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SPE Members Abstract The Gas Research Institute (GRI) has developed a project that is aimed at accelerating the transfer of several hydraulic fracturing related technologies to the marketplace. The project, known as the 'Research and Development (R&D) Wells for Technology Transfer", was initiated in the spring of 1992 and to date has been applied with nine producers on a total of 18 wells. The primary technology transfer vehicle used in the project is the cooperative research well, which is jointly sponsored by GRI and the participating producer. Emphasis is placed on heavy hands-on technology training and application by the producer, rather than on conventional GRI contractor involvement. The new technologies that are being promoted in this project include: special core tests and analysis; formation stress testing; expanded logging programs; three-dimensional fracture modeling using FRACPRO; fracture diagnostics; fracture fluid quality control; and special well clean-up techniques. Results from the project indicate that technology transfer using this technique can be effective under the right circumstances. The success is heavily dependent upon training, producer involvement, timing, and previous experience with hydraulic fracturing theory and technologies. Introduction Over the past 10 years, the GRI Supply Division has developed many technologies which have reduced the cost and risk of exploiting natural gas from unconventional resources (coal, shale, tight sands). Specifically, the Tight Gas Sand Project Area has devoted much effort toward furthering the understanding of the hydraulic fracturing process and has consequently developed a series of integrated technologies which optimize applications. The center piece of these technologies is the PC based three-dimensional hydraulic fracture modeling package, FRACPRO. Other GRI developed or enhanced technologies such as formation stress profiling, special logging suites, fracture fluid quality control, and fracture diagnostics all provide critical input parameters into the FRACPRO analysis for fracture design optimization. During the initial development and validation of these fracturing technologies, GRI contractors gather data from a cooperative research well. The four Staged Field Experiment (SFE) wells of the late 1980's are examples of this type of well. Typically, the GRI contractor's first priority is on research with technology transfer to the participating producer as a secondary objective. Under these conditions, the producer does not realize the full benefit of the technology being applied and transfer of these procedures to the producer's routine operations can be limited. In recognition of this problem, GRI initiated a project in March 1992 which would accelerate the transfer of these technologies to industry. Intera Petroleum Production Division (Intera) and Eastern Reservoir Services (ERS) were contracted to promote the Research and Development (R&D) Wells for Technology Transfer project. P. 179^
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.54)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
ABSTRACT The evolution in the use of subsea technology has seen advancement -from I well in the Gulf of Mexico in 1961 to over 750 wells in a tide variety of locations by the end of 1993. Along with the growth in numbers, the industry has seen rapid advances in technology, distances from the host facility, and water depth records. This paper gives an overview of the evolutionary changes in subsea applications, with emphasis on the most active regions, and some of the milestone installations that shaped the technology advance. INTRODUCTION In the 33 years since the first subsea well was completed in the Gulf of Mexico in 1961, the use of subsea wells has spread to most offshore producing areas of the world, as shown by Figure 1. By late 1993, a total of approximately 752 subsea wells have been completed worldwide, with over 440 of these wells still in service. This paper will provide an overview of subsea technology development by focusing on three areas which exemplify the technology used worldwide:The Gulf of Mexico and West Coast of North America The North Sea and The Campos Basin of Brazil. SUBSEA TECHNOLOGY OVERVIEW Subsea wells have been used in a variety of configurations. Typical arrangements shown by Figure 2 include single satellite wells consisting of subsea trees situated on their individual guidebases; subsea trees located on steel template structures with production manifolds; and clustered well systems which are single satellite wells connected to a nearby subsea manifold. These various design layouts and hybrid arrangements of them are usually produced back to platforms or to floating production vessels, although some have also been produced to shore. Over 50 floating production systems (FPS) have been deployed worldwide, with over 30 currently active. Maximum water depth experience of subsea wells has reached 2562 feet in the Campos Basin and 2245 feet in the Gulf of Mexico. Figure 3 shows the water depth experience range for worldwide subsea wells. The deepest production experience to date is the Aquila extended well test by Agip in 2788 feet of water in the Mediterranean in 1993. Maximum producing distance to the host facility is 30 miles for a gas reservoir and 12 miles for an oil reservoir, both in the North Sea. Most subsea wells have produced by natural flow, but over 110 wells have been produced by gas lift. Pressure maintenance with subsea water injection wells is used where needed. Well servicing or workovers can be performed using reentry from a floating drilling unit or jackup, Also, specialized techniques such as through flowline (TFL) operations can be performed downhole by pumping tools from the surface host facility through the flowlines and down the tubing. Chemicals can be pumped into the formation through the flowlines, and chemicals can be injected into the subsea tree or downhole by pumping from the surface host facility through hydraulic hoses in the subsea control umbilical. Pressure and temperature can be monitored at the tree or even downhole.
- North America > United States (1.00)
- Europe > Norway > North Sea (1.00)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth (0.28)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Garoupa Cluster > Garoupa Field (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Enchova Cluster > Enchova Field (0.99)
- South America > Brazil > Campos Basin (0.99)
- (67 more...)
ABSTRACT The paper summarizes the experiences and the technological development folio wing the construction and operation of25 concrete platforms installed over the last 20 years in the North Sea, Over the period there have been significant improvements in the concrete qualities which have permitted realization of new platform concepts for demanding conditions. The in service performance of the concrete structures has been very good. Concrete platforms are anticipated to play a major role in the future, mainly for deeper waters, floating production, smaller platforms and arctic conditions. INTRODUCTION After the installation of the pioneering Ekofisk Tank in 1973, the North Sea has been endowed with another 25 large platforms. The majority of these platforms have been of the caisson and tower configuration, however, to meet pertinent functional requirements and metocean, bathymetric and foundation conditions a variety of different platform designs have been realized. The platform types include the DORIS concepts, designed to reduce the wave forces by the perforated JarIan wall. Examples are the Ekofisk tank, the Frigg CDP1 and Ninian Central. DORIS Engineering have also designed compliant concrete towers such as the Maureen offloading buoy and the two piece barrier protecting the Ekofisk tank. Tower and caisson platforms are designed to minimize the wave force and overturning moment by utilizing slender shafts and a wide stabilizing caisson. Different designs have individual particularities such as the CONDEEP caisson composed of circular cells and the SEA TANK and ANDOC caissons with square cells. Smaller concrete platforms were recently installed in shallow waters at the Ravensburn North Field in the UK and at F3 in the Netherlands. New types of platforms are presently being constructed for very deep waters. These platforms include the Troll East platform where the 300 meters high shafts are stiffened by framing, and the pioneering Heidrun and the Troll West floating platforms for 345 meters/330 meters depths respectively. Concrete has also been chosen for platforms in other waters. The Hibernia platform, designed to resist impacts from icebergs of several million tonnes, is under construction at Newfoundland, Canada for installation on the Grand Banks. Two concrete platforms have been installed in the Baltics (Schwedeneck), two platforms in Brazil (PUB2 and PUB 3) and two platforms in the severely ice infested part of the Beaufort Sea. In Australia two concrete platforms are under preparation for installation in the Bass Strait. Most of these platforms have been smaller in size. CONCRETE PLATFORM CONSTRUCTION Construction To date, construction of all the major concrete platforms was started in a dedicated graving dock. Upon removal of the dock gate the base structure was towed out. Several platforms have been completed in the dry dock, but more commonly the upper parts of the substructure including the shafts are constructed while floating at a sheltered deep water site. The deck is normally transferred to the platform after immersing the substructure. Only the upper few meters of the shafts project above water during this operation, which in effect constitutes an inshore pressure test prior to the offshore installation.
- North America > United States (0.93)
- Europe > United Kingdom (0.90)
- Europe > Norway > North Sea (0.88)
- (3 more...)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Sognefjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Heather Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Fensfjord Formation (0.99)
- (30 more...)
ABSTRACT Although technologies do exist for removing solids from waters, oils, drilling fluids and sludges in the oil and gas industry, the capital and operating costs related to solids removal and cleaning can be very high and greatly reduce the economics in offshore oil and gas processing drilling technologies and many other sludge cleaning operations. For the past four years Chevron UK Limited and Richard Mozley Limited UK have been developing hydrocyclone technology, based on the minerals industry, for applications in solids removal and clean-up in the oil and gas industry. The flexibility of hydrocyclone with respect to fluid rate, solid type, solid concentration pressure, temperature, etc. enables them to be used for many different process applications. In addition the size, weight, cost and absence of moving parts make the hydrocyclone attractive when compared with alternative technologies. This improves the economics of offshore developments particular for small field development and simple retrofitting to existing field. This paper discusses the results of:Laboratory and field trials for removal of solids from brine/produced water for injection into reservoirs. Laboratory trials for cleaning oil from solids. The applications of the technology for offshore oil, gas and drilling process. Application of the technology to reduce environmental pollution SURVEY OF APPLICATIONS In nearly all offshore oil and gas field developments, solids present a major problem in optimizing processes and make operations difficult for many unit operations. Hydrocyclone technology can replace present offshore technologies reducing the size, weight and cost of the operations. These include:-Replacement of coarse and fine filters for sea-water filtration. Sea-water can be taken from a lower water-depth, below the possible ‘ algae bloom’ depth. For low permeability reservoirs the hydrocyclone may have to be used in conjunction with other filtration methods. Re-injection of produced water reduces the sea-water filtration and deaeration capacity required for reservoir pressure maintenance. Also, this has a major impact on the environment by reducing oil and solids discharge into the sea. Solids removal from separators and reducing the oil level on the solids to the accepted environmental requirement. Removing sand from gas/condensate field fluids to reduce pipeline deposition and erosion. Removing oil from drilling cuttings. Cleaning reservoir rock, debris or cuttings from drilling operations. Recovery and cleaning of solids from oil and water based muds. In the offshore oil and gas industry, removing and cleaning solids from oil will significantly reduce environmental pollution. Solids can be returned to the natural environment in many instances. If the quantity of residue is sufficiently small it may be economic to transport to a land-fill site. HYDROCYCLONE TECHNOLOGY DEVELOPMENT The Mozley hydrocyclone used in the minerals industry have been developed since 1977 for removing a wide range of particle sizes. Figure 1 is a graphic example of efficiency curves (percentage recovery of the size fractions to underflow) for different sizes of hydrocyclone. Figure 2 shows the operation of a hydrocyclone.
- Europe > United Kingdom (0.34)
- North America > United States > Texas (0.28)
- North America > Canada > Alberta > Coyote Field > 1354465 Coyote 10-18-29-15 Well (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 3/8 > Ninian Field > Brent Group Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 3/3 > Ninian Field > Brent Group Formation (0.99)
Abstract Dewatering a long pipeline requires special considerations regarding the design of the dewatering train components. Gels constitute a critical part of a dewatering train. This paper discusses the functional specifications that have been developed to select appropriate gels for a given application. These specifications pertain to thermal, chemical, and shear stabilities; contamination sensitivity resulting from dilution with other fluids; drying characteristics; solids content left in the pipeline upon drying; lubricity of sealing elements in the pigs; and fluid rheology to prevent fluid bypass. In addition to these properties, the gels selected should also be environmentally disposable. This paper also discusses the numerous criteria (biological degradation, ease of on-site quality control, etc.) developed for the gel selection process. Laboratory testing procedures applicable to long-term stability because of long pipeline lengths have also been discussed. The developed gel systems have been successfully employed in the dewatering of two subsea pipelines of the Zeepipe system in the North Sea:a 40-in. diameter, 505-mi. (814-km) long pipeline and a 20-in. diameter, 155-mi. (250-km) long pipeline. The performance of these gels has been excellent as verified through tests of fluid samples before and after the train travels. As a result of this study, water-based and methanol-based gels have been developed that provide excellent performance. It has been demonstrated that it is possible to design and operate dewatering trains even for long pipelines with virtually no gas bypass. The contributions of this paper are the functional specifications and the methodology for the development of appropriate gels for pipeline dewatering/drying applications. The laboratory-based simulations of the dilution and shearing of gels during the train travel will also be useful. Introduction With the development of offshore gas fields in the North Sea, the use of subsea pipelines for gas transportation has increased substantially over the past decade. As the number of gas pipelines has increased, the need for large-diameter, longer pipelines has also increased, which has created technical challenges. One of the largest technical challenges is how to dewater a large subsea pipeline after a hydrotesting operation before the pipeline is commissioned for gas transportation. Dewatering is sometimes done with a dewatering train consisting of mechanical pigs and fluid compartments driven by nitrogen, air, or produced natural gas, wherever possible (Fig. 1). The dewatering of long, large-diameter gas pipelines, using a methanol dewatering train propelled by gas, can be both a rapid and cost-effective method. However, the process should be considered a "one-shot" operation; if the operation fails, corrective action with the line filled with gas can be extremely time-consuming and expensive. The greatest risk of failure is the loss of pig sealing integrity, followed by the forward bypass of gas, which can result in hydrate formation that can partially or totally block the pipeline. Pig performance (better sealing and reduced wear) can be greatly improved by the use of appropriate gels.
- Europe > United Kingdom > North Sea (0.45)
- Europe > Norway > North Sea (0.45)
- Europe > North Sea (0.45)
- (3 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Midstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.77)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Offshore pipelines (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (0.78)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.68)
- Facilities Design, Construction and Operation > Facilities Operations > Pipeline pigging (0.66)
ABSTRACT The applicability of critical plane approaches to predict fatigue life expectancy of drillpipe is investigated. These approaches consist of physically-based damage parameters that are capable of handling complex axial, bending and torsional load histories. Two damage parameters are considered, one based on normal strain amplitude and the other on shear strain amplitude. Comparison of full scale results and data from polished coupons indicate a strong influence of microscopic surface discontinuities. Approaches are presented for dealing with these effects analytically, along with a discussion on effects of realistic drillpipe geometry and loading histories. Fatigue notch factors are estimated and used with the damage parameters. Results are correlated with data from full scale test facilities using Grade E drillpipe. INTRODUCTION Drillpipe failure due to fatigue is a very costly problem in the oil and gas industry. Although, many investigators have previously addressed this problem, its frequency of occurrence is still excessive. Based on the work of Lubinski and Hansford, the APl-RP7G provides the petroleum industry with a simplified procedure to calculate cumulative fatigue damage in drillpipe. However, this approach is strictly empirical and lacks the physical basis necessary to consider multiaxial effects (e.g. due to torsion). The most recent work concerning this problem was presented by Howard, et al, describing a systematic method of tracking cumulative fatigue damage of each joint of pipe while drilling a well. However, his approach is essentially that developed by Lubinski and Hansford. It has been documented that fatigue cracks tend to initiate and propagate along particular planes. The so-called "critical plane approaches" account for this problem by considering the history of strain and/or stress components acting on individual planes to analyze fatigue damage. For example, the amplitude of normal or shear strain acting on a particular plane is considered to cause damage. However, damage mechanisms also are influenced by the presence of a mean stress acting on the same plane. The development of such physically-based parameters has received considerable attention. In this paper, the application of critical plane approaches to predict drillpipe life expectancy is presented and discussed. Two damage parameters are considered, one based on normal strain amplitude and the other on shear strain amplitude. They are evaluated by comparison of baseline fatigue data and full scale drillpipe test data. Results demonstrate a significant influence from surface microdiscontinuities and drillpipe geometry, Analytical techniques are presented for including these effects. Full scale drillpipe fatigue facilities based on new design concept were built at the University of Tulsa and at the University of Leoben. The design allows the application of load histories that are similar to those experienced in service. CRITICAL PLANE APPROACHES Fatigue cracks tend to initiate on certain planes. Cracks have been observed to occur on planes experiencing the maximum normal strain fluctuation or the maximum shear strain fluctuation. Which of these planes control fatigue strength depends on numerous factors which include : material (isotropic or anisotropic), load amplitude (high or low cycle fatigue) and material discontinuities (notches or upsets).
- North America > United States > Texas (0.68)
- Europe > Austria > Styria > Leoben (0.26)
- Research Report > New Finding (0.66)
- Research Report > Experimental Study (0.48)
ABSTRACT Case history results show that, in short radius horizontal drilling applications it is possible to run a measurement while-drilling (MWD) tool in place of conventional surveying devices. With proper supervision and planning, Short Radius MWD can be conducted economically, reliably, and effectively. Modifications to existing MWD probe tools can allow them to maneuver the curve sections of short radius wellbores; that is, wellbores with a build rate on the order of 1.5 degrees per foot (4.9 degrees per meter). The objective for the development of this tool was to complement the short radius bottom-hole-assembly (BHA) with drilling efficiency, and provide a safer overall drilling operation. This paper discusses the criteria required to effectively plan for the use of MWD in short radius well applications. In addition it will take an overview to the development of this system, rig site operations, as well as examine actual case histories. INTRODUCTION This patented MWD system was introduced in February 1992, as a replacement for wireline steering instruments. Efficiency and safety concerns warranted a new look at MWD systems and their capability to assist the overall drilling project economics. The tool is a modified version of an MWD service currently available within the drilling industry. Through the adaptation of existing technology, a probe style, real-time, directional only, measurement-while-drilling instrument, was designed to economically assist in wellbore positional surveying and directional assembly control in short radius holes. The system is structured to accommodate the addition of other parameters, such as natural gamma-ray detection; thus, enhancing tool usage by providing a geosteering capability in short radius applications. In the initial development of the system, the ability to draw on design engineering from short radius mud motors, and conventional surveying technology, provided a means to complete the engineering design specification for a 1.5°/ft (4.9°/m) bending ratio in an accelerated time frame. This bending ratio translates to a radius of approximately 40 feet (12 meters) from vertical to horizontal. Extended lateral sections and deep hole short radius projects prove to be additional drivers for the development of this system, as safety concerns were raised over the use of a side-entry sub, and the associated wireline, for a steering tool when encountering a pressure situation. DEVELOPMENT Critical to the success of the system was the ability to remove bending stress from the probe modules which house the sensor, electronic, power, and pulser components. This was done by placing patented flexible tandems between modules and selecting the proper collar material to house the probe. Tool fit charts were developed, using the principle illustrated in Figure 1, to determine module lengths and their associated minimum curve radius. In addition to the concern over module length was the fatigue associated with the drillstring tubulars, and the frequency of passes through the actual wellbore radius. Through the use of Gerber Fatigue Criteria, a Von Mises stress limit was established for the complete downhole assembly (Figure 2). From this, guidelines were specified to minimize the possibility of stress cracks in the drillstring components.
- Asia > Middle East > UAE > Sharjah > Arabian Gulf > Ras al Khaimah Basin > Mubarek Field > Thamama Group Formation (0.97)
- Europe > Russia > Northwestern Federal District > Komi Republic > Timan-Pechora Basin > Pechora-Kolva Basin > Usa Field (0.89)
- Europe > Italy (0.89)
ABSTRACT: As offshore oil fields mature, enhanced oil recovery may be facilitated through the use of horizontal and extended-reach directional drilling. Slim-hole motors are currently used offshore to extend the vertical and directional depth of existing boreholes. These boreholes supply hydrocarbon information through geological zone isolation. As this information shows potential for hydrocarbon enhancement, horizontal technology and when needed enhanced oil recovery (EOR) methods may combine to further develop the mature offshore oil field. This paper goes into the description of offshore horizontal technology; bottom hole assembly (BHA) units and gee-guidance tools as they make for positive economics when applied to geological zones in the mature offshore oil field. INTRODUCTION: Horizontal drilling offsets economic decline as it enhances hydrocarbon production within the mature offshore field-making positive economics a reality. STATEMENT OF THEORY AND DEFINITIONS: In theory, greater exposure of the production zone via the wellbore increases hydrocarbon productivity while increasing monetary gain. This theory can be applied to the offshore mature field with respect to; vertical deepening, extended-reach drilling (ERD) as applied to workovers, multi-lateral directional well applications, and new horizontal drills. Offshore vertical deepening can be defined as a type of ERD drilling. The effect of ERD is to extend the directional well into new geological zones. Potential hydrocarbon production data gathered from these zones will then determine if these regions are further developed. Horizontal drilling maximizes hydrocarbon production when properly applied to feasible (ERD) regions, These regions then enhance production offsetting hydrocarbon decline within the mature offshore field, thereby, increasing hydrocarbon producability and field life. The radius should be considered prior to horizontal application, For radius selection, see table I, The radius type is dependent on formation geology and selection of well application; new drill, workover, or extension. The radius of choice is then set from the kick-off point (KOP) taking into account geology and type of reservoir. There are two types of reservoirs of which other reservoirs are composed in combination or in whole; the heterogeneous and homogeneous reservoir, see fig 1. and fig 2.(Available in full paper) In either the heterogeneous or homogeneous reservoir, horizontal section maximization maximizes hydrocarbon production. When horizontal technology is properly administered, it produces positive economics offsetting hydrocarbon decline in both the heterogeneous and homogeneous field. Maximum horizontal displacement in the homogeneous field means; more hydrocarbon surface area exposed to the producing wellbore, decreased specific area concentrated drawdown, decreasing water coning effect on the producing section of the wellbore, and increasing the productivity index (PI). In the mature offshore heterogeneous field, horizontal drilling optimizes hydrocarbon fracture penetration improving producability and enhancing monetary gain. This is achieved by drilling horizontally in the direction of minimum stress, thereby maximizing hydrocarbon fractures penetrated, see fig 1(Available in full paper). Prior to horizontal development of the mature offshore field, caution must be maintained with respect to; horizontal section length, geological dip of formations, location of hydrocarbon regions, optimum permeability depth, fracture azimuth, productivity index (PI), and all other reservoir specific properties.
- Europe > Netherlands > North Sea (0.29)
- Europe > United Kingdom > North Sea (0.28)
- North America > United States > Texas > Andrews County (0.24)
- North America > United States > Oklahoma > Anadarko Basin > L Formation (0.99)
- North America > United States > California > Dos Cuadras Field (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 49/16 > V-Fields > Valiant North Field > North Valiant Formation (0.99)
- (15 more...)
ABSTRACT Pipeline J lay method impose welding activity to take place in a single station. In recent years, several development have been aimed to generate a "One shot", non conventional welding system to a level of technical/commercial applicability, without a final positive result. Saipem has developed a mechanized welding system based on GMA W process : the "Passo" system, normally used for construction of cross-country/ offshore pipelines. The system, performing reliably since 1978 has been slightly and successfully modified (the "New Passo" system) and adapted to perform as well on offshore pipelines to be laid in J-mode. A dedicated testing program has been carried out with satisfactorily results. Welding trials have been conducted on pipe diameter 20" and 26" 0.D.(25 mm w.t.) X65 grade, simulating the J pipelaying configuration with the pipe axis inclined of 5°, 30° and 45° to the vertical. Mechanical testing (nick break, bends, hardness, Charpy and CTOD) have been conducted with positive results, in line with the requirements of the major international Standards for offshore pipeline construction (API 1104, BS 4515). INTRODUCTION On land, pipelines are laid horizontally by joining standard lengths of pipe, typically using all-positional manual metal arc welding (MMA) or mechanised gas shielded metal arc welding (GMAW) methods. In shallow waters, pipelines are laid in S-1ay mode, being this the configuration assumed by the pipe at the outlet of the lay-barge. Whilst these methods are highly successful and well developed, the demand for national self-reliance in oil and gas has encouraged countries to expand offshore exploration into deeper waters where the S-lay pipelaying method cannot be employed. Of particular interest is the J-/ay mode, where the pipe lengths are joined and laid from the barge in a vertical attitude. This method, due to the reduced working station size linked to the lay-barge configuration, impose welding activity to take place in a single station, with the negative effect of reducing the pipelaying productivity vs. the S-laying mode were a multistation working facility is easy to install. Economical impact and the technological innovation associated to the new lay barge concept, are the key factors who characterise and prevent this new pipe-laying methodology to grow. Consistent investments is required for the research and development of the most important equipment involved in the laying operation and, of course, on the welding system who determine the pipelaying productivity and finally the project cost. The utilisation of a fast and reliable welding system is therefore of primary importance. High welding speed, automation, easy operation and limited down time are essential as they have a direct influence on the overaIl production rate. Being a "One shot" welding system not ready yet for the application, attention has to be paid to the "Conventional" systems, and more particularly to those who has proved already their validity directly in the field in the recent past. Saipem offer the "PASSO" system, modified and tested for the new application : the "New PASSO" system.
Reliability-Based Design And Application Of Drilling Tubulars
Gulati, K.C. (Mobil R&D Corp.) | McKenna, D.L. (Mobil Producing Nigeria) | Maes, M.A. (U. of Calgary) | Johnson, R.C. (Mobil R&D Corp.) | Brand, P.R. (Mobil R&D Corp.) | Lewis, D.B. (Mobil R&D Corp.) | Riekels, Lynda (Mobil R&D Corp.) | Maute, R.E. (Mobil R&D Corp.)
ABSTRACT This paper describes a reliability based design of drilling casing and tubing in the load and resistance factor design format. The approach is based on the fundamental principles of limit state design. The paper identifies the limit states of pipe performance in well applications, discusses stochastic modeling of the load and resistance variables, and describes calibration of the design check equations. In the calibration analysis, uncertainties in the various design variables, e.g., kick load intensity and steel mechanical properties, are determined from analysis of the field and laboratory data and represented by appropriate statistical distributions. The reliability based design procedures are complemented by the pipe specifications and quality assurance procedures, also described in the paper. Application of the load and resistance factor design of casing is illustrated by an example problem. BACKGROUND Oil country tubular goods (OCTG) are subjected to a variety of loads during their service lives. These loads originate from various operations, e.g., running, cementing or producing, and accidental conditions such as the kick, or lost returns. Variability of the drilling tubular's strength and loads is well recognized [1, 2]. The strength uncertainty, for example, arises due to the inherent variability of material properties, workmanship, and handling of tubulars during installation. The load uncertainty is associated with a designer's inability to estimate loads precisely. The objective of design is to estimate the "minimum" strength and the "maximum" load over the life of a tubular and make sure that they are separated by an adequate margin. Traditional design utilizes experience based safety factors, along with a characteristic set of loads and strengths, to assure the safety of tubular design. These procedures work well when a large database of experience supports the design. However, outside of the historical experience, or when new materials and novel applications are considered, for example, deep sour wells, the basis of judgment essential to establish a safety factor is lacking. As a result, the safety of these designs cannot be assured to a known extent. A number of other issues question the validity of the traditional approach to produce optimum casing and tubing designs. Exploration and production well designs consider a distinctly different knowledge base for their load estimation. The consequences of failure of as-intended performance are also different for various applications of a given casing or tubing string. Obviously, the safety margin requirements should also vary. Also, the traditional safety factor approach considers the stress at a selected point to be the appropriate design criterion. However, it can be shown that in well design, as indeed in many other structural applications, capacity of a structural member is better characterized by its gross or total failure behavior, rather than the stress at a selected point. This is due to the fact that load bearing capacity and stress are often not linearly related.