BP (Germany)

Abstract This paper presents analyses which permit some of the parameters that quantify a fracture and the fracturing process to be estimated from the pressure decline following fracturing. The primary assumptions are consistent with those of current practice—a vertical fracture of essentially constant height, propagating through a quasi-elastic formation, with continuous displacements (i.e., no slip) at the planes bounding the top and bottom of the fracture. The parameters which can be quantified from the pressure decline are the fluid loss coefficient, the fracture length and width, fluid efficiency, and time for the fracture to close. Introduction At the present time there is no direct and simple procedure for evaluating the basic parameters achieved procedure for evaluating the basic parameters achieved during a fracture treatment, such as the length, width and fluid efficiency at the time the treatment ends. There exist fracture models which permit estimation of fracture length and width based on assumed heights, fluid loss coefficient, fluid viscosity, and formation modulus. However, at the end of the treatment there is no way of knowing if the assumed parameters were correct, with the possible exception of fracture height near the wellbore. Techniques for defining the fracture geometry from production performance do not satisfy this need completely because of the time delay required for the data, and the inferred lengths and widths (fracture conductivity) are average values over sections which significantly contribute to production and are at best lower bounds on the actual dimensions created by the fracturing fluid. As the volume and unit cost of fluids used for a typical fracture treatment continue to increase, so does the need for better definition of the fracture geometry created by a particular treatment in a particular zone. particular treatment in a particular zone. SUMMARY OF DERIVATIONS Based on the concept of a vertical fracture as presented by Perkins and Kern and as extended by presented by Perkins and Kern and as extended by Nordgren, relationships based on the fracturing pressure decline are derived in this paper. pressure decline are derived in this paper. References and illustrations at end of paper. The basic assumptions for the applicability of the analyses are that the fracture:has essentially constant height.propagates through a quasi-elastic formation with negligible slip of bedding planes.was created by a constant injection race of apower-law fluid into two symmetric wings.propagates continuously during pumping and propagation stops when pumping stops.closes freely without significant interference from proppant. Since actual hydraulic fractures will deviate by varying degrees at various times from these idealized assumptions, the utility of the analyses presented for any application will depend on the degree of deviation and the sensitivity to the deviation. The ultimate utility will depend on the ability to provide realistic engineering correlations and predictions. As discussed in the "Discussion of Applications" section, the most likely deviations from assumptions 1, 4, and 5 above, would produce estimates erring on the conservative side for the fluid loss coefficient and length. In the following, the derived relationships are summarized with equation numbers corresponding to those in later sections of the paper. The relationships are expressed in terms of the dimensionless shut-in time,= t/to where to is the time since pumping stopped (shut-in) and to is the pump time prior to shut-in. The rate of pressure decline at time is .....................................(9) with f() defined by the bounds .....................................(3)

Abstract This paper presents main results of a shale stability study, related to the understanding of shale/fluid interaction mechanisms, and discusses shale strength correlation. The major shale/fluid interaction mechanisms: Capillary, osmosis, hydraulic, swelling and pressure diffusion, and recent experimental results are discussed. Factors affecting the shale strength are discussed, and a sonic compressional velocity-log based correlation for strength is proposed. Recommendations for modeling and improving shale stability are described, based on the current understanding of shale stability.

Abstract A study was made of adsorption of n-dotriacontane and n-butanol dissolved in n-heptane onto graphitized carbon black and various ground graphites having surface areas ranging from 5 to 700 m2 g-1. It was established that the adsorption of n-dotriacontane by the graphites is confined entirely to the basal planes of graphite crystals. This is attributed to a remarkable fit between the hydrogen atoms attached to one side of the zig-zag carbon chain in the normal paraffins and the centres of hexagons formed by the carbon atoms in the basal planes of the substrate. The longer the chain the more contacts it can form with the graphite surface and the more strongly it is adsorbed. More detailed studies of the adsorption of n-paraffins on ground graphites have shown that they form close-packed monolayers of horizontally disposed molecules on the basal planes. There is little further adsorption after the monolayers are complete. The heat of adsorption per molecule increases uniformly with the chain length reaching very high values for the normal paraffins having more than 30 carbon atoms. The formation of the close-packed layers has been used for the measurement of the proportion of basal plane surface in different types of graphites. n-Butyl alcohol also forms closely packed monolayers, but on the polar sites of graphites, which can be used for the estimation of their area. The basal plane and polar sites act independently in adsorption and their relative proportions characterize the adsorptive properties of graphites. Examination of graphite ground in n-heptane, which consists of plates of average area of several square micrometres and average thickness of 5 nm, shows that its surface consists predominantly of basal planes having a high adsorptive capacity for n-paraffins.

Although intergranular stress corrosion cracking (IGSCC) of high-pressure gas pipelines has been known for more than 20 years, a transgranular form (TGSCC) was detected more recently. Instances of TGSCC have been associated with dilute solutions with pH values in the region of 6.5 because of the presence of carbon dioxide (CO2). Such pH values indicate relatively little, if any, cathodic current reaches the pipe surface, since hydroxyl ions would be generated and pH would increase to values in the region of 10 if current did reach the pipe surface. Slow strain rate testing (SSRT) of pipeline steel specimens in dilute solutions of pH in the region of 6.5 suggested dissolution and hydrogen (H) ingress into the steel are involved in the crack growth mechanism. The initiation of TGSCC in specimens subjected to cyclic loading and maximum stresses approximating those of an operating line was facilitated by pitting. The geometry of the pits allowed the localized generation of solutions of lower pH than that of the bulk solution outside the pits, thereby facilitating dissolution and H discharge.

Summary The object of this paper is to discuss some of the unknown or little-known relationships between surface structure and deep displacements in the well-exposed Zagros orogenic belt of south-west Iran, which can be divided into three major structural belts. The subjective nature of all inferences about deep structure in the absence of seismic data supported by deep borehole evidence is accentuated. Only at relatively shallow depths where the rock succession is well known can concealed structure be predicted with confidence from surface geology alone.

PreviousNext No AccessSEG Technical Program Expanded Abstracts 2000Extended elastic impedance for fluid and lithology predictionAuthors: David N. WhitcombePatrick A. ConnollyRoger L. ReaganTerry C. RedshawDavid N. WhitcombeBP Amoco, Aberdeen, Patrick A. ConnollyBP Amoco, Sunbury, Roger L. ReaganBP Amoco, Houston, and Terry C. RedshawBP Amoco, Sunburyhttps://doi.org/10.1190/1.1815660 SectionsAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Permalink: https://doi.org/10.1190/1.1815660FiguresReferencesRelatedDetailsCited byPressure and saturation changes estimated from extended elastic impedance properties using time-lapse seismic data: Enfield Field, NW AustraliaSergey Shevchenko and Wayne D. Pennington1 November 2022 | The Leading Edge, Vol. 41, No. 11Genesis and regularity of bright spots in Guantao Formation and its significance for oil and gas indicationJinhui Zhang, Zhijun Zhang, Hongtao Shen, and Hongbo Ding15 August 2022References19 January 2018Rock Physics Templates in AI-GI and Extended Elastic Impedance DomainsJuan-Mauricio Florez* and Stanislav Kuzmin19 August 2015Study of prestack elastic parameter consistency inversion methods29 December 2011 | Applied Geophysics, Vol. 8, No. 4Analysis on Factors of Elastic Impedance Based on Connolly FormulaGoing quantitative with 4D seismic analysisGeophysical Prospecting, Vol. 54, No. 3 SEG Technical Program Expanded Abstracts 2000ISSN (print):1052-3812 ISSN (online):1949-4645Copyright: 2000 Pages: 2484 publication data© 2000 Copyright © 2000 Society of Exploration GeophysicistsPublisher:Society of Exploration Geophysicists HistoryPublished Online: 04 Jan 2005 CITATION INFORMATION David N. Whitcombe, Patrick A. Connolly, Roger L. Reagan, and Terry C. Redshaw, (2000), "Extended elastic impedance for fluid and lithology prediction," SEG Technical Program Expanded Abstracts : 138-141. https://doi.org/10.1190/1.1815660 Plain-Language Summary PDF DownloadLoading ...

Abstract Most water-based reservoir drilling fluid systems used today are comprised of four primary components: the base brine, viscosifier, fluid-loss additive, and bridging particles. With the exception of minor adjustments of loading levels, the first three components normally do not change. The two primary types of bridging agents include calcium carbonate and sodium chloride salt. Some companies offer as many as seven different grades or sizes of each type of bridging particle. For the first time, the "ideal" pigment-size-distribution theory used widely in the paint industry has been transferred to practical oilfield use. This paper discusses the method and its use in selecting the optimum blend of bridging particles, focusing on an ideal packing sequence for minimizing fluid invasion. The authors examine the various procedures for optimizing sealing, as well as a management maintenance system. The paper expands on Abrams’ Median Particle-Size Rule by going beyond the size of particle required to initiate a bridge. In the discussion, the authors examine the ideal packing sequence for formulating a minimally invading (non-damaging) fluid.

I Dirichlet and Related Processes.- 1 Computing Nonparametric Hierarchical Models.- 1.1 Introduction.- 1.2 Notation and Perspectives.- 1.3 Posterior Sampling in Dirichlet Process Mixtures.- 1.4 An Example with Poisson-Gamma Structure.- 1.5 An Example with Normal Structure.- 2 Computational Methods for Mixture of Dirichlet Process Models.- 2.1 Introduction.- 2.2 The Basic Algorithm.- 2.3 More Efficient Algorithms.- 2.4 Non-Conjugate Models.- 2.5 Discussion.- 3 Nonparametric Bayes Methods Using Predictive Updating.- 3.1 Introduction.- 3.2 Onn=1.- 3.3 A Recursive Algorithm.- 3.4 Interval Censoring.- 3.5 Censoring Example.- 3.6 Mixing Example.- 3.7 Onn= 2.- 3.8 Concluding Remarks.- 4 Dynamic Display of Changing Posterior in Bayesian Survival Analysis.- 4.1 Introduction and Summary.- 4.2 A Gibbs Sampler for Censored Data.- 4.3 Proof of Proposition 1.- 4.4 Importance Sampling.- 4.5 The Environment for Dynamic Graphics.- 4.6 Appendix: Completion of the Proof of Proposition 1.- 5 Semiparametric Bayesian Methods for Random Effects Models.- 5.1 Introduction.- 5.2 Normal Linear Random Effects Models.- 5.3 DP priors in the Normal Linear Random Effects Model.- 5.4 Generalized Linear Mixed Models.- 5.5 DP priors in the Generalized Linear Mixed Model.- 5.6 Applications.- 5.7 Discussion.- 6 Nonparametric Bayesian Group Sequential Design.- 6.1 Introduction.- 6.2 The DP Mixing Approach Applied to the Group Sequential Framework.- 6.3 Model Fitting Techniques.- 6.4 Implementation of the Design.- 6.5 Examples.- II Modeling Random Functions.- 7 Wavelet-Based Nonparametric Bayes Methods.- 7.1 Introduction.- 7.2 Discrete Wavelet Transformations.- 7.3 Bayes and Wavelets.- 7.4 Other Problems.- 8 Nonparametric Estimation of Irregular Functions with Independent or Autocorrelated Errors.- 8.1 Introduction.- 8.2 Nonparametric Regression for Independent Errors.- 8.3 Nonparametric Regression for Data with Autocorrelated Errors.- 9 Feedforward Neural Networks for Nonparametric Regression.- 9.1 Introduction.- 9.2 Feed Forward Neural Networks as Nonparametric Regression Models.- 9.3 Variable Architecture FFNNs.- 9.4 Posterior Inference with the FFNN Model.- 9.5 Examples.- 9.6 Discussion.- III Levy and Related Processes.- 10 Survival Analysis Using Semiparametric Bayesian Methods.- D. Sinha.- D. Dey.- 10.1 Introduction.- 10.2 Models.- 10.3 Prior Processes.- 10.4 Bayesian Analysis.- 10.5 Further Readings.- 11 Bayesian Nonparametric and Covariate Analysis of Failure Time Data.- 11.1 Introduction.- 11.2 Cox Model with Beta Process Prior.- 11.3 The Computational Model.- 11.4 Illustrative Analysis.- 11.5 Conclusion.- 12 Simulation of Levy Random Fields.- 12.1 Introduction and Overview.- 12.2 Increasing Independent-Increment Processes: A New Look at an Old Idea.- 12.3 Example: Gamma Variates, Processes, and Fields.- 12.4 Inhomogeneous Levy Random Fields.- 12.5 Comparisons with Other Methods.- 12.6 Conclusions.- 13 Sampling Methods for Bayesian Nonparametric Inference Involving Stochastic Processes.- 13.1 Introduction.- 13.2 Neutral to the Right Processes.- 13.3 Mixtures of Dirichlet Processes.- 13.4 Conclusions.- 14 Curve and Surface Estimation Using Dynamic Step Functions.- 14.1 Introduction.- 14.2 Some Statistical Problems.- 14.3 Some Spatial Statistics.- 14.4 Prototype Prior.- 14.5 Posterior Inference.- 14.6 Example in Intensity Estimation.- 14.7 Discussion.- IV Prior Elicitation and Asymptotic Properties 15 Prior Elicitation for Semiparametric Bayesian Survival Analysis.- 15.1 Introduction.- 15.2 The Method.- 15.3 Sampling from the Joint Posterior Distribution of(ss? ao).- 15.4 Applications to Variable Selection.- 15.5 Myeloma Data.- 15.6 Discussion.- 16 Asymptotic Properties of Nonparametric Bayesian Procedures.- 16.1 Introduction.- 16.2 Frequentist or Bayesian Asymptotics?.- 16.3 Consistency.- 16.4 Consistency in Bellinger Distance.- 16.5 Other Asymptotic Properties.- 16.6 The Robins-Ritov Paradox.- 16.7 Conclusion.- V Case Studies.- 17 Modeling Travel Demand in Portland, Oregon.- 17.1 Introduction.- 17.2 The Data.- 17.3 Poisson/Gamma Random Field Models.- 17.4 The Computational Scheme.- 17.5 Posterior Analysis.- 17.6 Discussion.- 18 Semiparametric PK/PD Models.- 18.1 Introduction.- 18.2 A Semiparametric Population Model.- 18.3 Meta-analysis Over Related Studies.- 18.4 Discussion.- 19 A Bayesian Model for Fatigue Crack Growth.- 19.1 Introduction.- 19.2 The Model.- 19.3 A Markov Chain Monte Carlo Method.- 19.4 An Example: Growth of Crack Lengths.- 19.5 Discussion.- 20 A Semiparametric Model for Labor Earnings Dynamics.- 20.1 Introduction.- 20.2 Longitudinal Earnings Data.- 20.3 A Parametric Random Effects Model.- 20.4 A Semiparametric Model.- 20.5 Predictive Distributions.- 20.6 Conclusion.

A bstract Constant offset sections can be mapped to a fixed offset and compared in order to provide a method of velocity analysis. The direct mapping to zero offset prior to stack might provide an alternative processing procedure to NMO and stack. The main advantage of such a procedure would lie in the correct treatment of cross‐dips, but interpretational advantages might also follow from the performance of partial stacks biased to either high or low offset information.

A double blind, placebo controlled trial of 5% acyclovir cream, applied topically five times a day for five days, was carried out in 49 patients with recurrent herpes labialis. These patients had a total of 74 episodes, 34 of which were treated with the 5% acyclovir cream and 40 with matching placebo. First episodes and all episodes treated with acyclovir cream had significantly shorter times to formation of ulcer or crust and to complete healing (p less than 0.05 for all variables). The duration of all symptoms and proportion of patients developing itching was also reduced by acyclovir cream in first episodes, though the difference was not significant. When the patient started treatment early in the course of a first episode acyclovir cream significantly reduced the percentage of lesions progressing beyond the papular stage (p less than 0.05). Acyclovir cream is well tolerated and effective for the treatment of recurrent herpes labialis.

Abstract A recently computed fit of the African and South American continents is astonishingly close, apart from an overlap of some 120 miles in the vicinity of the Niger delta. This paper attempts to determine whether there is a genuine misfit at this point or whether the delta may have grown beyond the continental margin after the continents separated. The evidence suggests that final separation took place in Albian times, and that the bulge of the present continental edge into the Atlantic Ocean has resulted from post-Cretaceous development of the delta. The gross structure of the delta region and also the associated minor structures are considered to represent a passive response to the influx of sediment from the Niger River.

Optimizing the Selection of Bridging Particles for Reservoir Drilling Fluids M.A. Dick; M.A. Dick M-I Search for other works by this author on: This Site Google Scholar T.J. Heinz; T.J. Heinz M-I Search for other works by this author on: This Site Google Scholar C.F. Svoboda; C.F. Svoboda M-I Search for other works by this author on: This Site Google Scholar M. Aston M. Aston BP Amoco Search for other works by this author on: This Site Google Scholar Paper presented at the SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, February 2000. Paper Number: SPE-58793-MS https://doi.org/10.2118/58793-MS Published: February 23 2000 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation Dick, M.A., Heinz, T.J., Svoboda, C.F., and M. Aston. "Optimizing the Selection of Bridging Particles for Reservoir Drilling Fluids." Paper presented at the SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, February 2000. doi: https://doi.org/10.2118/58793-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search nav search search input Search input auto suggest search filter All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE International Conference and Exhibition on Formation Damage Control Search Advanced Search AbstractMost water-based reservoir drilling fluid systems used today are comprised of four primary components: the base brine, viscosifier, fluid-loss additive, and bridging particles. With the exception of minor adjustments of loading levels, the first three components normally do not change.The two primary types of bridging agents include calcium carbonate and sodium chloride salt. Some companies offer as many as seven different grades or sizes of each type of bridging particle.For the first time, the "ideal" pigment-size-distribution theory used widely in the paint industry has been transferred to practical oilfield use. This paper discusses the method and its use in selecting the optimum blend of bridging particles, focusing on an ideal packing sequence for minimizing fluid invasion. The authors examine the various procedures for optimizing sealing, as well as a management maintenance system.The paper expands on Abrams' Median Particle-Size Rule by going beyond the size of particle required to initiate a bridge. In the discussion, the authors examine the ideal packing sequence for formulating a minimally invading (non-damaging) fluid.IntroductionAside from minor adjustments of solids loading, the base brine, viscosifier and fluid-loss control additive in a traditional reservoir drilling fluid system change little from their original composition. However, the fourth primary component - the bridging particles - is used in a wide range of grades and sizes, depending on the anticipated extent of fluid invasion that must be thwarted. Thus, designing proper particle-size distribution is the first step towards formulating a minimally invading, non-damaging fluid.Historically, Abrams' rule1 has been used for this purpose. This rule states that "the median particle size of the bridging material should be equal to or slightly greater than 1/3 the median pore size of the formation." It goes on to suggest the concentration of the bridging solids must be at least 5% by volume of the solids in the fluid. In terms of particle size this means, for example, that 50µ particles should be effective at sealing pores up to or around 150µ in diameter. However, Abrams' rule only addresses the size of particle required to initiate a bridge. The rule does not give optimum size or address an ideal packing sequence for minimizing fluid invasion and optimizing sealing. While Abrams' rule has been the principle guideline for selecting particle size and concentration, others have used a "shotgun" approach to provide a broad and "all-encompassing" particle-size-distribution range. This approach assumes a single size distribution, often apparantly random, will cover the full range of pore throats or permeabilities that are likely to be encountered.2However, this paper considers an ideal packing approach to the sealing problem, with the aim being to reduce formation damage and enhance the performance. This theory approaches reservoir drilling fluids from a reservoir-specific perspective. The theory works equally well for water-based (WBM) and oil-based (OBM) reservoir drilling fluids.Ideal Packing Theory - A Definition"Ideal packing" can be defined as the full range of particle-size distribution required to effectively seal all voids, including those created by bridging agents. This subsequent layering of bridging agents results in a tighter and less invading filter cake.The Ideal Packing Theory (IPT) introduced here takes a graphical approach to determine the optimum particle-size distribution of bridging material for given formation characteristics. The IPT uses either pore sizing from thin section analyses or permeability information, combined with particle-size distributions of the bridging material, to determine the Ideal Packing Sequence (IPS). Keywords: upstream oil & gas, particle, laboratory study, agent, particle size, svoboda, invasion, optimum target line, filter cake, drilling fluid property Subjects: Drilling Fluids and Materials, Drilling fluid selection and formulation (chemistry, properties) This content is only available via PDF. 2000. Society of Petroleum Engineers You can access this article if you purchase or spend a download.

Abstract Fluvial channel sandstones commonly form hydrocarbon reservoirs in oil-and gas-bearing basins. Where such sands were the product of deposition in broad, extensive channel systems, their lateral extent is often greater than the area of the producing oil or gas field. In such situations, lateral pinchout of reservoir sandstone bodies is unlikely to reduce the gross reservoir volume of the field. Where fluvial sands were deposited in more laterally restricted, perhaps meandering channel belts, however, lateral pinchouts are common. In the case of laterally restricted fluvial reservoirs, the spacing and distribution of producing wells becomes critical, particularly where numbers of laterally offset, "shoestring" sandstone bodies within a vertical sequence are isolated from each other by floodplain/floodbasin fines. A method has been developed for predicting the proportion of laterally discontinuous fluvial reservoir sandstones that can be accessed by specified development well patterns. The method is based on (1) relationships between channel belt width, channel depth and deposit thickness for various fluvial regimes; and (2) a statistical description of reservoir sandstone beds encountered in previously drilled wells, and is designed to be generally applicable. A Fortran IV computer program has been written to allow rapid and easy usage of the method.

<div class="htmlview paragraph">“Gas-to-liquids” catalytic conversion technologies show promise for liberating stranded natural gas reserves and for achieving energy diversity worldwide. Some gas-to-liquids products are used as transportation fuels and as blendstocks for upgrading crude-derived fuels.</div> <div class="htmlview paragraph">Methylal (CH<sub>3</sub>-O-CH<sub>2</sub>-O-CH<sub>3</sub>), also known as dimethoxymethane or DMM, is a gas-to-liquid chemical that has been evaluated for use as a diesel fuel component. Methylal contains 42% oxygen by weight and is soluble in diesel fuel.</div> <div class="htmlview paragraph">The physical and chemical properties of neat methylal and for blends of methylal in conventional diesel fuel are presented. Methylal was found to be more volatile than diesel fuel, and special precautions for distribution and fuel tank storage are discussed.</div> <div class="htmlview paragraph">Steady state engine tests were also performed using an unmodified Cummins B5.9 turbocharged diesel engine to examine the effect of methylal blend concentration on performance and emissions. Substantial reductions of particulate matter emissions have been demonstrated for 10 to 30% blends of methylal in diesel fuel. This research indicates that methylal may be an effective blendstock for diesel fuel provided design changes are made to vehicle fuel handling systems.</div>

The crystal structures of dilithium, disodium and diammonium terephthalate (1,4-benzenedicarboxylate) have been solved ab initio using Monte Carlo simulated annealing techniques, and refined using synchrotron powder data. The structures of dipotassium terephthalate, potassium hydrogen terephthalate and ammonium hydrogen terephthalate have been refined using single-crystal techniques. Li2C8H4O4 crystallizes in P2(1)/c, with a = 8.35921 (5), b = 5.13208 (2), c = 8.48490 (5) A, beta = 93.1552 (4) degrees, V = 363.451 (3) A3, Z = 2. The Li anions are tetrahedrally coordinated and the packing of the terephthalate anions resembles the gamma-packing of aromatic hydrocarbons. Na2C8H4O4 crystallizes in Pbc2(1), with a = 3.54804 (5), b = 10.81604 (16), c = 18.99430 (20) A, V = 728.92 (2) A3, Z = 4. The coordination of the two independent Na is trigonal prismatic and the terephthalate packing resembles the beta packing of hydrocarbons. (NH4)2C8H4O4 also crystallizes in Pbc2(1), with a = 4.0053 (5), b = 11.8136 (21), c = 20.1857 (24) A, V = 955.1 (2) A3, Z = 4. The cations and planar anions are linked by hydrogen bonds and the packing is a looser version of the beta packing. K2C8H4O2 crystallizes in P2(1)/c, with a = 10.561 (4), b = 3.9440 (12), c = 11.535 (5) A, beta = 113.08 (3) degrees, V = 442.0 (3) A3, Z = 2. The K is trigonal prismatic and the packing is also beta. Both KHC8H4O4 and (NH4)HC8H4O4 crystallize in C2/c, with a = 18.825 (4) and 18.924 (4), b = 3.770 (2) and 3.7967 (9), c = 11.179 (2) and 11.481 (2) A, beta = 98.04 (3) and 94.56 (5) degrees, V = 816.8 (3) and 790.9 (3) A3, respectively, and Z = 4. The packing in the hydrogen-bonded acid salts is also beta. Electrostatic interactions among the terephthalate anions appear to be important in determining the crystal packing.

A Ni-Mn-Ga single crystal with a modulated five-layered martensite structure is reported, demonstrating giant magnetic field induced strain (MFIS) of 7.1% at room temperature and of 6% at temperatures close to the austenite transformation (TA = 71 °C). The room temperature MFIS clearly exceeds the best results of around 6% measured earlier in 10M martensites. The larger MFIS is connected to the huge (>1%) change in the lattice distortion of the 10M structure, obtained within a narrow temperature interval of 47 K, which has been previously observed only during intermartensitic transformation. The present material shall effectively reduce the size of magnetic shape memory actuators.

Abstract In anisotropic media, the short-spread stacking velocity is generally different from the root-mean-square vertical velocity. The influence of anisotropy makes it impossible to recover the vertical velocity (or the reflector depth) using hyperbolic moveout analysis on short-spread, common-midpoint (CMP) gathers, even if both P- and S-waves are recorded.Hence, we examine the feasibility of inverting long-spread (nonhyperbolic) reflection moveouts for parameters of transversely isotropic media with a vertical symmetry axis. One possible solution is to recover the quartic term of the Taylor series expansion for t 2 - x 2 curves for P- and SV-waves, and to use it to determine the anisotropy. However, this procedure turns out to be unstable because of the ambiguity in the joint inversion of intermediate-spread (i.e., spreads of about 1.5 times the reflector depth) P and SV moveouts. The nonuniqueness cannot be overcome by using long spreads (twice as large as the reflector depth) if only P-wave data are included. A general analysis of the P-wave inverse problem proves the existence of a broad set of models with different vertical velocities, all of which provide a satisfactory fit to the exact traveltimes. This strong ambiguity is explained by a trade-off between vertical velocity and the parameters of anisotropy on gathers with a limited angle coverage.The accuracy of the inversion procedure may be significantly increased by combining both long-spread P and SV moveouts. The high sensitivity of the long-spread SV moveout to the reflector depth permits a less ambiguous inversion. In some cases, the SV moveout alone may be used to recover the vertical S-wave velocity, and hence the depth. Success of this inversion depends on the spreadlength and degree of SV-wave velocity anisotropy, as well as on the constraints on the P-wave vertical velocity.

Abstract This paper presents a method to determine optimum drilling fluid properties and flow rates to minimize cuttings bed height and circulation time in high angle and horizontal wells. The method uses empirical models relating the cuttings bed height and the bed erosion time to drilling fluid properties and flow rates. Bed erosion tests have been conducted using a cuttings transport facility available at the University of Tulsa. Cuttings bed height as a function of time has been investigated by using variable flow rates (200 – 400 gpm) and four different drilling fluid compositions. Experimental results were used together with a non-linear regression analysis program to establish a functional relationship among drilling fluid properties, flow rate, cuttings bed height and the time required to circulate the borehole clean. A numerical example is provided to explain the field application of the method. The sequential calculations involved in determining optimum combination of the Power Law viscosity parameters n and K, and the flow rate to minimize the cuttings bed height and circulation time are also given. Field implementation of the proposed empirical correlations and the new method can aid optimization of circulation practices before tripping, and so reduce the associated risk of nonproductive time.

Abstract The introduction of viscoelastic surfactant (VES) base fracturing fluids has changed the way industry views fracturing fluids and proppant transport during a fracture treatment.1 Elimination of polymers allows one to achieve highly conductive proppant packs with no polymer damage. Retained permeability and leakoff control are two of the most important requirements for fracturing fluids. Traditional and new generations of cross-linked gels provide good leakoff control, but they often adversely affect the retained permeability of the proppant pack. In addition, minimizing frac-height growth and increasing effective fracture length are a few other advantages of using VES fluids.2 In the majority of cases in low permeability formations, a long and conductive fracture is the ultimate aim of hydraulic fracturing. Borate or metal crosslinked guar fluids, because of their inherent high viscosity, typically result in height growth rather than increased fracture length. With VES fluids proppant transport is based on the elasticity and structure rather than the viscosity of fluid. Therefore VES fluids efficiently transport proppants at lower viscosities. At the same time, VES fluids let one achieve a better fracture geometry, that with minimum fracture height and maximum fracture length. Pressure transient analysis and tracer studies have shown that this non-damaging low viscosity fluid can give longer effective frac-length even when using much less fluid and proppant volumes (Figure 1). Reduced friction pressure is another added advantage while using VES fluids. Hence VES fluid is the fluid of choice when fracturing is performed through coiled tubing.3,4 Simplicity and reliability of this two component system are the other features of this fluid that attract the industry globally.5 The use of VES technology is now extended to other oilfield applications, such as selective matrix diversion,6 filtercake removal,7 and coiled tubing clean out. VES technology is also defining new engineering practices in hydraulic fracturing that cannot be accomplished with conventional fluid systems, such as fracturing through coiled tubing.

Stress corrosion cracking (SCC) characteristics of a range of pipeline steels immersed in a carbonate-bicarbonate solution were studied in terms of the deleterious effects of small-amplitude cyclic loading on threshold stress, together with the increase of crack nucleation and the decrease of average crack growth rates with increasing test times. Data were reported on conditions for coalescence or otherwise of adjacent cracks in terms of spatial separation. The time dependence of crack nucleation rates and crack growth in laboratory tests varied with stress. The laboratory rates for crack nucleation and growth likely are applicable in high-pressure gas transmission pipelines in service, but values of the constants in the power law expressions for those rates differed for service conditions. The data showed service condition calculations can be guided by empirically assigning ranges of values for the constants by imposing boundary conditions that relate to service experience. Ranges of values also reflected service experience in relation to variability of service lifetimes for pipe joints that developed cracks.