BP (Spain)

Abstract The impact of the transition metals iron, chromium, nickel, titanium and copper on solar‐cell performance is investigated. Each impurity is intentionally added to the silicon feedstock used to grow p‐type, directionally solidified, multicrystalline silicon ingots. A state‐of‐the‐art screen‐print solar‐cell process is applied to this material. Impurities like iron, chromium and titanium cause a reduction in the diffusion length. Nickel does not reduce the diffusion length significantly, but strongly affects the emitter recombination, reducing the solar‐cell performance significantly. Copper has the peculiarity of impacting both base‐bulk recombination as well as emitter recombination. Two models based on the Scheil distribution of impurities are derived to fit the degradation along the ingot. Solar‐cell performances are modelled as a function of base‐bulk recombination and emitter‐bulk recombination. The model fits the experimental data very well and is also successfully validated. Unexpectedly, the distribution of impurities along the ingot, due to segregation phenomena (Scheil distribution), leaves its finger‐print even at the end of the solar‐cell process. A measure of impurity impact is defined as the level of impurity that causes a degradation in cell performance of less than 2% up to 90% of the ingot height. The advantage of this impurity‐impact metric is that it comprises the different impurities’ physical characters in one single parameter, which is easy to compare.

ABSTRACT Hole problems during the drilling phase of operations are often the consequence of mechanical wellbore instability. This leads to higher than necessary drilling costs. A number of analytical and numerical models are available for the diagnosis and prediction of wellbore instability; this paper reviews the merits and pitfalls of applying these models to field situations. Attention is focused on the peak-strength criterion and constitutive behaviour model. Anomalies from the incorporation of the intermediate principal stress into peak-strength criteria are highlighted. To illustrate the reliability of a number of models, their predictions are compared with laboratory results, and with a case history of a horizontal well drilled in the Cyrus Field in the North Sea.

In this paper we discuss some branch and bound methods implemented in the UMPIRE mathematical programming system for solving practical integer programming problems and give details of computational experience with these methods. We have found that the nontrivial integer programming problems we encounter tend to fall into two classes. The first class of problems is characterized by a relatively small number (less than 100) of binary integer variables embedded in a very large and difficult linear program, with a few thousand constraints and complex matrix structure. The second class of problems tends to have many more integer variables (perhaps several hundred), frequently organized into special ordered sets and expressing complex logical relationships, but embedded in a much simpler linear program with 500–1,000 constraints. Problems in the first group in particular do not generally behave well using a simple-minded “penalty” approach for reasons we will make clear and a number of heuristic estimation procedures are used to guide the branch and bound search. The most important devices used are “priorities,” the “best projection criterion” and “pseudo-costs.” Some or all of these heuristics can also be very useful in tackling the second group of problems, where it is important to reach a good solution quickly to limit the search.

ABSTRACT Hole problems during the drilling phase of operations are often the consequence of mechanical wellbore instability. This leads to higher than necessary drilling costs. A linear-elastic analysis is frequently proposed for the prediction of the onset of failure, and consequently the mud weights required to prevent hole instability. However, there is no clear choice of which compressive failure criterion to use in the analysis. This paper assesses the influence of two commonly proposed failure criteria on mud weight selection. The failure criteria selected is shown to have an extremely significant effect on the computed 'safe’ mud weights. Examples related to field situations are presented which highlight the anomalies and contrary evidence relating to the suitability of failure criteria.

ABSTRACT The presence of wax in crude oil can lead to the formation of wax deposits on the walls of pipelines and as a consequence significant increases in pumping pressure caused mainly by an increase in the pipewall roughness. This can be particularly pronounced with the high cooling rates typical of submarine pipelines and is not restricted just to very waxy crudes. Using an extension of standard molecular diffusion theory the parameters influencing wax deposition rates are identified, and from simple laboratory tests on stabilized crude the rate of deposition in full scale pipelines can be predicted. Further, these principles and test methods can be applied to evaluate the effectiveness of the many available deposit-inhibiting additives under conditions appropriate to pipeline operations.

ABSTRACT In this paper we present four methods of estimating the effective vertical permeability of a reservoir containing stochastic shales in both two and three dimensions. The methods vary in their accuracy, speed and range of applicability. The first is based on numerical simulation, the second is an analytical method, the third and fourth are based on calculating approximate streamline lengths. The methods give consistent results for similar models and are used to show that the effective vertical permeability is strongly dependent on the shale dimensions, shale fraction and layer thickness. It is also shown that the results of the two-dimensional models are inappropriate even when the megascopic flow is unidirectional.

Summary. Although complex categorizations are in vogue, "heavy oils" can be defined simply in terms of their flow properties in the reservoir e.g., a 100-cp [100-mPas] or greater viscosity. Such heavy oils are a major world hydrocarbon resource that is exploited where indigenous demand exists. Efficient methods of production require enthalpy input to the reservoir by hot-fluid injection or by creation of heat in the reservoir. Heat losses must be minimized to achieve maximum production efficiency. The widely used cyclic-steam-injection process is examined analytically to indicate which parameters govern successful exploitation. Steamflood and in-situ combustion techniques are discussed with reference to recent developments. Heavy-oil recovery from the more difficult carbonate reservoirs, such as those of the Middle East, is reviewed and potential production mechanisms are examined. Production techniques are described together with export handling schemes. Introduction Heavy-oil recovery is traditionally thought of as thermal stimulation of low-API-gravity oil, which may range from 4 to 20 degrees API [1.04 to 0.93 g/cm3]. Heavy oil is defined as having an API gravity of less than 20 degrees API [greater than 0.93 g/cm3]. Standard practice in the U.S. also uses this gravity definition. The API gravity, however, does not fully describe the flow properties of the crude; this is better represented by the oil viscosity. For instance, some crudes may be heavy (low gravity) but have a relatively low viscosity at reservoir temperature compared with some lighter crudes (Table 1). The oil viscosity and its response to increased temperature control the flow rate under thermal stimulation, and because the flow rate is a much more important factor in the economic exploitation of the reserve than the oil gravity, it is proposed that heavy oilsi.e., those requiring stimulation by heat or by other meansbe defined as crudes having viscosities greater than 100 cp [greater than 100 mPas] at reservoir conditions. Normally, pumped cold-oil production rates will be less than 10 B/D [1.6 m3/d] when the oil viscosity exceeds 100 cp [100 mPas]. The term "bitumen" is used interchangeably with heavy oil although its use does tend to signify the heavier end of the heavy-oil spectrum. The United Nations Inst. for Training and Research proposes that bitumen be defined as having a viscosity greater than 10(4) cp [greater than 10(4) mPas] and an API gravity less than 10 degrees [less than 1 g/cm3]. Another definition of bitumen is a naturally occurring viscous mixture consisting mainly of hydrocarbons heavier than pentane that may contain sulfur compounds and that, in its naturally occurring viscous state, is not recoverable at an economical rate through a well. The term "tar sand" is often applied to such deposits found in the Canadian Athabasca sands, which are shallower and accessible by mining. Heavy oil in this paper refers only to those deposits that have to be exploited in situ and that will normally be located at depths ranging between 1,000 and 4,000 ft [300 and 1200 m]. In common with tar-sand oil, heavy oils frequently have high asphaltene, sulfur, and metal contents compared with conventional oils. The nonhydrocarbon content tends to increase with decreasing API gravity, which, in combination with decreasing quantities of lighter ends, reduces the market value of the crude. Table 2 compares typical heavy-oil properties with conventional oil. Main Locations of World Heavy Oil We have estimated the total discovered heavy oil in place in the world to be 4,600 × 10(9) bbl [730 × 10(9) m3]. This should be compared with our estimate of remaining proved and probable conventional oil reserves as of Jan. 1, 1986, of some 700 × 10(9) bbl [110 X 10(9) m3]. As can be seen, an average heavy-oil recovery factor of 15 % would be required to equate heavy-oil reserves with the remaining conventional reserves. The total world consumption of oil as of Jan. 1, 1986, was about 537 × 10(9) bbl [85 × 10(9)m3], which shows that the heavy-oil resources are important long-term supplies of petroleum. The main known heavy-oil deposits are summarized in Table 3. The largest heavy-oil deposits are located in Canada, Venezuela, and the Soviet Union and represent over 90% of the known heavy oil in place in the world. Of these deposits, sandstone reservoirs are estimated to contain 3,000 × 10(9) bbl [480 × 10(9) m3], with the remaining 1,600 × 10(9) bbl [250 × 10(9) m3] contained in carbonate reservoirs. Table 4 shows the distribution of the 1985 world production by thermal techniques, which averaged 923,000 B/D [147 × 10(3) m3/d]. In the past, economics have dictated that a high oil price is necessary before heavy-oil production becomes attractive on a large scale. In many areas of the world, however, conventional oil reservoirs are becoming increasingly marginal as the giant fields remaining to be discovered become fewer and the exploration risks for offshore fields and their development costs become large. There are risks associated with developing offshore fields because very few early appraisal data can be collected and no long-term well performance observations are possible. In most cases, pressure maintenance will be required from the outset and has to be based on theoretical estimates and not pilot results. Thus, these conventional oil prospects require front-end capital, the majority of which is at risk should the project fail. In addition, the uncertainty of future oil prices and the currently perceived low-price scenarios reduce the estimate of potential reward. In contrast, large quantities of heavy oil have already been discovered; therefore, no exploration cost is required. In addition, these discoveries awaiting development are mainly onshore and are at shallow depth. Development wells are low cost and the capital expenditure (capex) profile is continuous throughout the project, rather than being front-end loaded. Such thermal processes as cyclic steam injection are well understood, and the technical and geologic risks are therefore small. These advantages, even though the heavy-oil price will be discounted, allow potential heavy-oil production to compare favorably with many high-risk conventional oil plays. Typical predicted cash-flow profiles for a marginal North Sea development and a heavy-oil development are compared in Fig. 1. Table 5 summarizes the resource and development economics of the two fields. Carbonate reservoirs also contain large quantities of heavy oil, but the technology and experience of producing such heavy-oil reservoirs are not well developed. Nevertheless, they are important development targets. The potential production mechanisms that may take place during the thermal stimulation of these reservoirs are discussed later. JPT P. 206^

Research Article| May 01, 1965 Section Through the Eastern Cordillera of Colombia, South America C. J CAMPBELL; C. J CAMPBELL British Petroleum Co., Ltd., London, England Search for other works by this author on: GSW Google Scholar H BÜRGL H BÜRGL Faculty of Geology, National University, Bogotá, Colombia Search for other works by this author on: GSW Google Scholar Author and Article Information C. J CAMPBELL British Petroleum Co., Ltd., London, England H BÜRGL Faculty of Geology, National University, Bogotá, Colombia Publisher: Geological Society of America Received: 19 Dec 1963 First Online: 02 Mar 2017 Online ISSN: 1943-2674 Print ISSN: 0016-7606 Copyright © 1965, The Geological Society of America, Inc. Copyright is not claimed on any material prepared by U.S. government employees within the scope of their employment. GSA Bulletin (1965) 76 (5): 567–590. https://doi.org/10.1130/0016-7606(1965)76[567:STTECO]2.0.CO;2 Article history Received: 19 Dec 1963 First Online: 02 Mar 2017 Cite View This Citation Add to Citation Manager Share Icon Share Facebook Twitter LinkedIn Email Permissions Search Site Citation C. J CAMPBELL, H BÜRGL; Section Through the Eastern Cordillera of Colombia, South America. GSA Bulletin 1965;; 76 (5): 567–590. doi: https://doi.org/10.1130/0016-7606(1965)76[567:STTECO]2.0.CO;2 Download citation file: Ris (Zotero) Refmanager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex toolbar search Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentBy SocietyGSA Bulletin Search Advanced Search Abstract The Eastern Cordillera of Colombia is a branch of the Andes. It is composed of rocks ranging in age from Lower Paleozoic to Recent. Lower Paleozoic phyllites are overlain by unmetamorphosed Devonian to Jurassic sediments. A geosyncline formed in late Jurassic times and continued to influence sedimentation until the close of the Cretaceous. A great thickness of marine sandstone, limestone, and shale was deposited in the geosyncline, which was affected by periodic transgressions and regressions of the sea and minor diastrophic movements. The final retreat of the sea at the end of the Cretaceous period led to the development of a nonmarine environment in which the Tertiary sediments were deposited.The structure of the Eastern Cordillera results primarily from orogenic movements in late Miocene times, although there were some earlier periods of diastrophism. The central parts of the chain are characterized by generally simple folding and subsidiary faulting. The margins, which are more strongly deformed, are cut by important thrusts that dip toward the center of the chain. Some of them have very large displacements.The Eastern Cordillera was strongly uplifted in Pleistocene times with the result that the base of the Tertiary is now as much as 8000 m higher in the Cordillera than in the adjoining basins.The chain is symmetrical and comparatively simple. It may be explained in terms of primarily vertical movements of the earth's crust. First Page Preview Close Modal You do not have access to this content, please speak to your institutional administrator if you feel you should have access.

Abstract We use two coupled climate models, GFDL‐CM4 and GFDL‐ESM4, to investigate the physical response of the Southern Ocean to changes in surface wind stress, Antarctic meltwater, and the combined forcing of the two in a pre‐industrial control simulation. The meltwater cools the ocean surface in all regions except the Weddell Sea, where the wind stress warms the near‐surface layer. The limited sensitivity of the Weddell Sea surface layer to the meltwater is due to the spatial distribution of the meltwater fluxes, regional bathymetry, and large‐scale circulation patterns. The meltwater forcing dominates the Antarctic shelf response and the models yield strikingly different responses along West Antarctica. The disagreement is attributable to the mean‐state representation and meltwater‐driven acceleration of the Antarctic Slope Current (ASC). In CM4, the meltwater is efficiently trapped on the shelf by a well resolved, strong, and accelerating ASC which isolates the West Antarctic shelf from warm offshore waters, leading to strong subsurface cooling. In ESM4, a weaker and diffuse ASC allows more meltwater to escape to the open ocean, the West Antarctic shelf does not become isolated, and instead strong subsurface warming occurs. The CM4 results suggest a possible negative feedback mechanism that acts to limit future melting, while the ESM4 results suggest a possible positive feedback mechanism that acts to accelerate melt. Our results demonstrate the strong influence the ASC has on governing changes along the shelf, highlighting the importance of coupling interactive ice sheet models to ocean models that can resolve these dynamical processes.

Abstract Kuwait's production to date is characterized by large, massive reservoirs undergoing natural depletion with the help of strong natural aquifer drives. In a few fields, natural aquifer support is supplemented by pattern or peripheral waterflood. However, there has been no systematic attempt to define the Improved Oil Recovery (IOR) potential within the country. This study is a first attempt to assess this potential. The study considered 10 IOR displacement processes, suitable for long-term implementation within Kuwait. These processes included waterflood (including chemical floods), gas injection processes, and thermal methods. The study did not consider techniques based purely on well stimulation or infill drilling (e.g. cyclic steam injection, or horizontal well development); the potential for these techniques is already well understood and considerable data already exists for planning around these options. The study focused on screening reservoirs and identifying IOR processes for further study. The screening was in two parts. The first part was an evaluation of process suitability for all reservoirs. The second part was a ranking of IOR opportunities by reservoir. In total, over 800 process/reservoir combinations were evaluated. The evaluation process made use of various industry criteria; however, these were modified to better reflect conditions within Kuwait. After screening for suitability, the reservoirs were ranked in importance for future study. This ranking included: incremental oil recovery, crude quality cost per barrel and urgency (timing). This ranking will be used to direct resources at particular projects for further study and, if positive, future implementation. Key technical contributions of this work include: data evaluation techniques, consistent ranking of reservoirs with varying degrees of risk, development of scoping economic models for preliminary project assessment.

One of the most conspicuous phenomena in the Arctic Is the fracture of sea ice. It is scarcely possible to travel far without seeing a variety of fracture forms, produced both by natural processes and by human activity. At strain-rates below about 10 −4 s −1 , deformation is dominated by creep, but at higher strain-rates fracture is much more important. One of the reasons for this is the very low fracture toughness of ice. The movements of ice in contact with offshore structures often induce strain-rates well beyond the level at which fracture begins, and so offshore structures will often operate in the fracture regime, and it is fracture processes which will determine the design loads. We consider the different modes of repeated fracture that will occur, and classify them into distinct mechanisms of crushing, spalling, and radial and circumferential cracking. Experimental and field observations are plotted on a deformation mode map. A theoretical treatment of radial cracking confirms that very low loads can propagate cracks to long distances; these loads are small by comparison with those calculated from theoretical models that treat ice as a plastically-deforming continuum.

Abstract The nature of pore morphology and surface chemistry are inherent in determining the recovery performance of reservoir rock through their influence on relative permeability. Assessment of pore morphology can be made directly by using imaging techniques, although recovery prediction based on this assessment is still difficult. The surface chemistry of the pore structure can determine the very important parameter, wettability. Determination of the most representative wetting state of the reservoir is essential to the laboratory core analyst, in order to establish representative relative permeability data. This paper discusses the application of surface science analytical techniques to the characterisation of the pore surfaces of reservoir material. Both inorganic and organic analyses have been performed on reservoir samples of known core properties. Techniques such as X-ray Photoelectron Spectroscopy (XPS), Secondary Ion Mass Spectrometry (SIMS) and Laser Induced Mass Analysis (LIMA) have been used. Particular emphasis has been paid to the correlations generated between wettability parameters and the organic content on the pore surfaces. The work demonstrates quite clearly that direct analysis analysis of the pore surfaces gives information pertaining to the wetting state. Further, chemical information is obtained which helps identify the functionality of organic species that leads to oil wetting character. The suggestion is made that the techniques outlined could be used to rapidly determine the wetting state of reservoir material. The surface analysis approach could also lead to a better understanding of how reservoir quality and wetting state can be modified, thus leading to improved predictive capabilities.

The stresses set up in a pipe being laid from a lay-barge over a stinger are determined by the configuration the pipe takes up. The equations governing this configuration are derived, and different techniques for solving them are examined. It is concluded that the finite-difference technique is the most attractive, and an example of its application is discussed in detail. The nondimensionalized form of the governing equation suggests a way of modeling the system physically and, at the same time, satisfying appropriate similarity conditions; the construction and use of such a model are described.

The Adria microplate has been thrust westward onto the Corsican microplate by a distance of at least 150 km. This crustal duplication followed the Late Cretaceous easterly directed subduction of the eastern Corsican continental margin after consumption of intervening Tethyan oceanic crust. The suture zone separating the two micro-plates is delineated by the ophiolite-bearing Schistes lustrés nappe, which suffered a Late Cretaceous HP-LT metamorphism. The Corsican blueschists crystallised during a major thrusting event at depths probably in excess of 35 km, and were overprinted by post-tectonic greenschist facies assemblages at 15-20 km during Late Eocene times. Eventual uplift and exposure of the Schistes lustrés and ophiolites were probably the result of isostatic compensation and erosion during and following their emplacement onto continental basement.

Abstract The horizontal and vertical motions of the surface of the ground on the arrival of reflected longitudinal and transverse waves from an elastic discontinuity are determined theoretically, with special reference to those parameters encountered in exploring for limestone structures in the foothills of western Canada by wide-angle reflection techniques. The results, which cover a wide range of possible overburden velocities, are expressed by means of curves from which the displacement for any practical elastic contrast, depth, and observation distance may be readily determined. Properties of these curves are examined empirically. The theory assumes plane waves in determining the amplitude ratios at the structural or free surface discontinuities and spherical waves in deriving spread factors. Corrections to the curves on account of a nonuniform overburden velocity are considered in the case of a typical central foothills well. The evidence for PP and PS in model, and to a less extent in field work and the significance of phase changes on reflection are discussed. It is concluded that the horizontal geophone should prove to be a useful additional tool in wide-angle reflection surveys in disturbed foothills zones. Here, it could confirm or refute the arrival of a reflection registered by the vertical geophones in the many cases where doubt exists.

Abstract An integrated approach to evaluating the causes of severe wellbore instability in the Cusiana field is described. The field is located in a tectonically active region of Colombia. Deterioration of the hole during drilling operations has led to excessive nonproductive time and expensive wells. The scale of the problem is unprecedented in the world. In wells costing tens of millions of dollars, millions per well could be attributed to poor hole conditions. This paper describes how the problem was addressed and what actions were taken to improve operational performance, resulting in reduced drilling costs. The improved understanding has contributed to better well planning, and improved drilling performance, and has underlined the need to consider all aspects of the drilling process to achieve improved hole conditions in a difficult geological setting.

Abstract The paper summarises many years' experience in applying laboratory procedures and heat transfer calculations to the prediction of the start up of flow in a gelled oil pipeline. The importance of simulating the full scale treatment in the laboratory testing is emphasised by reference to experience in full scale start up trials. Introduction The problems of handling waxy crude oils in pipelines are well-known to oilmen. Submarine pipelines are well-known to oilmen. Submarine lines carrying crude oil production to the shore present these problems more acutely than present these problems more acutely than landlines because:-The cooling rate of the crude oil is higher at all seasons of the year,Shutdowns are more frequent and may last longer than the 3-day limit which, except in remote areas, is normally assumed forland lines, andAccess to the line at intermediate points is practically impossible, unless special access points are provided when laying the line. Waxiness can cause two problems in crude oil production. One is the formation of deposits on production. One is the formation of deposits on the pipewall which increase the pressure drop in the pipeline. This occurs when the pipewall temperature is lower than the wax precipitation point (known as the cloud point for distillate point (known as the cloud point for distillate oils, but not so easily identified for crudes). Deposition will not be considered in this paper. The second problem is the possibility of gelation when the production is shut down, or when the line is pumping at a low rate. This can occur when the mean oil temperature is low enough to throw out of solution approximately two per cent or more of the crude was wax, which can form an interlocking gel structure. This paper describes how the likelihood of gelling is assessed, and how the pressure needed to start up the flow in a gelled line is calculated. PREDICTION OF GELATION PREDICTION OF GELATION A crude oil does not necessarily gel when it contains two per cent of solid wax. The gelling point depends on the size and the shape of the wax point depends on the size and the shape of the wax crystals and so any pretreatment which affects this size and shape also affects the gelling point. There are other complications: most crude oils contain resins which have a natural affinity for wax crystals. The resins act as natural gelling point depressants: when they collect around the wax point depressants: when they collect around the wax crystals they tend to prevent them from interlocking to form a gel. Thus, any pretreatment which prevents resins from collecting around the wax also raises the gelling point. To decide whether or not a particular crude oil, which is at the well-testing stage, is likely to gel in a submarine pipeline, it is therefore necessary to measure its gelling temperature after a pretreatment which simulates the normal production procedure. It may also be useful to production procedure. It may also be useful to measure the highest gelling temperature, ie the worst possible condition, in order to make sure that the pipeline could handle the crude should it attain this condition due to an unforeseen variation in the normal production procedure. If the highest gelling temperature is lower than 4 degrees C there should be no gelation of that crude in a North Sea pipeline. The gelling temperature is normally measured by the pour point test (IP 15, ASTA D97). This test is too well-known to need more than a cursory description here. The oil contained in a one inch diameter pour point tube is cooled in a carefully specified cooling bath. The tube is examined by cautiously tilting it at 3 degrees C intervals, to find the temperature at which the oil ceases to flow. P. 283

Wellbore Stability: The Effect of Strength Criteria on Mud Weight Recommendations M.R. McLean; M.R. McLean British Petroleum Search for other works by this author on: This Site Google Scholar M.A. Addis M.A. Addis British Petroleum Search for other works by this author on: This Site Google Scholar Paper presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, September 1990. Paper Number: SPE-20405-MS https://doi.org/10.2118/20405-MS Published: September 23 1990 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation McLean, M.R., and M.A. Addis. "Wellbore Stability: The Effect of Strength Criteria on Mud Weight Recommendations." Paper presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, September 1990. doi: https://doi.org/10.2118/20405-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE Annual Technical Conference and Exhibition Search Advanced Search AbstractHole problems during the drilling phase of operations are often the consequence of mechanical wellbore instability. This leads to higher than necessary drilling costs. A linear-elastic analysis is frequently proposed for the prediction of the onset of failure, and consequently the mud weights required to prevent hole instability. However, there is no clear choice of which compressive failure criterion to use in the analysis. This paper assesses the influence of two commonly proposed paper assesses the influence of two commonly proposed failure criteria on mud weight selection. The failure criteria selected is shown to have an extremely significant effect on the computed 'safe' mud weights. Examples related to field situations are presented which highlight the anomalies and contrary evidence relating to the suitability of failure criteria.IntroductionThe increasing demand for wellbore stability analyses during the planning stage of a field arises from economic considerations and the escalating use of deviated, extended reach and horizontal wells. Wellbore instability can result in lost circulation (Figure la) where tensile failure has occurred, and spalling and/or hole closure (Figure lb) in the case of compressive failure. In severe cases the hole instability can lead to stuck pipe and eventually loss of the open hole section. The causes of instability are often classified into either chemical or mechanical effects. Often, field instances of instability are a result of a combination of both chemical and mechanical effects. However, only mechanical effects are considered here.Due to the large costs associated with wellbore instability this subject has received considerable attention in the literature over the past two decades ([l] to [161). The majority of the literature focuses on analytical aspects of wellbore stability. In a previous publication [151 the authors reviewed strength criteria used in many of the models published and showed that certain criteria do not stand up to close scrutiny when compared with laboratory strength test data. In this paper the effect of strength criteria on mud weight selection is highlighted to show some of the anomalies and contrary evidence which can make the choice of a strength criterion difficult and confusing when performing wellbore stability analyses.2.0 BACKGROUND TO WELLBORE STABILITY MODELLINGBefore a well is drilled, compressive stresses exist within the rock formations (Figure 2). With the exception of structurally complex areas (e.g. near salt diapirs), the in-situ stresses can be resolved into a vertical or overburden stress, , and two horizontal stresses, (the maximum horizontal stress), and (the minimum horizontal stress), which are generally unequal. When the well is drilled, the rock stresses in the vicinity of the wellbore are redistributed as the support originally offered by the drilled out rock is replaced by the hydraulic pressure of the mud. pressure of the mud. P. 9 Keywords: instability, strength, failure criterion, society of petroleum engineers, linear-elastic analysis, wellbore stability, drucker-prager option, failure criteria, wellbore design, overbalance Subjects: Wellbore Design, Drilling Operations, Reservoir Characterization, Wellbore integrity This content is only available via PDF. 1990. Society of Petroleum Engineers You can access this article if you purchase or spend a download.

Late Miocene sedimentary records in the Gibraltar arch region hold fundamental information on the Atlantic-Mediterranean connectivity before, during and after the Messinian Salinity Crisis (MSC; 5.96-5.33 Ma). In this work we tackle this still unresolved problem through a detailed foraminifer-based biostratigraphy, micropaleontological and geochemical analyses of four available records (ODP 976B and DSDP 121) and boreholes (Andalucia-G1 and Alboran A1) in the West Alboran Basin (WAB). The combined use of these different analytical techniques together with new seismic stratigraphy enabled us to create a new and revised Upper Tortonian-Lower Pliocene Alboran Sea chronostratigraphic framework and estimate the magnitude of the Zanclean erosion. At Site 976, the dominance of a peculiar cold planktonic foraminifer fauna in the late Tortonian-early Messinian could possibly imply the existence of a proto-Gibraltar Strait, while at ~7.2 Ma, changes towards warmer foraminifer assemblages, increasingly stratified water column and sharp increase in terrestrial input indicate the beginning of the restriction of the Mediterranean from the Atlantic Ocean. Cyclical changes visible both in the elemental composition and foraminifer assemblages from here onward highlight a strong precessional cyclicity, which can be correlated to the first signs of reduced ventilation and sapropel deposition in the Eastern Mediterranean. The integration of seismic profiles and core analyses finally revealed that the Messinian expression in the Alboran basin is limited to two units: one hemipelagic and one chaotic, most probably connected to the MSC final stages. The Messinian succession in the Alboran basin is topped by an unconformity, most likely related with the Zanclean reflooding, which eroded a sedimentary succession of ~1.67 Ma. An extremely rare phosphate (canaphite) and Mg rich minerals were recognized described and associated to interstitial fluids and diagenetic processes.

OBJECTIVE: Patients' psychological reactions to multigene cancer panel testing might differ compared with the single-gene testing reactions because of the complexity and uncertainty associated with the different possible results. Understanding patients' preferences and psychological impact of multigene panel testing is important to adapt the genetic counselling model. METHODS: One hundred eighty-seven unrelated patients with clinical suspicion of hereditary cancer undergoing a 25-gene panel test completed questionnaires after pretest genetic counselling and at 1 week, 3 months, and 12 months after results to elicit their preferences regarding results disclosure and to measure their cancer worry and testing-specific distress and uncertainty. RESULTS: A pathogenic variant was identified in 38 patients (34 high penetrance and 4 moderate penetrance variants), and 54 patients had at least one variant of uncertain significance. Overall, cancer panel testing was not associated with an increase in cancer worry after results disclosure (P value = .87). Twelve months after results, carriers of a moderate penetrance variant had higher distress and uncertainty scores compared with carriers of high penetrance variants. Cancer worry prior to genetic testing predicted genetic testing specific distress after results, especially at long term (P value <.001). Most of the patients reported the wish to know all genetic results. CONCLUSIONS: Our results suggest that patients can psychologically cope with cancer panel testing, but distress and uncertainty observed in carriers of moderate penetrance cancer variants in this cohort warrant further research.