High-pressure Formation Research Articles

Variability in resistance to Cold Atmospheric Plasma (CAP) and Ultraviolet light (UV) and multiple stress resistance analysis of pathogenic verocytotoxigenic Escherichia coli (VTEC)

This study assessed the resistance to Ultraviolet light (UV) and Cold Atmospheric Plasma (CAP) of ten verocytotoxigenic Escherichia coli (VTEC) isolates and two laboratory non-pathogenic E. coli strains and monitored the effects that UV and CAP have on VTEC molecular composition by using Fourier transform infrared (FTIR) spectroscopy. In addition, serotype-related resistance patterns to different stresses (acid, alkaline, heat, high hydrostatic pressure, UV, CAP and biofilm formation ability) were determined through multivariate analysis of stress resistance parameters. While UV treatments were very effective in inactivating VTEC, with >5log reductions at the lowest intensity tested (15mJ) and low intraspecies variability, the efficacy of CAP treatments was more limited, with in general <3log reductions after a treatment of up to 3min in the lab-scale CAP equipment and larger interstrain variability. Two VTEC strains with non-sense mutations in the global stress response regulator rpoS showed an increased sensitivity to CAP at short treatment times, what suggests that RpoS is important for the cellular defensive response to this technology of preservation. Stepwise Discriminant Analysis (SDA) of FTIR spectra allowed the differentiation of untreated and treated samples based on a subrange of the spectral region w4 (1200 to 900cm−1), which suggests that the damage inflicted to the cells is focused, both for UV and CAP treatments, in nucleic acids and the cell wall. Principal Component Analysis (PCA) of stress resistance parameters allowed the identification of significant associations between VTEC serotypes and their stress resistance patterns. Strains of the serotype O157, more commonly associated with human disease, were in general more resistant to food-related stresses than strains of other serotypes when they had a functional RpoS, emphasizing the influence that stressors may have in the epidemiology, ecology and disease-causing potential of VTEC.

Shale gas in China: Characteristics, challenges and prospects (I)

Abstract This paper mainly discusses the industrialization progress, “sweet spot” evaluation criterion, E&P technologies, success experiences, challenges and prospects of China's shale gas. Based on the geologic and engineering parameters of the Fuling, Changning and Weiyuan shale gas fields in the Sichuan Basin, this paper points out that China's shale gas has its particularity. The discoveries of super-giant marine shale gas fields with high evolution degree (R o =2.0%−3.5%) and ultrahigh pressure (pressure coefficient=1.3−2.1) in southern China is of important scientific significance and practical value to ancient marine shale gas exploration and development to China and even the world. It's proposed that shale gas “sweet spots” must be characterized by high gas content, excellent frackability and good economy etc. The key indicators to determine the shale gas enrichment interval and trajectory of horizontal wells include “four highs”, that is high TOC (>3.0%), high porosity (>3.0%), high gas content (>3.0 m 3 /t) and high formation pressure (pressure coefficient>1.3), and “two well-developed” (well-developed beddings and well-developed micro-fractures). It's suggested that horizontal well laneway be designed in the middle of high pressure compartment between the Upper Ordovician Wufeng Formation and Lower Silurian Longmaxi Formation. The mode of forming “artificial shale gas reservoir” by “fracturing micro-reservoir group” is proposed and the mechanisms of “closing-in after fracturing, limiting production through pressure control” are revealed. Several key technologies (such as three-dimensional seismic survey and micro-seismic monitoring of fracturing, horizontal wells, “factory-like” or industrialized production mode, etc.) were formed. Some successful experiences (such as “sweet spot” selection, horizontal well laneway control, horizontal length optimization and “factory-like” production mode, etc.) were obtained. The four main challenges to realize large-scale production of shale gas in China include uncertainty of shale gas resources, breakthroughs in key technologies and equipment of shale gas exploration and development below 3 500 m, lower cost of production, as well as water resources and environment protection. It is predicted that the recoverable resources of the Lower Paleozoic marine shale gas in southern China are approximately 8.8×10 12 m 3 , among which the recoverable resources in the Sichuan Basin are 4.5×10 12 m 3 in the favorable area of 4.0×10 4 km 2 . The productivity of (200−300)×10 8 m 3 /a is predicted to be realized by 2020 when the integrated revolution of “theory, technology, production and cost” is realized in Chinese shale gas exploration and development. It is expected in the future to be built “Southwest Daqing Oilfield (Gas Daqing)” in Sichuan Basin with conventional and unconventional natural gas production.

Effect of quadratic pressure gradient term on a one-dimensional moving boundary problem based on modified Darcy’s law

A relatively high formation pressure gradient can exist in seepage flow in low-permeable porous media with a threshold pressure gradient, and a significant error may then be caused in the model computation by neglecting the quadratic pressure gradient term in the governing equations. Based on these concerns, in consideration of the quadratic pressure gradient term, a basic moving boundary model is constructed for a one-dimensional seepage flow problem with a threshold pressure gradient. Owing to a strong nonlinearity and the existing moving boundary in the mathematical model, a corresponding numerical solution method is presented. First, a spatial coordinate transformation method is adopted in order to transform the system of partial differential equations with moving boundary conditions into a closed system with fixed boundary conditions; then the solution can be stably numerically obtained by a fully implicit finite-difference method. The validity of the numerical method is verified by a published exact analytical solution. Furthermore, to compare with Darcy’s flow problem, the exact analytical solution for the case of Darcy’s flow considering the quadratic pressure gradient term is also derived by an inverse Laplace transform. A comparison of these model solutions leads to the conclusion that such moving boundary problems must incorporate the quadratic pressure gradient term in their governing equations; the sensitive effects of the quadratic pressure gradient term tend to diminish, with the dimensionless threshold pressure gradient increasing for the one-dimensional problem.

Geological characteristics and “sweet area” evaluation for tight oil

Tight oil has become the focus in exploration and development of unconventional oil in the world, especially in North America and China. In North America, there has been intensive exploration for tight oil in marine. In China, commercial exploration for tight oil in continental sediments is now steadily underway. With the discovery of China’s first tight oil field—Xin’anbian Oilfield in the Ordos Basin, tight oil has been integrated officially into the category for reserves evaluation. Geologically, tight oil is characterized by distribution in depressions and slopes of basins, extensive, mature, and high-quality source rocks, large-scale reservoir space with micro- and nanopore throat systems, source rocks and reservoirs in close contact and with continuous distribution, and local “sweet area.” The evaluation of the distribution of tight oil “sweet area” should focus on relationships between “six features.” These are source properties, lithology, physical properties, brittleness, hydrocarbon potential, and stress anisotropy. In North America, tight oil prospects are distributed in lamellar shale or marl, where natural fractures are frequently present, with TOC > 4 %, porosity > 7 %, brittle mineral content > 50 %, oil saturation of 50 %–80 %, API > 35°, and pressure coefficient > 1.30. In China, tight oil prospects are distributed in lamellar shale, tight sandstone, or tight carbonate rocks, with TOC > 2 %, porosity > 8 %, brittle mineral content > 40 %, oil saturation of 60 %–90 %, low crude oil viscosity, or high formation pressure. Continental tight oil is pervasive in China and its preliminary estimated technically recoverable resources are about (20–25) × 108 t.

Surface and internal energy of hydrocarbon gas bubbles as a factor of formation of gas deposits and related heat anomalies

It is shown that, during coalescence of bubbles, the mechanical energy of the surface tension transits to the heat energy sufficient to increase the temperature of the bed–reservoir by several tens of degrees. The positive heat anomalies and anomalously high formation pressure in the petroleum regions may be caused by energy released during the amalgamation of a small-disperse gas phase into economic deposits.

Оценка возможности ликвидации газопроявлений Бованенковского месторождения новыми цементными составами

Background Future increase in production of natural gas demands to develop new gas fields. Today the main gas producing region is Western Siberia where the major part of gas fields is located. In order to increase gas production in the nearest future, it will be necessary to start the development of new fields situated on the Yamal peninsula. The productive horizons of this oil and gas region have a complex geology, and some gas condensate reservoirs confined to Neocomian and Jurassic deposits have abnormally high formation pressures and temperatures above 100 °С. Special place among the Yamal fields takes the Bovanenkovskoye oil and gas condensate field. It is situated in the central part of the Yamal peninsula on the territory of the Yamal area, in the Yamal-Nenets Autonomous District of the Tyumen region. The region is featured by severe climate, slight solar radiation, high cyclonic activity, permafrost, flat terrain and proximity to the cold Kara Sea with its gulfs going far into the land. Aims and Objectives Preventing gas shows in the ice rich permafrost in the construction and repair of gas wells. Methods The study of the causes of gas shows in ice rich permafrost, development of cement compositions, laboratory and field tests. Results 1. The Bovanenkovskoye field is formed by ice rich permafrost. Today, avoiding gas shows during well construction is impossible. 2. Various cement mixes were used during well casing and cementing to prevent gas shows. Cementing with the use of CemFrost gave lower coefficient of the cement bond with the casing and the rock, in comparison with the design TsTRO and TsTRS cements used for well casing and cementing. 3. The use of GranCem-7 cement slurry mixed with calcium chloride solution gave higher values of cement-to-casing adhesion coefficient, yet not sufficient for the cement-rock bond. 4. The advantage of GranCem-7 mixture is almost complete filling of the annulus, which significantly reduces the likelihood of gas show occurrence. Conclusion Since the work aimed at a comprehensive solution of the problem of cementing quality assurance without significant changes in technology was experimental, the results obtained in preventing gas shows can be considered ambiguous. However, when using the compositions based on GranCem-7 obvious is the need to change them so as to improve their gas blocking properties for reliable isolation of the lower interval of Beryozov formation. The occurrence of gas shows between the intermediate and conductor casings in the wells being drilled in the Bovanenkovskoye field can be explained, first of all, by gas penetration from the upper layers of the Beryozov formation, as well as by the gas cross flows from the neighboring wells with annulus pressures.

High pressure study of a highly energetic nitrogen-rich carbon nitride, cyanuric triazide.

Cyanuric triazide (CTA), a nitrogen-rich energetic material, was compressed in a diamond anvil cell up to 63.2 GPa. Samples were characterized by x-ray diffraction, Raman, and infrared spectroscopy. A phase transition occurring between 29.8 and 30.7 GPa was found by all three techniques. The bulk modulus and its pressure derivative of the low pressure phase were determined by fitting the 300 K isothermal compression data to the Birch-Murnaghan equation of state. Due to the strong photosensitivity of CTA, synchrotron generated x-rays and visible laser radiation both lead to the progressive conversion of CTA into a two dimensional amorphous C=N network, starting from 9.2 GPa. As a result of the conversion, increasingly weak and broad x-ray diffraction lines were recorded from crystalline CTA as a function of pressure. Hence, a definite structure could not be obtained for the high pressure phase of CTA. Results from infrared spectroscopy carried out to 40.5 GPa suggest the high pressure formation of a lattice built of tri-tetrazole molecular units. The decompression study showed stability of the high pressure phase down to 13.9 GPa. Finally, two CTA samples, one loaded with neon and the other with nitrogen, used as pressure transmitting media, were laser-heated to approximately 1100 K and 1500 K while compressed at 37.7 GPa and 42.0 GPa, respectively. In both cases CTA decomposed resulting in amorphous compounds, as recovered at ambient conditions.

Automatic detection of formations using images of oil well drilling cuttings

Abstract In oil well drilling process, a perennial issue is formations detection particularly in passing through high and low pressure formations. However, automatic classification of keybeds in the Gachsaran and Asmari formations by applying drill cutting images can help in decision-making, especially in oil wells of Iran, about mud weight and casing design for oil well drilling process. First, this study focuses on color analysis and fuzzy c-mean clustering to extract relevant features from images of the drill cuttings. Furthermore, a support vector machine and different kernel functions are utilized to classify the samples into different keybeds. Second, due to changing color of drilling cutting in each well, this study proposes texture analysis for keybeds classification. In this method, a co-occurrence matrix and features of energy, homogeneity, entropy and brightness are applied as feature vectors and classification is done by using the support vector machine too. This study, moreover, introduces the accuracy and response speed of the above techniques. To sum up, the results show that this method can be used to detect different formations (particularly between Gachsaran and Asmari) by approximately 95% accuracy.

Combining Pressurized-Mud-Cap-Drilling and Early-Kick-Detection Techniques

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 165893, ’Combining Pressurized-Mud-Cap-Drilling and Early-Kick- Detection Techniques for Fractured Formations Overlying a High-Pressure Reservoir in Offshore Kalimantan,’ by Benny Benny, SPE, Andri M. Hidayat, Ardia Karnugroho, SPE, Julius Sosa, and Julmar Shaun S. Toralde, SPE, Weatherford, prepared for the 2013 SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 22-24 October. The paper has not been peer reviewed. Pressurized-mud-cap drilling (PMCD) and early kick detection (EKD) are two unconventional drilling techniques that have been used widely individually, mostly in relation to closed and pressurizable systems and to managed-pressure-drilling (MPD) applications. The techniques, however, are seldom used together as an integrated setup. This paper describes a synergized PMCD and EKD setup and the field deployment where it was used to drill a well successfully offshore Kalimantan, Indonesia, that had a high-pressure formation below a zone prone to severe circulation losses. Introduction Many drilling problems offshore Kalimantan involve lost-circulation problems and unintended influxes. Drilling conventionally through fractured and extremely vugular carbonate formations, which are prone to severe lost-circulation problems, can lead eventually to well-control situations. Aside from that, significant time and resources are required to cure the losses before conventional drilling can be continued. In addition, of 1,000 ft of carbonate formation drilled offshore Kalimantan, the fractures often are present in layers, which will multiply considerably the time and resources spent each time severe or total loss is encountered. One of the more well-known ways to mitigate this problem is implementation of the variant of MPD called PMCD, which enables the operator to drill through the fractured formation safely and efficiently. Meanwhile, also in offshore Kalimantan, most of the zone that resides just several feet below the fractured carbonate formation is highly pressurized gas reservoir. Drilling conventionally through such a pressurized zone exposes the operation to greater risk because of a lack of precision in detecting any influx or outflux during the drilling operation. A better method for detecting influx is the use of a flowmeter to monitor the flow from the well. The most common flowmeter used is a Coriolis mass flowmeter (CMF). Although the CMF has the advantage of great precision in measuring flow rates, the conventional setup lacks accuracy because the system is open to the atmosphere. A further improvement is to use it in conjunction with the MPD system to create a closed-loop system that will increase accuracy. This is the EKD system.

Fracture Stimulation in the First Joint-Appraisal Shale-Gas Project in China

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16762, ’Successful Fracture Stimulation in the First Joint-Appraisal Shale-Gas Project in China,’ by Liang Jin, Changlong Zhu, Yong Ouyang, Ming Zhou, Qingguang Qu, Fei Li, Roger Yuan, Chris Wu, Zhiyi Zhang, Yan Wang, and Fa Dwan, Shell China Exploration &amp; Production; Sanjay Vitthal, Shell Canada; and Shiqian Wang, PetroChina Southwest, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. This paper discusses fracture stimulation in the first joint-venture shale-gas project with foreign companies in China. The block is in Sichuan province, and the target zone is Longmaxi hot shale, a Silurian formation. Its matrix permeability is extremely low (100 to 300 nanodarcies), but it is rich in natural fractures. Hydraulic fracturing has been shown to be critical to enhancing production. A collaborative approach was applied to the completion of the shale gas wells during appraisal. Introduction Most of China’s proved shale-gas resources are in the Sichuan, Tarim, and Ordos basins. China’s technically recoverable shale-gas resources are estimated at 1,275 Tcf. The operator jointly appraised a shale-gas block in Sichuan with PetroChina. The project team needed to make several determinations in the early phase of the project, such as whether there is sufficient gas in the shale formation and whether the gas can be extracted at a high-enough (commercial) rate. From the production technologists’ perspective, the technical objectives of the early wells included the following: Test the ability of the Longmaxi hot-shale interval to be fractured under high formation pressure. Establish baseline fracture designs for the Longmaxi hotshale interval, at greater than 3500-m true vertical depth (TVD), and systematically evaluate the design parameters. Establish an effective multidisciplinary workflow. Gather fracture-stimulation-performance data and subsurface-pressure information. Determine the productivity of the gas from the appraisal wells to prove the presence of a shale-gas play. The joint-appraisal phase began in November 2010. While planning the drilling of deep wells to evaluate the Longmaxi formation, data were obtained from several shallow wells at a location close to the surface. Extensive laboratory tests were conducted to evaluate the geochemical properties of the rock. In addition, some rock-mechanics properties were measured. The drilling of the first well (Well A) began in December 2010, and hydraulic fracturing began once the well reached designed depth. To date, five wells have been drilled; two are vertical, and three are horizontal.

Extreme Deepwater Wells Push Drillers to Begin Using Managed-Pressure Methods

Dual-Gradient Drilling Dual-gradient drilling has long been described as the drilling method of the future for challenging offshore wells. Now there are indications that it could start being used with some regularity, with multiple-well campaigns possible as early as next year. This method of managed-pressure drilling has been used a handful of times on a floating drilling rig, mostly to precisely manage the pressure in wells while drilling in weak, low-pressure formations prone to major fluid losses. Currently, Chevron and Statoil are seeking to use the system for deep, difficult, high-pressure formations in the US Gulf of Mexico. A drillship leased by Chevron, Pacific Santa Ana, is testing dual-gradient equipment on the ocean bottom while drilling a conventional well, and the company has leased a second drillship from Pacific Drilling, Pacific Sharav, that was built to accommodate dual-gradient drilling equipment. Statoil is seeking a permit to drill what could be the first dual-gradient well in the deep waters of the Gulf of Mexico, using another version of the managed-pressure method. “When we came here to the Gulf of Mexico, it was a perfect match with the challenges we had here,” said Uno Holm Rognli, vice president of drilling and wells in the offshore US for Statoil. “We started a program locally to develop this system” for conditions in the Gulf. It is the next step for the method used by Statoil off Norway, and by three companies in water 7,500 ft deep off Cuba. In both places it was used to successfully drill wells where pressure was so low, and the rock so fragile, that wells drilled using conventional methods were plagued by major fluid losses. While a few pioneers are working on dual-gradient drilling, there is a broader, growing base of operators using managed-pressure systems offshore. These are closed-loop systems with metering to allow precise measurement of change in fluid flows and chokes that allow them to apply backpressure when needed. Petronas and Petrobras are embracing managed-pressure drilling to deal with offshore wells where total fluid loss makes some wells impossible to drill using conventional methods. Managed-pressure equipment allows them to drill through sections of wells with cavernous underground hazards that can cause major fluid loss by using managed-pressure methods such as mud-cap drilling. ’New Ways To Manage Pressure Raise Well Control Questions’ When discussing dual-gradient drilling, there is an important distinction between controlling wells and well control. Controlling wells requires maintaining the balance between preventing influxes that could lead to trouble and exceeding the limit that could push drilling fluids out of the well and into the formation. Well control refers to the hardware, procedures, and training associated with dealing with situations in which an influx has occurred and needs to be quickly stopped before it grows into a bigger problem, and then circulated out of the well. For companies seeking to win approval from the US Bureau of Safety and Environmental Enforcement (BSEE) to drill the first deepwater well in the US Gulf of Mexico using dual-gradient drilling, questions about well control are critical. Offshore regulators want to be sure that all the new equipment has been thoroughly tested because this is a new way to drill, and the BSEE wants to be sure that it is understood that when it comes to well control, the requirements are not changing. “With Dual-Gradient Drilling, the Name Requires Explanation” Dual-gradient drilling covers a variety of methods for managing pressure within an offshore well while drilling. Dual refers to systems built to reduce or eliminate the pressure added by drilling fluid in the riser. The goal is to create distinct pressure gradients above and below the mudline. It is a departure from the simpler traditional approach using a single fluid combining water or oil plus drilling mud to make it viscous enough to remove cuttings while drilling, and just heavy enough to control pressures in the open hole without causing damage. As drilling moved into deeper waters the gap has narrowed between the effective mud weight-per-gallon to offset the formation pressure, and the level that can fracture it. Drillers refer to this slim margin as working within tight drilling windows.

Black Sea Hydrate Formation Conditions of Methane Hydrogen Sulfide Mixtures

The objective of the study is to examine hydrate formation conditions of methane-hydrogen sulfide mixtures providing the Black Sea conditions. An experimental work is carried out by using a system that contains a high-pressure hydrate formation cell with different H2S concentrations and both brine and distilled water. Hydrate equilibrium conditions, the number of moles of free gas in the hydrate formation cell, and rate of hydrate formation are determined. Effects of H2S concentration on the hydrate formation conditions are also obtained during the study. It is observed that with an increase in H2S concentration, the methane hydrogen sulfide hydrate formation conditions reach higher equilibrium temperature values at a given pressure. According to the experimental results, it is concluded that the Black Sea has suitable conditions for hydrate formation of methane hydrogen sulfide mixtures.

A New Experimental Evaluation Technology for Foaming Agent in High Temperature and High Pressure Formation

Foaming deliquification is one of the most widely used technologies in the development of water production gas field. The key of this technology is the experimental optimization or develop the foaming agent suitable for gas field. With the development of a large number of high temperature and high pressure gas field, foam experimental evaluation methods used at present can not satisfy the temperature range of high temperature and high pressure evaluation requirements, in this case, used the Ross-Miles foam evaluation method as the foundation, built a new experimental evaluation method for foaming agent. Through an example, analyzes the influence of temperature and pressure on the foaming agent performance.

Influence of Engineering Pressure on Testing String Deformation

During well testing, liquid pressures exerted on testing string change frequently. Actions of downhole tools rely on annular or tubing pressure operation; information collection of the reservoir needs the production control valve switch on and off repeatedly. Pressure variability makes it very difficult to predict testing string safety both in deformation and strength. Although many measures have been taken to forecast pressure and component of the reservoir, exceptions often occur, and one exception is abnormal pressure. Considering technological process, axial deformation, helical buckling and strength of testing string are calculated with abnormal high and low formation pressure. Influence of other parameters is discussed, including string structure, completion fluid density, cushion and downhole tool operation pressures.

Mathematical model and numerical simulation of multiphase-flow in permeable rocks considering diverse deformation

Abstract Formation deformation of oil reservoirs is a widespread phenomenon for unconsolidated or abnormal high-pressure formations due to the depletion of reservoir pressure in the process of oil recovery. It may not only result in formation damage, but also have an adverse influence on production performance. In this paper, the deformation behavior of formation and formation damage are analyzed by elastic, elastic–plastic and plastic theory of solid porous media, and a set of expressions is derived to describe the change in porosity and permeability caused by linear or nonlinear deformation. Based on the comprehensive study on deformation of reservoir rock and multiphase flow in porous media, a new three dimensional and three phase-flow mathematical model that is used to predict the changes of porosity and permeability is presented, and the model is solved by the finite-difference method and self-adaptive iterative technique. A field-scale numerical simulator written in FORTRAN code is developed to predict the change trend of porosity and permeability in elastic and elastic–plastic deformation range. The runs of an oil field example with five-spot patterns are calculated on the simulator, and the formation damage and its influence on the pressure profiles in the vicinity around production well are studied under the condition of linear and nonlinear deformation of a reservoir. This work implies that the deformation of oil formation may be elastic, elastic–plastic or plastic in actual oil formation during the oil exploitation. The declines of porosity and permeability induced by the deformation are completely recoverable only for elastic deformation. Furthermore, elastic–plastic and plastic deformation may occur in the vicinity of production wells in unconsolidated formations. It is found that the increase of deformation coefficients presented in this work results in a sharp pressure-drop funnels on the vertical cross profile, which can be interpreted by the permeability decline induced by rock deformation.

Failure of Solid Oxide Fuel Cells by Electrochemically Induced Pressure

It is well known that many electrochemical devices such as fuel cells, electrolyzers, batteries, etc. degrade under various operating conditions. Many devices are based on solid electrolytes. In many cases, degradation manifests as electrode delamination and/or cracking of the electrolyte. An apparently obvious conclusion often reached is that this must be due to weak interfaces and some approach to mechanical strengthening or toughening should alleviate the problem. It is the intent of this manuscript to show that such electrochemical degradation often occurs due to electrochemical-mechanical coupling effects which result in extremely large internal pressures. So large can be the pressures that no amount conventional strengthening or toughening can prevent degradation. In fact, even a perfect lattice can be disrupted by electrochemically induced pressure leading to failures. In order to prevent failures, it is necessary to fully understand the role of coupling and develop strategies of mitigating high pressure formation by optimizing ion and electron transporting properties of the membrane. This manuscript discusses a fundamental mechanism of electrochemical failure of solid oxide fuel cells, solid oxide electrolyzer cells, and oxygen separators based on oxygen ion conducting solid electrolytes. Experimental results on two types solid electrolyte cells are presented in support of the mechanism.

Fabrication of Entangled Tough Titanium Wires Materials and Influence on Three-Dimensional Structure and Properties

Pure titanium (Ti) TA1 fibers/wires with 0.08 and 0.15 mm diameters were processed by a novel method that combined press forming, vacuum sintering (≥10−2 Pa), and heat treatment to fabricate entangled Ti wire materials (ETWMs). The ETWMs exhibited a total porosity ranging from 44.2 ± 0.1 to 81.2 ± 0.1% and an open porosity ranging from 43.5 ± 0.1 to 80.9 ± 0.1%. The processing parameters of fiber diameter, formation pressure, sintering temperature, and sintering time were applied to examine porous ETWM morphology, porosity, pore size, and mechanical properties. The importance of primary factors controlling porous structure and porosity in ETWMs were found to be fiber/wire diameter > formation pressure > sintering temperature > sintering time. Furthermore, Ti fiber diameter was shown to directly impact pore size. High formation pressure resulted in a fine, uniform porous structure with low porosity. Sintering at high temperature for long-time periods promoted sintering point formation, resulting in neck coarsening. This effect contributed to the characteristic mechanical properties observed in these ETWMs. If the sintering effect is considered in isolation, ETWMs fabricated with 0.08 mm diameter Ti fibers/wires and sintered at 1300 °C for 90 min achieved smaller, more uniform porous structures that further exhibited improved connections among fibers/wires and excellent mechanical properties.

High-pressure formation and stabilization of binary iridium hydrides

A new class of binary iridium hydrides (IrxHy) is investigated in the 1 atm to 125 GPa pressure range at the ab initio level, using DFT. Upon compression a number of hydrides are predicted to stabilize in the excess hydrogen environment. Static stabilization pressure is calculated to be ∼14 and ∼5 GPa at which a dihydride (Ibam, Z = 2) and a trihydride (P63mc, Z = 2) stabilize thermodynamically, respectively. In both the di- and the trihydride iridium and hydrogen atoms form short contacts in the range typical for covalent interactions. All of the reported hydrides exhibit metallic character with the notable exception of IrH3 (P63mc, Z = 2) which exhibits a non-zero band gap and a molecular character at intermediate pressures.

The Effect of Weight Material Type on Barite Sag Tendency

Settling of weight materials is a phenomenon that occurs in high-pressure formations where a high mud weight is needed. Barite sag is roughly defined as the change in density due the settling of weight materials that observed when circulating bottoms up following operations such as tripping pipe where the mud has not been circulating for an extended period of time. This may lead to problems such as lost circulation, well control difficulties, poor cement jobs, and stuck pipe in oil industry. In deviated wells, the settling distance to the lower side of the wall is small in comparison to vertical wells. This leads to rapid generation of solids beds and consequently, sag problems are particularly severe in deviated wells. The authors present the settling rate of different weight materials in muds with mathematical method. Furthermore, it investigates the effect of weight material type and hindered settling factor on settling rate. Moreover, the type of weight materials for barite sag management is recommended.

Drilling and Completing Cascade and Chinook Wells: A Case History

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24179, ’Drilling and Completing Cascade and Chinook Wells: A Design and Execution Case History,’ by Flavio Dias De Moraes, Petrobras; Oswaldo Moreira, Petrobras America; Ziad Haddad, FOI Technologies; Scott Ogier and Jonathan Shipley, SPE, Cherokee Offshore Engineering; Mauricio Rebelo, Petrobras; and Fernando Gama, Petrobras America, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. During the design, implementation, and operation of the Cascade and Chinook (C&amp;C) field development project in ultradeep water in the Lower Tertiary play of the Gulf of Mexico (GOM), the technical limits of single-trip multizone (STMZ) frac-pack systems were pushed to depths greater than 27,000 ft using high fracture rates and high-strength proppants; knowledge was gained from ultrahigh-pressure (greater than 20,000 psi) tubing-conveyed perforating systems; and well-design criteria suitable for high-drawdown (more than 12,000 psi) production operations were demonstrated. Introduction The C&amp;C development plan in the GOM is one of the most technologically challenging and complex projects ever implemented by Petrobras. This project uses the first floating production, storage, and offloading vessel in operation in US waters at a water depth of 8,200 ft. The C&amp;C subsea infrastructure considers the use of subsea manifolds, rigid flowlines, pipe-in-pipe pipelines, and freestanding hybrid risers. These two fields are 15 miles apart and share several characteristics such as depth, lithology, and reservoir similarities. The Wilcox 1 (Eocene) and 2 (Paleocene) sands belong to the Lower Tertiary geologic period and are part of the latest exploratory frontier in the GOM. At least 12 discoveries have been made in the Lower Tertiary, holding a potentially recoverable volume of several billion bbl of oil, highlighting the importance of this technology development for the industry. These reservoirs are characterized by a considerable thickness of intercalated sandstones and shales. The reservoirs show low horizontal permeability (less than 100 md) and poor vertical communication between sand layers. Other characteristics include a very high static formation pressure, a maximum temperature of 256°F, and a low gas/oil ratio. The produced oil has carbon dioxide concentration in the gaseous phase of less than 1.5%, and there is no evidence of hydrogen sulfide contamination. Drilling Design The casing design was based on delivering an 8½-in.-internal-diameter casing at total depth (TD) to accommodate the completion design. In this design, each string is run to its approximate design limit to maximize leakoff-test (LOT) values. One of the most important strategies of the C&amp;C wells was the elimination of the 11⅞-in. liner, which prevents achieving adequate circulation rates for a successful primary cement job on the 10⅛-in. production casing.