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In order to improve the vertical and lateral load bearing capacity of the drilling conductor, composite design of bucket foundation and drilling conductor was studied. The bearing behavior of composite conductor subjected to lateral and longitudinal external loads was investigated. In this paper, the finite element analysis was conducted by two methods, load loading and displacement loading. The bearing capacity and influencing factors of composite conductor were studied with consideration of contact surface models of composite structures and surrounding soil. The results show that the vertical bearing capacity increase with the depth increasement of the bucket foundation under the combined bearing effect of the bucket foundation and the conductor. Meanwhile, the depth of the embedded point of the composite conductor increases with the bending moment when subjected to lateral loads. When the bending moment is constant on the structure top, the lateral displacement of the structure increases with the increase of the vertical force, and the depth of the embedded point increases with the increase of the vertical force. The results also show that the change of the bending moment at the top of the composite conductor is more significant than that on the lateral displacement. The composite foundation can effectively reduce the displacement of the deepwater conductor and improve the lateral and vertical load bearing capacity of the structure. And also the research results can provide theoretical reference for further development and optimization of the deepwater composite conductor structure.

Considering the geological and reservoir conditions in the north-west fields of Cuba, a program is being developed for casing running and cementing long extended reach wells with a horizontal displacement up to 10,000 meters. The paper reveals the result of the main tasks, which include design of the well construction, calculation of casing strings, development onting program, focused on obtaining a high-quality cemf a cemeenting in this type of wells. It also assesses the impact of the implementation of several proposed strategies, in the main indicators of the process of casing running and cementing. The design of our horizontal well profile considers that the profile is in second dimension because azimuth does not suffer variations and consists of five sections: first section is vertical, then two sections with angle construction and finally a horizontal section. To make the necessary calculations of our profile, it was necessary to develop a new calculation methodology that considers the initial and final data of the classical methodology and at the same time considers the new geometric condition. Considering the characteristics of geological formations and using the classical methodology for calculating the necessary diameters of casing strings and bits in construction are included: Conductor Pipe; Surface Casing; Intermediate Casing 1; Intermediate Casing 2 (Running in the hole in 2 stages); Production Liner - Liner and Slotted Liner Filter. Cementing program of conductor pipe and a surface casing using a stinger is developed, also the development program for running and cementing multistage sections for the first intermediate column, in addition the development program for running and cementing of second section in the second technical column.

The following paper deals with the prediction of the theoretical net drilling time for a conductor pipe (CP) of offshore platforms when it plugs. The CP is driven to prevent the looser surface layer from caving in and obstructing the wellbore, because the shallow section of most wells on- and offshore is drilled in unconsolidated sediment. Due to the small CP diameter, the CP plugs very often. Normally the material is drilled out by using jetting, normal drill rigs and sometimes jack-up rigs. As offshore operations time is very important, this paper tries to assess the theoretical net time needed to excavate within the CP as a relief drilling operation, by means of Nishimatsu and Evans cutting theories. The results are compared with publicly available TBM excavation rates and then theoretical drilling rates for different unconfined compressive strength values for CP diameters of 700, 900 and 1000 mm are suggested. The results are considered for drag bits, however, they are only theoretical assumptions and cannot be applied for commercial projects with the same geotechnical properties.

With gap elements modeling the gap contact condition between jacket platforms guided supports and the conductor pipe, the deflections of the conductor pipe induced by the motions of Jackup in cantilever mode, and offsets of the jacket platforms under operating conditions are investigated. The limiting relative excursions between the jacket out of phase or in phase with the jackup and the distributions of the moment are quantified by the strength and stability analysis of the conductor systems. The results show to avoid an overload for given conductor strength and dimensions, the maximum relative displacement between jackup and jacket platform with guide offsets is about 75.0cm.

Specialists at the company Severstal’ and the Central Research Institute of Ferrous Metallurgy have developed a chemical composition and technology for making steel of strength class X56, and they have also produced a commercial batch of this steel. Production of the batch on the 5000 mill at Severstal’ entailed the use of a modern controlled-rolling technology together with accelerated cooling, which made it possible to obtain the required set of characteristics in thick plates. The Vyksa Metallurgical Plant converted the plates into 762-mm-diam. conductor pipe with a wall thickness of 38.1 mm. Analysis of the effect of the tube conversion on the mechanical characteristics of the steel showed that the changes which take place in the mechanical characteristics of the base metal during the formation of thick-walled tubes must be taken into account when specifications are developed for the flat-rolled products used to make these tubes.

Fatigue loading on subsea wellheads has been increasing in recent years through the use of larger and heavier BOP stacks and the longer drilling durations needed for deeper wells and to extend production lives. This challenge has prompted the widespread implementation of monitoring systems to confirm predictions of wellhead fatigue and ensure well operations are conducted safely. Monitoring system design requirements, data processing and evaluation of field measurements from a number of wells are described. Monitoring systems for measurement of wellhead fatigue require careful planning. Considerations include what to measure, instrument accuracy, power, data transmission, methods of attachment, data processing and data storage. The evaluation will determine the suitability of off-the-shelf equipment or the need for application specific devices. An example assessment of the requirements of measurement devices from which wellhead fatigue can be derived is given that demonstrates the importance of integrated consideration of instruments, resolution and data processing methods in the selection and design of the system. The assessment presented here has widespread application across subsea wellhead systems worldwide. A variety of different approaches to monitoring wellhead system fatigue have been attempted. These include motion measurement, using devices located in varying positions along the wellhead and BOP, to strain measurement of the conductor pipe. Examples of real systems used in different geographical locations and the wellhead system fatigue damage derived from the data are presented. The improved understanding of wellhead behaviour and modelling improvements that can be made from the use of the data obtained are demonstrated. Finally, comparisons of response measurements from different devices demonstrate the importance of instrument positioning. This finding provides a driver for the design of future instrumentation systems and an important pointer for verification of wellhead fatigue damage derived from previous monitoring programs. The work presented here provides a systematic basis for design and implementation of wellhead fatigue monitoring systems. Furthermore, the field measurements obtained demonstrate some potential pitfalls to be avoided and how to get maximum value from the data obtained.

Dry Tree Semisubmersibles (DTS), with the capability of supporting surface wellheads and allowing drilling and completion through direct vertical access risers, have attracted intense interest from the oil and gas industry. A wet tree deep draft semisubmersible has been carefully reconfigured considering the balance between the overall floater configuration and the tensioner stroke for a harsh environment application. A large amount of simulation efforts have been performed for the optimization of the integrated hull/deck/mooring/riser system. Recently, a basin model test was also successfully completed and further demonstrated its technical feasibility. The paper presents the overall design of a Top-Tensioned Riser (TTR) system for a DTS application focusing on the complexity of the DTS-TTR interface including ram style tensioning system, riser conductor and riser top assembly design with keel joint, etc. Due to the heavy weight of the TTR system in the ultra-deep water application, the riser top sections are subject to high reaction loads with the DTS in severe environments. The riser system faces the challenge to have a feasible and economic top assembly design. In this paper, an engineered riser conductor pipe is introduced to interface the riser top assembly with hull. The riser conductor pipe, which spans from deck to keel, is integrated with riser top assembly and the tensioner system design. The riser conductor protects the riser in the splash zone and prevents the high reaction loads directly transferring from hull to riser, thus reducing the riser keel joint and tension joint size. The feasibility and performance of the TTR system are demonstrated through the static and dynamic analyses. Pipe-in-pipe (PIP) contact model is employed in the simulation to ensure the dynamic interaction loads between riser and riser conductor are captured. The TTR overall system design consideration for the DTS application is discussed.

Soil moisture-monitoring equipment is difficult to install in poorly consolidated sand or sediments using hand tools because the loose material tends to collapse. The technique described herein uses a 5.5-hp wet/dry vacuum cleaner, powered by a portable gasoline generator, to remove the soil while an operator pushes a conductor pipe or casing into the profile. After initiating the hole using a hand bucket auger, an open-ended metal pipe or polyvinyl chloride (PVC) casing is inserted vertically into the shallow hole. A smaller tube, or stinger, attached to a wet/dry vacuum is inserted into the pipe to extract loose material while downward pressure is applied on the pipe. Once the casing is installed, instrumentation such as lysimeters, gypsum blocks, or tensiometers can be placed at the desired depth and backfilled with native soil. The casing is then raised and the soil allowed to collapse around the equipment, or the pipe can be left in place for neutron probe access. Measurements of soil water content after an infiltration experiment demonstrates uniform downward movement with minimal preferential flow or soil disturbance as a result of the vacuum installation of gypsum blocks and a neutron access tube.

There is ice in the Gulf of Mexico, and this type of ice called gas hydrates burns when ignited. Gas hydrates form slowly within the soil mass when the gas seeping up from offshore oil reservoirs mixes with water under high pressures (>500 m of water) and low temperatures (a few degrees Celsius). The oil travels from the well to the platform through a conductor pipe. The oil and therefore the conductor are very hot and melt the existing hydrates that are within the depth of the foundation piles. The melting process generates a large amount of gas that can endanger the stability of the foundation. The rate at which the temperature rises around the hot conductor in the hydrate rich soil is studied using the finite-element method (FEM). A detailed thermodynamic analysis is performed. It includes a laboratory experiment to help validate FEM, a study of the mesh size, the thermodynamic analysis results, a study of the conductor size, and of the latent heat influence. The results can be used to evaluate the temperature rise around a hot pipe buried in soil and therefore the propagation of the hydrate melting front around the conductor and toward the piles.

In support of a well drilled in the Great Australian Bight (GAB) by the Glomar Jack Ryan dynamically-positioned (DP) drillship in 4308 feet of water in early 2003, drift-off riser analysis was carried out to establish “alert” offsets for the emergency disconnect sequence (EDS). Drift-off analysis of the vessel/riser system is a key element to the successful management of the riser on a DP drillship, as it deals with protecting the equipment in case of the potential loss of vessel power. At this well site, high seastates combined with wind and current conditions dictate that drilling should be carried out in accordance with “well-specific operating criteria” (WSOC). These criteria assist the crew by identifying the metocean conditions that limit various operations. Analysis of the drilling riser was carried out for drift-off, hang-off and recoil scenarios to establish certain criteria to avoid exceedence of allowable limits in the riser and conductor pipe. The novel aspect of this drift-off analysis is the use of a fully-coupled, time-domain, finite element solution. The fully-coupled aspect of this solution models the vessel / tensioner system / riser / LMRP / BOP / wellhead / conductor / soil interaction process more accurately and thus allows for less conservativism when compared to uncoupled solution methods. This enables the rig to work in areas that might otherwise be considered marginal due to the anticipated time spent waiting on weather.Copyright © 2004 by ASME

Shallow water flows (SWF) from overpressured aquifers have been a persistent problem in the deepwater Gulf of Mexico (GOM) and can create significant financial and operational risks for exploration and development drilling programs. For the GOM, shallow water flow intervals typically occur between 300 ft to 2500 ft below mudline (BML) and in water depths greater than 1500 ft. If left unchecked, the disturbance from the water flow can cause loss of soil strength surrounding the wellbore, thereby compromising the structural integrity of the well. In industry, extreme cases have led to collapsed casing and/or total loss of wellbores. The Titan No. 1 exploration well was drilled in Garden Banks Block 785 (GOM), in 4640 ft of water. At Titan, the planning and successful implementation of operational procedures designed to mitigate the risks associated with SWF hazards included: performing a shallow hazards assessment, preparing and implementing SWF contingency plans, identifying the SWF zone quickly, immediately controlling the water flow zone with weighted mud (while drilling riserless), and using nitrified foam cement to seal off the water flow behind 20" conductor pipe. Operations at Titan were based on the philosophy of quickly identifying the SWF, and immediately stopping the flow with weighted mud, as the chance of successfully mitigating the flow and maintaining the structural integrity of the wellbore will likely decrease with time if the sand is allowed to produce water, sand and/or sediment.

Re-entry of a temporarily abandoned offshore well offered a unique well control challenge. When the 7-in. liner and 6-in. open-hole section had been drilled, well control problems had left the liner cement bond with questionable integrity. The well was ultimately circulated with kill weight fluid and a 100-ft surface cement plug was installed in the 9 ⅝-in. casing. A temporary abandonment (TA) cap was placed in the 9 ⅝ in. and the 13 ⅜-in. mudline hanger equipment. The 30-in. conductor pipe was severed 9 ½ ft above the mud line. Two years later, subsurface investigation indicated that bubbles were escaping from the wellbore. The danger was that reservoir pressure was migrating under the surface TA caps. The authors were members of the pressure control team called in to solve the problem. In planning for re-entry, the team designed a means of pressure investigation that relied on hydraulic snubbing equipment and well control expertise. The 13 ⅜-in. casing, with a burst rating of 3,450 psi, was the limiting factor to pressure control in a situation where 7,500 psi surface pressure was possible. The plan included installing a platform over the well, using a jackup rig, tying back the 30-in. conductor, removing the vented 13 ⅜-in. TA cap, and tying it to the platform. The team designed an elaborate surface blowout preventer (BOP) stack that included dual 8-in. overboard diverters and a pressure-confining tubing string which latched mechanically to the 9 ⅝-in. TA cap. Because it would be necessary to vent or bleed the potential well pressure to zero or use other means to kill the well for conventional re-entry, the team also designed a pressure investigation tool. A 150 K series hydraulic snubbing unit with 1 ¼-in. CS Hydril tubing would convey the tool to depth, where it would check surface pressure under the 9 ⅝-in. TA cap.

ABSTRACT Conductor pipe or drive pipe, including platform conductors, Jackup-supported conductors and free-standing conductors, is an area that can offer significant cost savings. This paper contains a comprehensive discussion of various facets of conductor pipe including structural design, as well as fabrication and installation considerations. The API LRFD interaction equations for combined axial and bending loadings are revised to include the effects of infernal and external Conductor loads. This approach will result in a more rational and cost effective conductor pipe design. Other structural design considerations are discussed including selection of environmental criteria, vortex shedding, fatigue, SCFS, S-N curves, slenderness ratio limitations and deepwater applications. An equation for conductor penetration is presented which is based on loss of circulation of drilling fluids. Recommendations are also made concerning fabrication and installation issues including Iifting, driveability, welding, inspection, mechanical connectors and practical considerations. Finally a recommendation is made on drive shoe bevel shapes based on field studies of actual installations. INTRODUCTION In an offshore well, conductor pipe, also known as drive pipe is the external pipe which provides structural support for the internal well tubing and casing strings. The objective of conductor pipe design is to provide the most economical structural member that will safely support the well during all phases of its life, including installation, drilling and production. Each phase may have different structural requirements that govern its design. The selection of the structural member can have significant cost ramifications not only in weight savings on an individual conductor, but also in the weight of a drilling/production platform. The difference in conductor sizes, i.e., between 30" and 26" diameters, could heavily influence the jacket design by increasing or decreasing environmental loadings. DEFINITIONS There are several different offshore applications for conductor pipe with each having specific requirements for its design. These applications are best categorized by three basic types: platform conductor, jackup-supported conductor (marine riser) and free-standing conductor (self-supporting caisson). They are defined for the purposes of this paper as follows:Platform ConductorA platform conductor is installed through the guides of an existing platform. Lateral support is provided to the conductor by guides at the platform's horizontal elevations. They typically have diameters of 26"-30" with uniform wall thicknesses ranging from ½" - 1" or more. Typical loading and moment diagrams are shown in Figure 1.Jackup-Supported Conductor A jackup-supported conductor, or marine riser, is a temporary conductor used only during drilling operations (usually about three to four months) which is installed by a jackup drilling rig. The conductor in this case has lateral support provided by multiple cables at the drilling rig. The cables should be taut to insure no deflections of the conductor are allowed at the rig. Internal strings are supported by a mudline suspension system and are usually not grouted to the surface. Upon completion of drilling operations the conductor is either cut off slightly above the mudline to allow for future operations or plugged and abandoned (P&A).

ABSTRACT The purpose of this new method is to calculate the probability of failure by fatigue of a free standing conductor pipe subjected to waves. This combines two approached;stochastic approach using statistical distribution of sea wave conditions and of fatigue crack initiation time.deterministic approach using standard nonlinear finite element analyses to compute the nonlinear transient response of a conductor pipe to a given set of irregular waves. Two types of nonlinearity are of importance:soil rheology leading to a nonlinear stiffness matrix,wave loading due to the nonlinear term in the Morison equation which is proportional to the square of the relative velocity between the flexible structure and the water particles. Experimental data on fatigue measurements (S-N curve) and sea conditions display a high degree of scatter. A deterministic approach adopting a safety margin at every stage may therefore lead to unrealistic design. The method described below takes into account the sources of randomness, the uncertainties and the nonlinearities. To characterize the scatter in the data, the probability density functions are used. A fatigue analysis using this method has been carried out for a typical conductor pipe 'in the Guff of Guinea. A dozen dynamic analyses using generated waves described by different wave heights and associated periods are needed because of nonlinearity and since the stochastic approach requires computing the response of the structure to any irregular wave. For this study, results show that the conductor pipe is still sfee while the usual deterministic approach leads to a damaged structure. The end result is no longer an overconservative lifetime but a distribution for the lifetime of the structure. INTRODUCTION A free standing conductor pipe is a slender structure commonly used in shallow waters. It gives oil companies much concern in terms of repair, and needs specific dynamic and fatigue studies. For water depths beyond 30m, the structural behavior is critical since a lot of these structures suffer damage due to fatigue. Standard deterministic analyses based on Miner's rule generally confirm that the structural behavior is critical at this depth. However, they predict a much shorter lifetime than the actual one. Miner's rule is almost universally used today to predict the lifetimes of parts subjected to random amplitudestresses. However, this universality is not immune to criticisms:the method uses an S-N cuNe, or in other words, it omits, by some means, the scatter of the experimental data obtained at constant amplitude cycles,the critical value of 1 for the accumulative damage is also subject to a high degree of uncertainty whichis confirmed by conductor pipe experience and by fatigue tests under variable amplitude stress. The aim of the paper is to provide a more realistic lifetime estimate.

A drilling system is described for geotechnical exploration and soil sampling in the seabed, modelled after the concept of the marine riser pipe. The system derives its stability from a "tensioning weight," in the form of a cylindrical concrete block at the bottom, which keeps the conductor pipe in tension at all times. The axial tension from the tensioning weight and the self-weight of the conductor pipe substantially reduce the bending effects in the conductor pipe resulting from current and wave forces, as well as from the drift of the drilling vessel. The lateral reaction required to keep the pipe in place at the sea floor is provided by a concrete footblock. The bottom end of the conductor pipe slides into the footblock, which has a doughnut-shaped cross section that allows for the vertical movement or heave of the drilling vessel. The Hermitian equation is used to solve for the secondary effects due to the deformation of the flexible conductor under wave or current forces and the self-weight of the conductor pipe. The system has been used successfully on the Grand Banks in 122 m of water. Keywords: geotechnical exploration, sampling, deep water drilling, marine riser analogy, tensioning weight.

The paper describes a study of the charge transfer of a solid‐gas suspension in turbulent pipe flow. Using hollow glass spheres as the particulate phase, nitrogen and saturated air respectively as the gaseous phase, experiments were performed at flow rates of Reynolds number 5000–16000. Experimental results reveal that along a dielectric pipe there is strong electrification of the suspension, with particle electrification per pipe‐diameter displacement of the order of ‐ 10−5 C/kg, while along a conductor pipe the charge decay of the electrified suspension is of an empirical form (q/m)0 exp(−αl1/2), where l is the suspension displacement from the pipe entrance and α is a constant. In each case the pipe length was approximately 1 m, and the internal diameter approximately 1 cm. The process of charge transfer through particle‐pipe impact is discussed, and an experimental EGD generator setup is described.

Summary We developed a step-by-step cementing process design chart for Conoco Inc.'s operating divisions. It includes information on selecting cement and additives and the associated hardware for casing and liner cementing operations. Each cementing operation is designed to ensure the compatibility of hardware and cement slurry components. The chart is separated into two major categories - primary and liner cementing. These categories are separated further into design criteria for cementing each casing string in a well, conductor pipe through production string, and each type of liner that is set. Conoco has reduced primary cementing costs by as much as $35,000/well and has had fewer remedial cement jobs because of adherence to practices in the design chart. These cost savings can be attributed to proper cementing practices consolidated from many geographic regions that are included in this easy-to-use chart. For example, cement costs can be reduced by limiting the use of expensive synthetic cement additives in less critical pipe strings. Less expensive natural cement additives, which perform just as well, can be used to reduce the cost per cubic foot of cement slurry. Introduction Because of economic "belt-tightening" caused by depressed oil prices, all phases of drilling, completion, and production operations are undergoing cost reviews. When high-cost areas are identified, we must reduce costs without compromising design specifications. One such cost area is cement and cement additives that are used in oil, gas, and injection well cementing. During the drilling and completion phases of a well, all casing strings must be cemented to effect a hydraulic seal between the formation and pipe, to protect and to support the casing, and to isolate production zones. Failure to accomplish this can result in costly well repairs and may endanger equipment, lives, or the environment. For this reason, primary cementing operations must be carried out in such a way as to attain these cementing goals without resorting to expensive remedial squeeze cementing. The engineer must optimize primary cement slurry design and placement techniques. Casing and liner cement design generally is a joint effort among drilling, engineering, and cement service companies. The resulting design often is influenced by such factors as personal experiences, total cost or bids, profit margins, working-time safety factors, and equipment availability, rather than by prudent engineering based on available data. This method contributes to increased primary cementing costs, increased remedial costs, and sometimes, lost production. This paper describes how we have reduced cementing costs without compromising design specifications. Furthermore, in-house cementing schools and cementing studies are conducted to improve cementing practices and to reduce cementing costs. We will present case histories and the cementing process design chart that incorporates this philosophy in a systematic approach for cementing casing strings in a cost-effective manner. The Process Design Chart The process design chart in the Appendix will aid engineers and operations personnel in designing and executing successful cementing operations. While the chart is intended for general use, we realize that each well has individual characteristics that must be examined separately. Therefore, we do not specify how much additive is needed for a particular case, but we do indicate maximum amounts. When cementing recommendations exceed the maximum limits, the slurry design should be questioned and the reasons explained. We also consider casing hardware. The design of the chart generally proceeds from the well bottom to the top and reflects what is considered the best technology to obtain a uniform cement sheath around each casing string. For example, float equipment that has a spring-loaded dart valve generally is recommended over ball or flapper valves. This recommendation is based on calculations of the differential forces exerted on the seal during cement placement vs. the seal's resistance to failure. The chart does not necessarily recommend the use of the least expensive cement slurry, but it does inform the user about the available products and slurry design choices. The choice of what slurry and casing hardware to use will depend on well parameters and other design considerations the user feels are most important during the life of the well. The chart is designed so that the user can read from the top to the bottom of a casing string or liner column, and make decisions that are based on well requirements. By the end of the column, the user should be able to select an appropriate cementing procedure and corresponding cement slurry design, as well as the compatible casing hardware.

The tensile strain on a submarine optical-fiber cable may reach a nonlinear elastic region when recovered from the sea floor. In this paper, a method is shown to characterize cable elongation up to the nonlinear plastic region by extending wire theory previously developed to evaluate cable strain in the elastic linear region. The results of applying this method to several optical-fiber cables agrees well with tensile test results of the cables when cable ends are prevented from twisting, as well as when they are free to rotate. Also, by evaluating the dependence of cable strain on cable materials, such as stranded-strength members and pressure-resistant conductor pipe, a practical submarine optical-fiber cable structure for deep-sea use is determined.

Summary Subsea wellheads can be subjected to extreme external loads when a drilling or production riser remains connected during storm or vessel drive-off conditions. In addition, vortex shedding from high currents and wave action on drilling and production risers can subject the wellhead to high-cycle fatigue loads. These extreme external and high-cycle fatigue loads can cause failure of the wellhead system when a fully cemented annulus between the 30-in. [76-cm] structural conductor pipe and 20-in. [51-cm] surface casing is not achieved. This effect of cement shortfall is most damaging when the cement level is just below the wellhead-body/conductor-housing region. Purposefully setting the cement level far below the mudline can be a cost-effective solution to the unintentional cement-shortfall problem.

The performance of a novel method, using multichannel ARMA prediction, for damping ratios estimation from natural excitation accelerations measurements is assessed through Monte Carlo simulation with simple but representative models. It is compared with some Fourier spectral methods of current practice. The high quality of the estimation has enabled the authors to determine the variation of damping versus significant wave-height for an 8-pile jacket in the North Sea and a free-standing conductor pipe in the Gulf of Guinea.

Abstract Offshore platform-conductor pipe interaction is investigated and the conductors in the role of transmitting horizontal loads into the soil are evaluated for a structure erected in a water depth of 176 feet. It is concluded that the conductor pipes will transmit significant horizontal loads into the foundation media. Introduction Offshore structures have an important role in the petroleum industry with the increasing expansion of offshore drilling and production operations. Since the first installation of a platform in the Gulf of Mexico in 1947, a number of questions of basic engineering have been raised and considerable research has been performed in this rapidly developing field. There have been several papers published in the past 20 years which deal with published in the past 20 years which deal with offshore structural problems in particular and provide valuable contributions. Among those notable are the studies of Howe, Reese and Matlock, Bouwkamp, Cooper, Blumberg and Strader, Freudenthal and Gaither, Karsan and Koehler, and McCleeland et al. It is apparent from the foregoing studies that no specific work was reported on the specific problem under consideration. Conductor pipes are installed to serve as the outside casing for wells on offshore drilling platforms. Normally, these pipes are driven through the prefabricated conductor guides, which are framed to the platform, after the erection of the jacket on platform, after the erection of the jacket on site, and are considered as parasitic elements to the whole structure. It is then customary that the conductors are not treated as structural members in most cases of structural analyses, although the wave forces, which act on the conductors and are transmitted to the platform via guides, have been taken into account. From experience, however, the conductors, which are typically driven to a penetration of 200 to 300 feet, reveal some characteristics of piles with a potential to transmit some part of the horizontal potential to transmit some part of the horizontal loads into the foundation media, thereby reducing bending moments in the primary piling elements.