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Collaborating Authors
cement
Abstract Wells in the northeastern United States are generally drilled to a depth of from 3,000 to 6,000 ft. They are usually air drilled through several incompetent formations among which are the Marcellus and Coffee shales. Completions in this area are hampered by very low fracture gradients of 0.4 to 0.6 psi/ft, with most of the formations containing a large number of natural fractures. During cementing, pressures in excess of 1,100-psi hydrostatic can result in breakdown of the formation leading to incomplete fill-up on the cement job. This paper will discuss the existing completion practices in this area, which include the use practices in this area, which include the use of multistage cementing, and the incorporation of cementing baskets and other downhole tools. The current cement systems in use and the problems encountered in using them will also be discussed. Several case histories of new cementing techniques, using ultralight weight foam-cementing systems, will be presented along with the job design used on these wells. Bond logging of the foam-cemented wells creates an array of special problems for the logging companies, due to the ultra-low densities and the high porosities of these special cementing systems. Newly developed techniques for logging these wells will be discussed, along with the bond logs from the case histories. Introduction Many wells in the northeastern United States are air drilled through several incompetent formations. Fracture gradients can run as low as 0.4 psi/ft. Many operators have been very successful in cementing these wells using stage cementing practices. This paper will address the areas where, despite stage cementing, cement fill-up cannot be achieved. Discussion will center around the problems associated with the existing cementing practices, as well as the alternatives to these. Case histories of wells completed using ultralight weight foamed cement are presented along with the cement bond logs from these wells. A brief discussion of methods to properly evaluate these logs is also included. EXISTING PRACTICES Cement job design in these wells has generally been centered around combating the very low fracture gradients, while attempting to obtain the maximum cement fill-up possible. Wells are classically cemented using stage collars in conjunction with from three to seven cementing baskets. Often, the operator is faced with either doing several remedial squeeze jobs in an attempt to cover the entire zone, or only covering the zone of interest while leaving the remainder of the hole uncemented, which can lead to excessive corrosion of the casing. Cement system designs used on these wells normally use thixotropic cement systems with large quantities of lost-circulation materials. Either the bottom and top stages are cemented using this system, or the bottom stage incorporates this system, while the top stage is cemented using an extended cement system such as 50:50 blend of cement and pozzolan. This type of approach can cause an array of problems. While all stage collars are designed and manufactured to operate properly, all too often they do not. Costly rig time is also lost while waiting for the bottom stage of cement to obtain sufficient compressive strength to continue the operation. The stage tool must be subsequently drilled out before continuing with the stimulation treatments, again resulting in additional lost time. Another problem is that when the tool is opened, the displacement fluid used during the first stage can wet previously dry formations which can result in excessive formation damage in the producing zones, or the breakdown of weak zones. p. 193
- North America > United States > West Virginia > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.94)
- North America > United States > Virginia > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.94)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.94)
- (3 more...)
- Well Drilling > Casing and Cementing > Cement formulation (chemistry, properties) (1.00)
- Well Drilling > Casing and Cementing > Cement and bond evaluation (1.00)
- Management > Professionalism, Training, and Education > Communities of practice (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Knowledge management (1.00)
Summary A novel sand-consolidation technique especially suited for the prevention of sand influx in gas wells is described. This technique-"Silicalock"-has the advantage of being a single-chemical one-phase dynamic treatment that can be carried out through tubing and that leads to reduced chances of productivity impairment. The results of three successful field tests also are described. Introduction The importance of natural gas as an essential and clean source of energy has increased considerably in recent years. Much of this gas is produced from loosely consolidated sandstone reservoir that require some form of sand control. Experience in both field and laboratory has shown that the probability of sand influx increases as a reservoir is depleted and pore pressure decreases. Production facilities may be, designed to cope safely with the production of small amounts of sand. However, sand production over a long time is generally not acceptable since it often leads to serious erosion problems. Furthermore, some of the produced sand will normally remain in the wellbore, which may result in a sand fill that adversely affects the well's productivity. The standard forms of sand control, primarily developed for oil wells, also may be applied to gas wells. These include(1) beaning back production, (2) mechanical methods such as wire-wrapped screens with and without gravel packs, and (3) consolidation processes in which the sand grains are "glued" together. However, none of these methods makes allowance for the special conditions found in gas wells, and they are therefore not optimal. The Shell group of companies has been exploiting several large gas fields during the past decade, including the giant Groningen field [operated by the Nederlandse Aardolie Mij. (NAM)] where about 280 wells can produce up to 480 × 10 std m /d during peak winter production periods. A view to possible future sand problems justified the star, of development of a sand control process especially geared to the conditions prevailing in gas wells. This has resulted in the novel chemical technique "silicalock" described in this paper. The process is based on the following reaction. SiCl4 + - 2H20- silica cement +4 HCl. The water is supplied by the connate water naturally adhering to the sand grains. The process differs from previous sand consolidation processes involving silicon tetrachloride in that it operates from the gas phase. The "silicalock" technique consists in vaporizing liquid silicon tetrachloride into a stream of high-pressure nitrogen gas. The mixture is injected into the well, preferably through coiled tubing. Immobile water present in the near-wellbore region is converted into silica cement, which cements the grains together, thus preventing any (further) influx of sand into the well. JPT P. 2087^
- North America > United States (0.47)
- Europe > Norway (0.46)
- Europe > Netherlands > Groningen Province (0.35)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Geology > Geological Subdiscipline > Geomechanics (0.49)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > PL 024 > Block 25/1 > NOAKA Project > Frigg Field > Frigg Formation (0.99)
- Europe > Netherlands > Groningen > Southern North Sea - Anglo Dutch Basin > Groningen License > Groningen Field > Upper Rotliegend Formation (0.99)
- Europe > Netherlands > Groningen > Southern North Sea - Anglo Dutch Basin > Groningen License > Groningen Field > Limburg Formation (0.99)
Abstract A natural gamma ray spectroscopy logging system has been designed which incorporates active compensation for differences in borehole conditions into the least squares calculation of the K-U-TH elemental concentrations. A low atomic number tool case allows gamma rays in the photo-electric energy region to be detected, while a coincidence photo-electric energy region to be detected, while a coincidence gain stabilization technique distinguishes formation gammas from those originating in the stabilizer source. These features permit additional measurements of formation lithology in open permit additional measurements of formation lithology in open holes and mean casing thickness in cased wells. Introduction For almost fifty years natural gamma ray logs have been an important constituent in the evaluation of downhole reservoirs, The naturally radioactive elements potassium (K), uranium (U), and thorium (Th) are the sources of the gamma rays counted in gamma logging, but until the last fifteen years nocommercial service attempted to isolate the individual contributions from each element. Potassium, thorium, and uranium(and Th and U daughters) have different depositional properties, exhibit different solubility characteristics, and respond properties, exhibit different solubility characteristics, and respond differently to diagenetic processes. Therefore, valuable Geological and petrophysical parameters, and important information for assisting in well log analysis and reservoir production can be obtained from both absolute and relative K. U. and Thconcentrations. Existing natural gamma ray spectroscopy systems, have proven useful in providing these K-U-TH data. This paper describes a new Compensated Spectral Natural Gamma system which expands on the basic K-U-TH measurement concepts of the existing systems. CSNG*information is processed over a very wide energy range from= 20 KeV up to = 3 MeV. In addition to providing K-U-TH data. the shape of the composite spectrum is used to provide information on borehole conditions. Since both the shape and magnitude of K-U-TH spectra are affected by borehole changes, both absolute and relative K-U-TH concentration calculations are much improved when borehole effects a reproperly modelled and input into the program which properly modelled and input into the program which calculates the elemental concentrations. In addition to improved K-U-TH concentrations, the CSNG tool uses the scattered low energy gamma rays from the formation to provide information on photoelectric absorption. Based on initial Monte Carlo calculations and subsequent tool measurements, photoelectric absorption in anuncased well can be observed and used to identify formation lithology, using similar physical principles to those employee in recent lithology/density lodging devices. In a cased well photoelectric absorption in iron masks the formation lithology photoelectric absorption in iron masks the formation lithology signal, but in itself is useful for determining the mean thickness of the casing, which is indicative of wear and external or internal corrosion. The physical tool hardware also incorporates several improved features relative to existing equipment. A very accurate new coincidence counting stabilizer automatically adjusts the downhole system for any gain changes experience ouring tool warmup or operation. The spectra are digitized and accumulated downhole and are transmitted to the surface The spectra can be recorded on magnetic tape and visually output on the log, as well as being used in the software for the K-U-Th. lithology, and casing thickness determinations The toolcase over the detector is composed Of a low atomic number (and low density) material, which both facilitates the photoelectric absorption measurements and improves the count rates in the detector in the higher energy K-U-Th spectral region in very high temperature and pressure applications, a titanium toolcase version of the CSNG pressure applications, a titanium toolcase version of the CSNG tool is also available. COMPENSATED SPECTRAL NATURAL GAMMA SYSTEM DESCRIPTION For most logging situations.
Abstract Fracturing and completing deep wells in hot, non-porous crystalline basement rock challenges conventional equipment use, procedures, and techniques common in oil and gas and normal geothermal completions. Fracturing operations at the Fenton Hill, New Mexico, Hot Dry Rock (HDR) Geothermal Test Site initiated unique developments necessary to solve problems caused by an extremely harsh downhole problems caused by an extremely harsh downhole environment. Two deep wells were drilled to approximately 15,000 ft (4.6 km); formation temperatures are in excess of 600F (315C). The wells were drilled during 1979–1981, inclined at 35 degrees, one above the other, and directionally drilled in an azimuthal direction orthogonal to the least principal in-situ crustal stress field. The pair of wells form the injection and production wells of an energy extraction system which will be unique in reservoir development. The test site is located near the flank of a young silicic composite volcano, the Valles Caldera, in the Jemez Mountains of northern New Mexico. The deeper well was planned as the cold water injection hole; as such, it may be cooled from the static, conduction geothermal gradient to as low as 80F (25C). The upper, production well will be heated to over 500F (260C) along its entire length. The well pair has been designed to be a closed loop, pair has been designed to be a closed loop, heat-extraction system formed with hydraulic fracture connections between the 1200 ft (370 m) vertically-spaced wells. These production conditions, and the in-situ formation temperatures, strongly constrain all completion hardware, cementing formulations and procedures, and fracturing operations. procedures, and fracturing operations. Hydraulic fracturing experiments to connect the two wells have used openhole packers, hydraulic jet notching of the borehole wall, cemented-in isolation liners and casing packers. Problems were encountered with hole drag, high fracture gradients, H2S in vent back fluids, stress corrosion cracking of tubulars, and the complex nature of three-dimensional fracture growth that requires very large volumes of injected water. Two fractured zones have been formed by hydraulic fracturing and defined by close-in, borehole deployed, microseismic detectors. Initial operations were focused in the injection wellbore near total depth, where water injection treatments totalling 51,000 bbls (8,100 m3) were accomplished by pumping through a cemented-in 4-1/2-in. liner/PBR assembly. Retrievable casing packers were used to inject 26,000 bbls (4,100 m3) in the upper section of the open hole. Surface injection pressures (ISIP) varied from 4,000 to 5,900 psi (27 to 41 MPa) and the fracture gradient ranged from 0.7 to 0.96 psi/ft. Introduction Natural, or hydrothermal, geothermal reservoirs form where water has contacted rocks heated by shallow heat sources within the crust. In a few places, large circulating convection systems exist within porous, fractured reservoirs. These natural systems, capped by an impervious layer, are characterized by high heat flux at the surface and are sometimes associated with leakage of fluids, via hot springs, geysers, and fumaroles. Natural hydrothermal reservoirs are rather rare, but are excellent resources when exploited. World-wide development of such high-grade hydrothermal reservoirs is at an installed electrical capacity of about 3200 MW(e) in 13 nations, from about 3000 wells. Increasing exploration activities have seen wells drilled into some 147 hydrothermal reservoirs located in 43 countries. The current worldwide growth rate of installed geothermal electric power generating capacity is approximately 15% per year. Several HDR projects have been initiated around the world, with those in the United States, United Kingdom, Germany, France, and Japan being the most advanced. Pursuit of research and development projects for innovative geothermal energy extraction projects for innovative geothermal energy extraction systems has been motivated by the recognition that exploration and development wells often do not produce fluids. The ratio of dry to producing wells in hydrothermal exploration averages somewhat greater than 3 to 1.
- Europe (1.00)
- North America > United States > Texas (0.67)
- North America > United States > New Mexico > Los Alamos County (0.35)
- Geology > Rock Type (1.00)
- Geology > Geological Subdiscipline > Volcanology (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Renewable > Geothermal > Geothermal Resource > Hot Dry Rock (0.86)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/7 > Greater Ekofisk Field > Eldfisk Field > Tor Formation (0.98)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/7 > Greater Ekofisk Field > Eldfisk Field > Hod Formation (0.98)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/7 > Greater Ekofisk Field > Eldfisk Field > Ekofisk Formation (0.98)
- (5 more...)
Summary Studies of the individual cementing variables should be combined to lead to a total cement-job design approach that results in effective zonal isolation in critical wells. For the proper design of cement columns in (particularly gas) wells, a thorough understanding of the mechanism causing loss of hydrostatic head of a cement column is needed. In addition, fluid-loss control, slurry stability, and setting behavior should be carefully designed. Attention should also be given to mud conditioning, batch mixing, scavenger slurries, and spacers. Efficient mud displacement is achieved with high cement-displacement rates. reciprocation, and suitable cement rheologies and contact times. Introduction Cementation of the productive zone is one of the critical pails in the completion of a well that will determine whether the production strategy planned by the reservoir engineers can be successfully carried out. Thus, unless proper zonal isolation can be achieved, it will not be possible to produce independently the different reservoirs penetrated by the well, as is often required by reservoir engineering considerations. In the case of faulty zonal isolation, it will also not be possible to perform chemical treatments in the desired intervals. Faulty zonal isolation also frequently manifests itself at the surface by the appearance of pressure on casing annuli and, in the worst case, by a blowout in which the unset cement slurry is thrown out of the casing annulus by a rapid flow of formation fluids. Remedial (squeeze) cementations to correct uncontrolled flow behind casing are not only time-consuming and expensive, but they also weaken the integrity of the casing. Our cementing research along with other work has focused on methods to increase the success rate of primary cementing. This report sets out to explain the need for a total-job-design approach to cementation. It is shown how drilling and cementing variables together with Correct cement formulations can lead to efficient displacement of the drilling mud from the casing annulus. A theoretical model has been developed to explain how a dense cement, with more than sufficient hydrostatic head to control the formation fluids, loses its overpressure, which can result in annular (gas) flow. This theoretical model is used to define values of cement-formulation variables, which will increase the chance of successfully achieving zonal isolation. The Annular Gas-Flow Problem Mechanism of Gas Influx Into a Cement Column Research at Koninklijke/Shell, as well as recent publications (see Ref. 1), have indicated that gel buildup, together with simultaneous volume reduction (caused by the cement hydration process and fluid loss to permeable formations), are the mechanisms that cause loss of hydrostatic head of the cement column. Fluid (gas) can enter the cemented annulus once the hydrostatic head has been reduced sufficiently so that overbalance is lost. Our current views on the mechanism of (gas) influx into a cemented annulus are summarized as follows. During and immediately after pumping, the cement slurry behaves as a liquid and fully transmits hydrostatic pressure. JPT P. 1600^
- North America > United States > Texas (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Well Drilling > Casing and Cementing > Cement formulation (chemistry, properties) (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Summary To investigate the causes of fluid migration behind the casing after primary cementing, pressure and temperature measurements were made in the annulus of seven wells during cementing operations. Sensors were attached to the outside of the casing as it was run into each well; in this way data were obtained from several depths. A logging cable, also clamped to the casing, was used to bring data from the sensors to the surface. In some of the wells these annular measurements were continued during subsequent completion or work over operations. The pressure data could be used to determine conditions that either prevented or allowed fluid entry into the wellbore. Generally, pressure in the cement column began to decrease shortly after the cement was pumped. The success of the cementing operation depended on the cement attaining sufficient strength to exclude pore fluids from the cement before the pressure somewhere in the cement column declined to pore pressure at that depth. Pressure in the cement generally appeared to decline to the pore pressure in adjacent formations after the cement had set. In one well, however, pressure in the cement opposite a "tight streak" steadily declined to far less than a water hydrostatic gradient as the cement set. Fluid did not enter the wellbore and migrate to the surface soon after cementing in any of the wells investigated, but in one well fluid flow between zones behind the casing was indicated when the pressure in the cement decreased to pore pressure before the cement set. Before perforating was performed, annular flow was confirmed by a noise log in this well. The pressure sensors allowed other observations to be made both during and after cementing, including the effects of annular pressure applied at the surface during curing of the cement, and communication behind the casing during perforating, acidizing, and squeeze cementing. The temperature measurements in the annulus were used to monitor the setting of the cement, which is accompanied by evolution of heat. The cement generally set from the bottom of the wellbore toward the top. These field data confirm laboratory data that show a pressure decline in a cement column as the cement cures. pressure decline in a cement column as the cement cures. Conditions more likely to lead to annular fluid migration before the cement sets and steps that can be taken to decrease the likelihood of these occurrences can be identified from the field results. The pressure loss in a cement column before the cement cures is believed frequently to be responsible for vertical fluid flow behind the casing. The acronym FILAP is suggested for the phenomenon of "flow induced by loss in annular phenomenon of "flow induced by loss in annular pressure." pressure." Introduction The importance of achieving successful primary cementing of a well is hard to overemphasize. If there is a failure to seal the annulus outside the casing or liner, pressure may appear at the surface of the well from pressure may appear at the surface of the well from migrating gas (which is called "annular gas flow"), a liner top may leak, or fluids may flow between zones behind the casing in the well. Flow between zones can cause the loss of valuable hydrocarbons, the failure of stimulation treatments, and other problems. JPT P. 1429
- Well Drilling > Pressure Management (1.00)
- Well Drilling > Casing and Cementing > Cement formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Summary The crystalline nature of hydrated Portland cement is dependent primarily on temperature. The calcium silicate hydrate (CSH) gel is produced at low temperatures and, upon curing at higher temperatures, will convert to one or more crystalline phases. The better cementing compositions contain a low lime-to-silica (C/S) ratio. Xonotlite is a phase commonly produced above 150 deg. C (302 deg. F) when approximately 35% fine silica is added to Portland cement. Generally, it has good strength but moderate permeability, Truscottite, produced when an even larger quantity of silica is added to the cement, has lower permeability than xonotlite but is slightly more difficult to produce and to stabilize. Pectolite can be produced by introducing sodium into a truscottite-type formulation. Once formed, pectolite is very stable but typically has high permeability. The addition of carbonate to any of these formulations may produce scawtite. Scawtite appears to be an inferior phase by itself, but in small quantities it can be helpful in strength development. Introduction The failure of wells in several geothermal fields has been directly attributed to degradation of cement. This implies that the cementing materials used to complete geothermal wells had not been sufficiently evaluated. For the past 3 years, under the auspices of the U.S. DOE, we have studied geothermal cementing materials in an attempt to identify suitable systems. A major portion of this study was devoted to research on the behavior of calcium silicate hydrates at the high temperatures found in geothermal zones. The literature contains many references pertaining to calcium silicate hydrates in wells at temperatures up to 150 deg. C (302 deg. F), but little has been published concerning higher temperatures. Portland cement is the material normally used to seal steel pipe in a borehole. Originally designed for hydration at or near atmospheric temperature, Portland cement can be adapted for use in petroleum or geothermal wells with bottomhole temperatures approaching 370 deg. C (700 deg. F). The hydration chemistry and phase equilibria of Portland and similar calcium silicate cements change with increasing temperature. At atmospheric temperatures, tricalcium silicate (C3S)* and dicalcium silicate (C2S), which comprise about 75% of the dry Portland cement composition, react with water to form a CSH gel with variable composition and calcium hydroxide (CH). A cement slurry becomes rigid when less than one-half, and sometimes less than one-fourth, of the cement has hydrated. At this point, pores begin to close and free movement of water is no longer possible within the cement. Consequently, a true gel is formed that is strong and impermeable. Calcium ions migrate from C3S and C2S particles into the water trapped in pores. Silica migrates from quartz (sand) grains into the water at various locations. The resulting calcium silicate reaction products are high in calcium at one point and high in silica at another. Aluminum ions released by another important compound in Portland cement, tricalcium aluminate (C3A), are also of concern. Considering the number of calcium silicate compounds and aluminum substitutions possible, it is surprising that reasonably pure cement phases are commonly obtained. As temperature increases to about 120 deg. C (247 deg. F), CSH gel converts to other crystalline forms. If excess calcium hydroxide is present, alpha dicalcium silicate hydrate (alpha-C2SH), a very weak and porous material, is produced. Fine silica is normally added to Portland cement to prevent this. If at least 35% silica is added to Portland cement, to bermorite (C5S6H5 approximately), also a strong and impermeable binder, usually is formed. JPT P. 1373^
- Materials (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Renewable > Geothermal > Geothermal Resource (0.34)
Abstract One of the concerns of hydrocarbon resource companies is how effectively their wells have been cemented. One of the methods of evaluating cement quality has been with cement bond logs. Conventional cement bond logs have not always been conclusive, even in supposedly excellent cement, or alternatively in supposedly "free--pipe" situations. A decision to attempt a remedial cement repair in an indicated poor cement situation may not be successful. A decision not to attempt a remedial cement repair in an indicated good cement situation may result in unwanted fluid production from an adjacent zone. This paper will present examples and discuss the effects of high gel cements, pipe eccentralization and Channeling on current cement quality tools. A discussion leading to a suggested interpretation of current cement quality log results with respect to repairability of the cement will be presented. During the discussion of the interpretation method, several examples will be presented showing possible predictability of determining what will yield first during a cement squeeze, the cement or the formation. Limitations of the interpretation methods will be presented and discussed. Suggestions for future studies and improvements will be outlined. Introduction The efficiency of a tertiary oil recovery process will be affected when the injected fluid(s) react chemically with the reservoir rock. Chemical reaction between the rock and the injected fluid could be in form of fluid adsorption on to the rock surfaces or rock dissolution by the injected fluid. In microemulsion flooding, the efficiency of the process is affected by surfactant adsorption on to the rock surface. Holm reported a study in which the permeability of a dolomite core increased threefold after about nine pore volumes of carbon dioxid.e slug and carbonated water was injected through the core. This is a case of rock dissolution by the injected fluid. CrawEord et. al reported a case history in which the use of carbonated water as postfracture treating fluid resulted in rapid and complete well cleanup. Formation of stalactite and stalagmite in caverns show that. although carbon dioxide does dissolve carbonate rocks in the presence of water, the reaction is to some extent reversible in nature. This understanding can be extended to the reaction between CO2 and the rock in CO2 flooding of carbonate reservoirs. Since many carbonate reservoirs (mostly dolomite are potential candidates for CO2 flooding, there is a need, EOR an in-depth study of the reaction between CO2 and dolomite rock. The object of this study was to investigate the effect of CO2 on dolomite rocks and the effect of pressure on CO2-dolomite rock interaction. The purpose of this paper is to present the result of the investigation to show that while CO2 can dissolve pore linings of carbonate rocks and increase the rock permeability near the injection well, calcite crystals are precipitated and are deposited in the flow path when the pressure is reduced.
ABSTRACT This paper describes the equipment and procedures for economic placement of a 20-foot diameter caisson in the Arctic sea floor for the purpose of placing the well head and Blow Out Preventer (BOP) stack below the sea floor to avoid ice damage. Reverse circulation induced by air lift and a hydraulic-motor-driven, large-diameter bit are used to drill a 20-foot hole. The caisson sections are made of heavy corrugated steel. The drill string serves as the running tool for installation of prefabricated caisson sections which follow the bit down hole and upon reaching desired depth are released and the bit retrieved. A Variably Buoyant Guide base (VBG) is installed inside the caisson. This VBG will:provide a large load-bearing surface, minimize foundation loading by deballasting and supporting casing and well head loads with its buoyancy, protect permafrost from thermal inversion from sea water by means of an external jacket through which refrigerated brine is circulated. The riser is used for running the VBG and remains in place to drill the 36-inch hole, thus allowing cuttings recovery and drilling fluid control. The VBG is deballasted upon landing the 3D-inch casing. Deballasting supplies a support for the 30-inch casing in the event of cement bond failure from permafrost deterioration. INTRODUCTION The advance into offshore Arctic drilling has presented problems previously not encountered in conventional offshore drilling in warmer latitudes. The problems encountered include scouring of the ocean floor due to ice pressure ridges and deterioration of permafrost when penetrated. The scouring problem has forced the well head and well control equipment to be sunk to a safe level below the mud line with the aid of a large-diameter hole cased with a segmented 20-foot-diameter caisson. The permafrost must be disturbed as little as possible to allow good hole definition and cement bonding, which has led to the development of programs for refrigerated or chilled drilling fluid and special arctic cement. Well heads in the Canadian Beaufort Sea have been protected by drilling large "Glory Holes" in the sea floor so that the Blow Out Preventer stack can be place below the point of grounding of an ice ridge. This method requires the drilling of several large diameter holes in a cluster. The sea water melts down the permafrost barrier over a period of several months time. This process allows enough time for a large hole to be cleaned out by means of an airlift dredge. This procedure is time consuming and requires several months delay between preparing the "Glory Hole" and the spudding of the well. In developing this design, the major goal was to devise a system for installing the Blow Out Preventer stack beneath the sea floor in the variety of bottom soil conditions expected while using a minimum amount of rig time and additional equipment.
SYNOPSIS: A broad investigation is reported on the mechanical behaviour of the volcanic tuff of the Naples area under uniaxial compression. The strength and stress-strain behaviour of this soft rock have been successfully related to genetic and structural features of the tuff, as described by a simple mechanical model in which a matrix, inclusions and cement are distinguished. RESUME: On presente une etude poussee sur le comportement mecanique du tuf volcanique de la zone de Naples. La resistance à la compression simple et le comportement sous contrainte de deformation ont ete experimentes sur plus de 400 echantillons. Les resultats ont ete correles avec les caracteristiques genetiques et structurelles du tuf, lesquelles s'intègrent dans un simple modèle mecanique où l'on distingue la matrice, les inclusions et le ciment. ZUSAMMENFASSUNG: Dies ist ein Bericht ueber eine im Gebiet Neapel ausgefuehrten Laboruntersuchung ueber das mechanische Verhalten des Vulkantuffs unter Zusammendrueckung ohne Behinderung der Seitenausdehnung. Die Druckfestigkeit und die Spannung-Dehnung sind bei mehr als 400 Kern-Proben untersucht worden. Die Ergebnisse sind auf genetische und strukturelle Eigenschaften des Tuffs mit Erfolg zurueckgefuehrt worden, wie es sich von einem einfachen mechanischen Modell ergibt, wo Bindemittel, Einschluesse und Zement unterschieden werden. 1. INTRODUCTION Wide areas of central and southern Italy, extending from northern Latium to southern Campania, are characterized by the presence of volcanic tuff, that from a rock mechanics viewpoint may be defined as a soft rock. The experimental investigation herein presented refers to a plain area of Naples, about 300,000 m2 wide, where, starting from a depth of about 20 m, two units of volcanic tuff (neapolitan yellow tuff and grey tuff) are subsequently found. The ground surface is about 5 m above sea level, while the water table is 2 4 meters deep. The aim is to single out the connexion between genetic, textural and structural features of tuff and, on the other hand, its strength and rheological characteristics under uniaxial compression. For this purpose a mechanical model has been adopted, according to which the tuff consists of an ashy matrix, pumice and lithic inclusions and a zeolitic cement. The effectiveness of the model in describing the essential features of tuff behaviour has been substantiated by means of mineralogic analysis and Scanning Electron Microscope (SEM) observations. Depending on the different arrangements of matrix, inclusions and cement, different structures have been outlined. Each one is characterized by its own uniaxial compressive strength (σc) and stress strain behaviour, both in the region preceeding σc and in the post-peak phase until collapse of the specimen. A wide range of structural and rheological features of the tuff in Naples has been investigated, throughout the whole tuff formation thickness. 2. MAIN ASPECTS OF TUFF GENESIS In the area around Naples tuffs originated from volcanism of the Phlegrean Fields. The major event of this volcanic activity is represented by the emplacement of large volumes of pyroclastic products. According to literature, the pyroclastic materials were deposited with two different mechanisms: either a pyroclastic flow, as a result of a fissure activity, or a pyroclastic fall, subsequent to a typical volcanic explosion. The volcanic deposits of Phlegrean Fields are relative to three main periods of activity, the first and the second of which are characterized respectively by the Grey Campanian Tuff (Campa nian Ignimbrite) (28,000 35,000 years B.P.) and the Yellow Neapolitan Tuff (10,000 12,000 years B. P.) (Barberi et al. 1978; Lucini, Tongiorgi 1959; Lirer, Munno 19 75). The grey campanian tuff has an areal distribution of about 7,000 km, while the neapolitan yellow one outcropps in a smaller area, which stretches from Naples to the Phlegrean Fields. The loose pyroclastic materials (ash), that gave, rise to tuff, are formed mainly by volcanic glass particles, and secondarily by crystal and lava fragments. The grains are irregulary shaped and their size is that of a sandy silt. They have a vitreous texture which is spongy and frothy. The particles exhibit high porosity, but only a limited number of pores are in communication with one another and with the atmosphere. In the ashy matrix pumice and lithic fragments, are chaotically arranged. Their size may range from few mm to several cm. Pumices are generally more numerous and larger than lithic fragments. Lithification of the complex of loose materials (ash + pumice and lithic fragments - pozzolana) is a consequence of a diagenetic process that, under favourable conditions, yielded to the development of zeolites. Zeolites are neo-formed hydrate minerals of Al and Si; grown as a result of unwelded volcanic glass modification under the action of fluids in subaereal environment. The zeolitic minerals generally found in neapoli tan tuffs are mainly phillipsite, and chabazite; they appear as variously arranged crystals. Duration of zeolitization process has been deter mined in 4,000 5,000 years (Capaldi et al. 1971).