offshore Brunei. These wells, installed in 1974-76, presently are operated by Brunei Shell Petroleum and include both single-and dual-string (multizone) completions.

Introduction
In the early 1970's, Shell Internationale Petroleum Mij. (SIPM) undertook a series of studies aimed at the development of systems for producing deepwater oilfields beyond the continental shelf. An important building block in deepwater production systems would be the underwater completed (UWC) well. A principal objective was that the UWC wells would be drilled, completed, produced, and serviced using remote control and servicing techniques. Downhole servicing of the well would be done by pumpdown TFL techniques.

Single-Zone Well
In 1971 it was envisaged that the UWC wells would have to be large producers for an economical deepwater field development. The terms of reference established for a diverless deepwater subsea completion resulted in these basic requirements and assumptions:the well must be a prolific producer of 5,000 to 10,000 B/D (794.9 to 1589.8 m3/d);no artificial lift by gas lift would be needed;sand production would not be present;completion would be as simple as possible, preferably with a single production string probably 4 1/2 in. (114.3 mm) OD; androutine well servicing by TFL.
It was decided to install a pilot UWC (Fairley 16) offshore Brunei (Borneo) in relatively shallow water, permitting easy intervention by divers if necessary. For this purpose a project team was set up in Brunei. Since at that time TFL tools and ancillary equipment had been well-developed only for 2 3/8-in. (60.3-mm) tubing, SIPM approached Otis Engineering Corp. in Oct. 1971 to set up a program for developing and testing TFL capability in the larger tubing size [4-in. (102-mm) nominal size tools].Subsequently Otis designed and constructed the TFL tool string and service tools, a surface-controlled subsurface safety valve suitable for TFL, a Sliding Side-Door (SSD), and a standing valve. The equipment was tested in the Otis test well in Dallas from Aug. to Oct. 1972. A number of modifications were made to the equipment. It became apparent that the "reach rod" approach using conventional sucker rods led to unacceptable friction resistance in the TFL loops. ("Reach rod" refers to an operation whereby a flow control may be installed in a nipple below the TFL circulation point by using rods or bars to span the distance between the flow control running tool and the TFL piston units, which must remain above the circulating point.) To counter this friction, knuckled spacer bars approximately 3 ft (1 m) long were introduced and later tested successfully.
JPT
P. 1538＾
Error Characteristics of Extratropical-Storm Wind Fields Specified From Historical Data
Authors: Cardone V.J. , Broccoli A.J. , Greenwood C.V. , Greenwood J.A. 
Published: December 2007

This study derives errors inherent in methods used to specify marine surface wind fields in hindcast studies of extreme environmental factors associated with extratropical storms. The northeastern Pacific Ocean is taken as the study basin, but results should apply to most Northern Hemisphere areas.

Introduction
As part of the selection process for environmental design data for offshore structures to be placed in regions exposed to severe storms, data on extreme waves, currents, and surge are generated, usually by the application of hydrodynamic models in historical hindcast studies. The need to describe accurately the temporal and spatial distribution of the surface over the sea arises both in calibrating the hydrodynamic models and in applying the models to long meteorological series to provide a data base of environmental extremes for statistical evaluation.
Specification of the most accurate wind field description possible is especially crucial in the calibration studies. There, it is important to isolate errors in predictions of environmental factors (waves, currents, and surge) that are related to model physics or numerics from those errors introduced by deficiencies in the wind field. Of course, accurate windfield specification is desired in long-term historical simulations, though the sparsity pf early history meteorological data places an upper bound on attainable accuracy. In lieu of high accuracy, it becomes important to determine the errors that characterize historical wind field descriptions and the impact of those errors on the accuracy and reliability of environmental series generated by hindcast models. While much work has been reported recently on development, calibration, and application of hindcast models, the specification and validation of wind fields has received little attention, at least for extratropical storms.
This study was designed specifically to determine the errors characteristic of alternative methods that have been used to specify marine surface wind fields in hindcast studies of extreme environmental factors associated with extratropical storms. The northeastern Pacific Ocean was taken as the test basin, but the results should apply to any extratropical region with a comparable meteorological data density (e.g., north Atlantic, North Sea, Bering Sea).
Modeling of a Deepwater Turbidite Reservoir Conditional to Seismic Data Using Principal Component Analysis and Multiple-Point Geostatistics
Authors: Strebelle Sebastien , Payrazyan Karen , Caers Jef 
Published: December 2007

SummaryA new geostatistical approach, known as multiple-point statistics (MPS) simulation, recently has been proposed to generate 3D depositional facies models that integrate both large-scale information derived from seismic data and fine-scale information derived from well logs, cores, and analog studies. In this paper, the practicality, flexibility, and CPU advantage of this new approach are demonstrated through the modeling of an actual deepwater turbidite reservoir. First, based on well-log interpretation and a global geological understanding of the reservoir architecture, a training image depicting sinuous sand bodies is generated using a nonconditional object-based simulation algorithm. Then, disconnected sand bodies are interpreted from seismic amplitude data using a principal component cluster analysis technique, while a sand probability cube is generated using a principal component proximity transform of the same seismic. Multiple-point geostatistics allows simulating multiple realizations of channel bodies similar to the training image, constrained to the local sand probabilities, partially interpreted sand bodies, and well-log data. As illustrated in this paper, to account for uncertainty about the geometry of the sand bodies, different training images associated with alternative conceptual models proposed by the geologists can be considered.
Influence of Temperature and Clays/Emulsion Microstructure on Oil-Based Mud Low Shear Rate Rheology
Authors: Herzhaft Benjamin , Rousseau Lionel , Neau Laurent , Moan Michel , Bossard Frederic 
Published: December 2007

SummaryOil-based muds (OBMs) are complex fluids composed of water, oil, organophilic clays, and various additives. Their very good filtration and lubricating properties make their use beneficial in numerous drilling operations. Deep offshore operations may present phases using OBMs as drilling fluids. In these operations, the mud will experience extremely low temperature (down to 0°C) and low shear rate when flowing through the riser. It is therefore of primary importance to control mud rheological properties under such conditions.This work presents a rigorous experimental study of OBM rheological properties using scientific rheometers. Temperature dependence and low shear rate behavior are specially studied. Because of their complex nature, OBM rheological properties will be extremely dependent on their microstructure. Characterization of this microstructure has therefore been sought during this study.Several OBM compositions have been investigated. Flow curves have been established with a precise and reproducible procedure at temperatures varying from 0 to 80°C. For an offshore designed composition, a specific behavior at low shear rate has been detected. Two different regimes can be seen: a Newtonian behavior at low shear rate and a Herschel-Bulkley behavior at higher shear rate. The limiting shear rate value between the two regimes is dependent on temperature. Experiments on partial compositions (partial muds with/without solids, with/without clays) have shown that the specific clay used in this composition is responsible for this particular behavior at low shear rate. Oscillatory rheometry measurements have confirmed the existence of these two different regimes. CryoMeb and microscopic observations have allowed us to estimate the size of the emulsion droplets and of the clay particles. A simple energetic and structural model is proposed that fits the data well. Finally, a comparison is made between these experiments and those obtained using a Fann 35 (Fann Instrument Co., Houston) rheometer, concluding that classical Fann 35 measurements induce large error for low-shear-rate rheology.
Valuation of Technology and Information for Reservoir Risk Management
Authors: Raghuraman B. , Couët B. , Savundararaj P. , Bailey W. J. , Wilkinson D. J. 
Published: December 2007

SummaryReservoir risk management involves optimizing assets given inherent reservoir uncertainties and minimizing risk by reducing these accordingly. The decision to implement any reservoir management technology is usually based on some form of cost-benefit analysis. Consequently, the correct valuation of value-adding technology (often based on net present value, or NPV) becomes a significant part of a reservoir management process. This paper discusses techniques for the valuation of technology and information related to reservoir risk management. For demonstration purposes, these techniques are applied to valuation of real-time control and monitoring technologies in a reservoir with multiple uncertainties in its physical properties. Because of the presence of these uncertainties, value quantification requires a stochastic optimization of the reservoir production strategy, where the objective function includes a risk-aversion factor. By applying these techniques, one can generate a decision-making table that shows the benefit of implementing a technology at various confidence levels. One can then extend the analysis further to estimate the added value to the reservoir if the uncertainties were to be reduced (or even eliminated) by implementing appropriate monitoring technologies. This process enables quantification of the value of information and is useful in designing monitoring strategies.
Density Logging in the Gulf Coast Area
Authors: Campbell John L.P. , Wilson John C. 
Published: December 2007

Abstract
A radiation log, depending upon gamma rays scattered by and absorbed in the formation, gives a record from which the formation density can be derived. A comparison with laboratory measurements of cores sets the accuracy of the log at approximately 0.03 gm/cc.
In areas where lithological identification and correlation is difficult, the density log can give useful assistance.
The density log provides more representative and detailed density values for gravity meter interpretation than has been available from measurements made on either bit cuttings, well cores or outcrop samples.
Densities derived from the density log provide a means of calculating the formation porosity in limestone and sandstone reservoirs.

Introduction
Well logging equipment has been developed for measuring and recording many properties of the rocks through which the borehole passes, which are useful in the solution of exploration, well completion and petroleum production problems. Rock density or weight per unit volume of rock is a very important and basic rock property which has never been fully exploited. This has been due principally to the difficulty in making a suitable measurement of formation density from the borehole. However, within the past few years application of the strong effect of the density of materials on the absorption of gamma rays passing through them has provided a reliable means of making a continuous well log of formation density.
The density of materials can be measured in pounds per cubic foot but the metric unit, grams per cubic centimeter, is more commonly used because it is numerically equal to the specific gravity of the material, that is, the number of times the material is heavier than the same volume of water. The density of a rock is dependent upon the minerals of which it is composed. It varies from a low of 1.30 for lignites, through 2.05 for sulfur, 2.15 for salt, 2.31 for gypsum, 2.65 for clean non-porous sandstones, 2.71 for limestone, 2.85 for pure dolomites and 2.92 for anhydrite. These densities may be used for lithological identification of rocks which are known to be pure and non-porous. Fig. 1 illustrates the correlation of two logs showing density difference lithologically. However, many of the sediments are heterogeneous mixtures and cannot be identified on the basis of density measurement alone.
Nuclear Magnetic Resonance While Drilling in the Southern North Sea
Authors: Appel Matthias , Radcliffe Nigel J. , Aadireddy Prabhakar , Bonnie Ron J. M. , Akkurt Ridvan 
Published: December 2007

Summary
Standard formation evaluation of an exploration well in the U.K. southern North Sea was supported by magnetic resonance while drilling (MRWD).
In this paper we show that even in tight gas sands, MRWD provides information about porosity and producible fluid fraction and allows estimation of formation permeability.
This successful introduction of MRWD technology in a known hard-rock environment illustrates a powerful addition to the logging-while-drilling (LWD) tool suite.
Bank Loans on Gasoline Plants
Authors: McGonagill Frank E. 
Published: December 2007

Abstract
This paper presents the various factors concern the economics of gasoline plant design, construction and operation from the viewpoint of a financial institution considering a loan. The gas reserves, plant design, processing equipment, marketing conditions, and estimated construction and operating expenses are reviewed and the information required for the proper evaluation of a loan discussed.
The information obtained from the study of the various factors affecting the economics of gasoline plant design, construction and operation are then considered together in predicting the economics of future operation. The effects of depreciation and income tax in the cash throw-off of a plant are also covered. This information is then used to Illustrate the type of loan, the amount that can be loaned, and the repayment ability of a proposed plant being considered.
In addition to the above, a discussion is presented of the legal information necessary for the proper processing of the loan and the various legal instruments which are prepared for the protection of the lender.

Introduction
During the past few years, the increased demand for natural gasoline, butane, and propane has made the operation of a natural gasoline plant profitable in small fields that were previously considered of no economic value. This has brought an increase in the number of small plants being constructed and has opened the door for small companies and individuals in a field that previously was dominated by major companies. It has been necessary for the small companies and individuals to turn to private lending institutions for financing these plant, since they have not been in a position to finance construction out of income or obtain funds from the sale of securities to the public as have the larger companies.
In order to properly make and service gasoline plant loans, it has been necessary for banks to set-up a yardstick which can be used as a basis for determining the value of a plant and the amount which can be safely loaned. It is desirable that such loans be arranged on a conventional basis; that is, for the amount loaned to be adequately secured by the value of the plant with a means of liquidation being provided by income generated by the plant. Such a loan is considered a secured loan and is the type which this paper will consider.
Integrated Interpretation of Wireline and 3D Seismic Data To Delineate Thin Oil-Producing Sands in San Jorge Basin, Argentina
Authors: Torres-Verdín Carlos , Chunduru Raghu K. , Mezzatesta Alberto G. 
Published: December 2007

SummaryHydrocarbon-bearing sand units in San Jorge basin, Argentina, exhibit a wide range of spatial variability and thickness. In view of this, a typical well is planned to vertically intersect as many sand units as possible. There are several problems faced by the petrophysicist in assessing whether a given sand unit should be perforated: (a) discrimination between oil- and water-bearing sands is not trivial because of very low-salinity water, (b) there exist substantial vertical variations of effective porosity within an individual sand because of shale laminations, and (c) it is often impossible to assess lateral extent away from the well. We have successfully addressed most of these difficulties with an interpretation procedure centered on the 2D inversion of wireline array-induction data. Two-dimensional inversion of array-induction data is necessary for the accurate estimation of shallow and deep resistivities, as well as the invasion length in light of significant shoulder-bed effects. This procedure has been complemented with the use of borehole nuclear magnetic resonance (NMR) data to provide estimates of effective porosity within individual sand units. Finally, we have made use of geostatistical inversion of 3D post-stack seismic data to estimate the lateral extent of hydrocarbon-bearing sands laterally away from wells. We present several application examples that yield results consistent with borehole testing and production data.
Development of the Alba Field—Evolution of Completion Practices, Part 2: Openhole Completions, Conventional Gravel Packing After Drilling With SOBM
Authors: Murray G. , Morton K. , Blattel S. , Davidson E. , McMillan N. , Roberts J. 
Published: December 2007

Summary
Chevron has been successfully drilling and gravel packing openhole horizontal wells in the Alba field (central North Sea) since 1998, and 13 openhole gravel-packed (OHGP) wells drilled with water-based mud (WBM) are currently in production with no history of sand production. Although these wells have been hugely successful with significant net present value (NPV) returns, it was recognized that the future, mature redrill and infill targets cannot sustain the current costs associated with traditional OHGP completions. The challenge was to develop alternative techniques to maintain the benefits of OHGP wells but to achieve a low-cost well and completion concept to assist in realizing new drilling opportunities.
Drilling the shale above the top of the reservoir and the productive interval in a single hole section would require removing conventional requirements for setting an additional casing string and changing over to a water-based system before drilling into the reservoir. This would save costs but raises a question concerning the gravel-packing operation. Hitherto, attempts to gravel pack that involve alpha/beta placement techniques using an aqueous carrier fluid following drilling with oil-based systems have had only limited success.
The prospective problems were examined by extensive laboratory tests carried out cooperatively by Baroid and Chevron. A new, synthetic oil-based mud (SOBM) formulation was developed, and compatible displacement fluids and procedures were devised.
Based on this work, 1,500 ft of shale and reservoir were drilled, a liner that was predrilled over the reservoir section was installed, and screen was run inside the liner. Gravel was pumped using brine as the carrier fluid, and complete gravel placement was achieved. The well has achieved productivity levels at least as good as existing WBM wells. A second well completed in the same manner has given a similar performance.
This combination of a liner system and SOBM fluids offers several advantages. There is the prospect of considerable savings with respect to operating time, cementing, and drilling fluids. The liner also gives protection to the screen.
This new approach, which represents potential large savings in costs and excellent productivity, is considered applicable to other types of completions when it is desirable to drill with oil-based mud even though conventional thinking would have called for water-based drill-in fluid. This consideration applies to targets in the Alba field and worldwide.
Laboratory Evaluation of In-Situ Gelled Acids for Carbonate Reservoirs
Authors: Taylor K. C. , Nasr-El-Din H. A. 
Published: December 2007

SummaryThree different commercial formulations (A, B, and C) of in-situ gelled acids are compared in detail at temperatures up to 150°F and acid concentrations from 5 to 20 wt% HCl. In-situ gelled acids are said to work by a gelation mechanism that occurs at the rock surface as the acid is spent. These acids contain a polymer, a crosslinker, and a breaker, in addition to other additives. Detailed viscosity measurements of each in-situ gelled acid were made with live, partially neutralized, and spent acid. A new experimental procedure was developed to partially neutralize the in-situ gelled acid with calcium carbonate, and then the apparent viscosity was measured as a function of shear rate in the range 1 to 3,000 s−1. The pH values of these samples varied from 0 to 6. Relative reaction rates with reservoir rock of the three in-situ gelled acids were compared at 100°F. Coreflood experiments were conducted with small acid volumes, so that permeability could be measured before acid breakthrough occurred.In-situ gelled acids all retarded the reaction of acid with reservoir rock, primarily as a result of the polymer present in the acid formulae.From viscosity measurements, live in-situ gelled acids A and B behaved more like gelled acids. Their viscosity in live acid was significantly higher than that of Acid C. In spent acid, the viscosity of Acid C was higher than that of Acids A or B. Acid C was most effective at initial HCl concentrations of 5 and 10 wt% at 100 and 150°F. Acids A and B were effective only at an initial HCl concentration of 10 wt% and 100°F.Coreflood studies showed that the polymer and crosslinker component of in-situ gelled acids irreversibly reduced the permeability of carbonate reservoir rock.As with any spent acids, mixing spent in-situ gelled acids with seawater resulted in calcium sulfate precipitation for all three of the acid systems.
Riser Slugging: A Mathematical Model and the Practical Consequences
Authors: Sagatun S. I. 
Published: December 2007

SummaryThis article presents a novel approach to estimating severe riser slug buildup time and, consequently, the slug period. The slug model is based on a simplified mechanical model. An explicit estimate of the slug buildup time is presented. The simplified slug model has subsequently been used to illustrate the effects of the traditional actions to prevent severe riser slugging. The slug model is subsequently tested against field data from an offshore floating production platform and large-scale experimental data, as well as data from the literature. The experimental setup is described in detail. The estimate on the slug buildup time provided by the simplified model matches well the experimental data, the field data, and data from relevant references.