MARKET SURVEY FOR DERRICK, SUBSTRUCTURE, AND DRILLING EQUIPMENT

Transcription

1 MARKET SURVEY FOR DERRICK, SUBSTRUCTURE, AND DRILLING EQUIPMENT 0_Market Surv DE vendors15.doc 1 of 27 1/14/04

2 Drilling Equipment Market Survey TABLE OF CONTENTS 1.0 BACKGROUND PURPOSE OF MARKET SURVEY INFORMATION THE VENDOR NEEDS TO PROVIDE TAMU REQUESTED INFORMATION/RECOMMENDATIONS SCOPE OF WORK DRILLING/CORING EQUIPMENT FOR VESSEL CONVERSION TWO UPGRADE SCENARIOS Scenario I Scenario II REPLACE DRILLING EQUIPMENT FOR SCENARIOS I AND II Derrick Traveling Equipment Crown Block Traveling Block Drill String Compensator Hook Swivel, Wireline BOP, and Oilsaver Top Drive Unique Coring Equipment Required by Scientific Operations Coring Winch and Wireline Heave Compensator for Coring Line Iron Roughneck Core Barrel Stabbing Guide Mechanized Core Handling System Dual Elevator System Rig Instrumentation Subsea Television System Guide Horn Synchronous Condenser (Power Factor Correction) Integrated Drill Pipe Handling, Racking, Laydown, and Storage Pipe Racker System Pipe Storage and Laydown Derrick Modification for Tripping Drill String Pipe Handling Options for Various Drill String Sizes Driller's Controls Miscellaneous Drilling Equipment Drawworks Triplex Mud Pumps Mud Mixing Centrifugal Pumps Rotary Table Remote Drilling Equipment and Technical Support Cranes INSPECTION AND SERVICING OF EXISTING DRILLING EQUIPMENT TRIP TIME ASSESSMENT TOP HOLE DRILLING PACKAGE Introduction Top Hole Definition Equipment Handling System _Market Surv DE vendors15.doc 2 of 27 1/14/04

3 Drilling Equipment Market Survey THDP System Configuration (Figs. 2, 3, and 4) Guide Base and Conductor Lower THDP Return Riser for Mud Circulation Upper THDP Mud Processing Equipment Choke Manifold, 3 in. I.D., H2S Service Control Equipment for the Drilling Fluid System THDP Operational Procedure (Figs. 2 and 3) Recommendations WIRELINE LOGGING ODP PROCEDURES HEAVE COMPENSATED LOGGING WINCH FOR IODP LOGGING LIST OF INFORMATION/RECOMMENDATIONS REQUESTED FROM VENDOR Figure 1 Guide Horn Figure 2 Top Hole Drilling Package Single Line Concept Figure 3 Proposed THDP Concept Figure 4 Integration with the Upper THDP Table 1 Drill String Options vs. Core Diameters...9 Table 2 Drill String Options Table 3 Total Depths (Water and Pipe) Attachment I Attachment II Attachment III Attachment IV Attachment V Attachment VI Timeline Candidate Drillships Overview of Scientific Ocean Coring in the Ocean Drilling Program Cost Summary Drilling Equipment Descriptions Trip Time Assessment 0_Market Surv DE vendors15.doc 3 of 27 1/14/04

4 Drilling Equipment Market Survey 1.0 BACKGROUND The U.S. National Science Foundation (NSF) announced the award of the Integrated Ocean Drilling Program (IODP) contract for the riserless drillship to the Joint Alliance (JA) of Joint Oceanographic Institutions, Inc. (JOI), Texas A&M University (TAMU, Science Operator) and Lamont Doherty Earth Observatory (LDEO, logging subcontractor) as the Implementing Organization on September 30, The proposed plan for the IODP is to carry out scientific coring operations in the oceans of the world using three coring platforms: A riser drillship supported by Japan A riserless drillship supported by the U.S. Alternate platforms of opportunity supported by the European community The riserless drillship selected by the JA could be in a shipyard for upgrades by late spring to early summer in 2005 (Attachment I). It is estimated that equipment will be ordered six months before the shipyard date. The goal of this Market Survey is to obtain information on equipment for the riserless drillship supported by the U.S. We request that the Market Survey data be returned to Texas A&M Research Foundation (TAMRF) by January 16, 2004 and include the cost summary, equipment specifications, and detailed technical responses to the requests for information and recommendations. The address for TAMRF is: 1000 Discovery Dr., College Station, TX The following attachments are provided to assist you in creating the market survey response: Attachment I defines the potential timelines associated with the drilling contractor Request for Proposal (RFP). Attachment II identifies potential drilling contractors and candidate drillships that may be available for IODP operations in response to the RFP. Attachment III (Overview of Scientific Coring) outlines the operational practices of the Ocean Drilling Program for scientific coring. Attachment IV is a cost summary to be returned by the vendor in response to the Market Survey. Attachment V describes the derrick and drilling equipment used on the JOIDES Resolution for scientific ocean drilling/coring. This information is provided as background for conversion requirements for a vessel. Attachment VI describes trip speeds when pulling pipe with equipment used on the JOIDES Resolution. This information is provided as background for conversion requirements for a vessel. 0_Market Surv DE vendors15.doc 4 of 27 1/14/04

5 Drilling Equipment Market Survey 2.0 PURPOSE OF MARKET SURVEY This market survey is being undertaken by TAMU on behalf of the Joint Alliance for the riserless vessel for IODP scientific coring. TAMU is interested in obtaining technical information, budgetary pricing, and estimated procurement schedules on a derrick and related drilling equipment to: improve our understanding of the current state of the art in this equipment, and determine the funding level required to convert a pre- or post-1995 drillship (Attachment II) to a U.S. riserless coring vessel for use by IODP. 0_Market Surv DE vendors15.doc 5 of 27 1/14/04

6 Drilling Equipment Market Survey 3.0 INFORMATION THE VENDOR NEEDS TO PROVIDE TAMU TAMU requests information for two possible upgrade scenarios as well as information on an inspection and servicing arrangement for the drilling equipment. TAMU is using the ODP drillship, the JOIDES Resolution, as the technical and operating reference for this market survey to ensure that all vendors understand the unique nature of the drilling equipment required for continuous coring for scientific investigations (see Attachment III). Current or past operational procedures provided in this document should not be construed as the template for future operations and are provided for information only. Responders are encouraged to be innovative in their presentation of future operational procedures. An overview of ODP engineering tools and hardware can be viewed at: REQUESTED INFORMATION/RECOMMENDATIONS Although we recognize that these are only preliminary estimates, we request that the vendors pricing be accurate to within +10% (ten percent). We also request that you provide your cost and lead-time estimates for delivery in the format shown in Attachment IV (Cost Summary). Please note, specific requests for recommendations from you are marked with a red box. If there is more than one recommendation requested, they are also marked with lower case Roman numeral numbers. Several of these items are also listed on Attachment IV, Cost Summary. In addition, requests for information/ recommendations are listed in their entirety at the end of this document (Section 6.0). It is important you respond to all such requests in your vendor response SCOPE OF WORK The primary function of the IODP vessel is to support coring, drilling, logging, and testing for scientific ocean research worldwide. The maximum hole depth is estimated to be 4000 meters below seafloor (mbsf). Holes may be loaded with mud, usually for logging, but heavy mud (up to 12.5 ppg) will not be used except as a kill fluid. The maximum water depth is 7000 m. By definition, the vendor would consider in his market survey documentation response the configuration and limitations of both the pre- and post-1995 drillships listed in Attachment II. Please provide, as appropriate to your company, the following information: 1. the estimated costs and time line to replace (Scenario I) or service and modify (Scenario II) the derrick and drilling equipment, as required, on a(any) post-1995 or pre-1995 candidate drillship(s); 2. the operational capacities and specifications for vendor's proposed drill floor and derrick equipment to handle any of the three drill pipe size options described in Table 2; 3. estimated procurement timelines to service, upgrade, or replace the equipment; 4. estimated costs to inspect and service equipment items 1-7 listed under "Inspection and Servicing of Drilling Equipment," 5. the availability of real time diagnostic systems to monitor rig drilling equipment and support the drill crew in fault finding and repair; 6. impact of each of the three drill string size options on ship conversion and on trip time for the three specified water depths (Table 3 in "Trip Speed" section and Attachment VI); 7. estimated cost to modify the drill floor, derrick, and substructure to handle and run a top hole drilling package as well as equipment descriptions, recommendations, and specifications of the handling equipment for the THDP, and; 8. possible solutions to enable the derrick to handle drill pipe in triples and pass under the Bridge of Americas (AKA Panama Canal Bridge) in Panama. The maximum height at transit draft to clear the Panama Canal Bridge is 62 m. Note: Transiting the canal is a desirable, but nonessential element of the IODP riserless vessel design. We request that you provide your summary cost and lead-time estimates for delivery in the format shown in Attachment IV (Cost Summary). 0_Market Surv DE vendors15.doc 6 of 27 1/14/04

7 Drilling Equipment Market Survey 4.0 DRILLING/CORING EQUIPMENT FOR VESSEL CONVERSION TAMU requests information for three sections: (1) two upgrade scenarios (Subsection 4.1), (2) replace the drilling equipment for the two upgrade scenarios (Subsection 4.2), and (3) the inspection and servicing of drilling equipment (Subsection 4.3). TAMU utilized the ODP drillship as a technical and operating reference to ensure that all Drilling Equipment Vendors understand the unique nature of the drilling equipment required for continuous coring for scientific investigations (Attachments III and V). Attachment V describes equipment based on the systems used by ODP for scientific coring. The derrick equipment is unique, as it must accommodate a wireline retrievable core barrel. The other drilling equipment is typical for an early generation drillship TWO UPGRADE SCENARIOS We request that you define the optimum means, estimated time to complete, and estimated cost to accomplish one of the following two upgrade scenarios to both the pre- or post-1995 drillships listed in Attachment II Scenario I Install a 1.6 million-lb derrick and substructure on any operating pre-1995 drillship. In addition, replace the existing drill floor and derrick drilling equipment on the drillship. Specific work to be discussed and costed: A 1.6 million-lb derrick and substructure with drill string compensation (DSC) that can handle 90 ft triples and has a minimum number of umbilicals hanging in the derrick. Recommend optimal procedures compatible with the new derrick and substructure for safe and efficient pipe handling (i.e., making up and laying down pipe and BHA components) to minimize the time spent tripping and preparing for transit. An overhead crane under the substructure to move 10 MT heavy lifts from the spotting area to under the derrick in the moonpool area for eventual deployment through the moonpool Scenario II Fully inspect, service, and modify the existing derrick and substructure on a pre-1995 drillship for years of additional continuous service. In addition, replace the existing drill floor and derrick drilling equipment on the drillship with new drilling equipment suitable for continuous scientific coring and compatible with the existing (assumed to be a 1.0 million-lb) derrick. Specific work to be discussed and costed: Modify the existing derrick to accomplish the following: Provide adequate clearance for the traveling equipment for coring operations and handle 90-ft triples. Limit the number of independent umbilicals hanging in the derrick. Recommend optimal procedures compatible with the derrick and substructure for safe and efficient pipe handling (i.e., making up and laying down pipe and BHA components) to minimize the time spent tripping and preparing for transit. Please comment on the feasibility of increasing the static strength of the derrick and substructure to 1.6 million pounds. An overhead bridge crane under the substructure to move 10 MT heavy lifts from the spotting area to under the derrick in the moonpool area for eventual deployment through the moonpool REPLACE DRILLING EQUIPMENT FOR SCENARIOS I AND II Both Scenario I and II require that the necessary drilling equipment (see Attachment V for more detailed descriptions) on the drill floor and in the derrick, as listed below, be replaced with new traveling and drilling equipment. New equipment is required to accommodate retrieval of the 9.5-m long core barrel used for continuous scientific coring (i.e., the equipment must have space for the core barrel, sinker bars, and overshot to be retrieved through it after breaking the drill pipe connection on the rig floor). The core barrel is retrieved with the coring line winch. Please provide documentation and the cost (Attachment IV) for the following equipment (listed in Subsections through 4.2.4) compatible with the strength of the proposed derrick (i.e., the 1.6 million-lb and 1.0 million-lb static derricks described above). 0_Market Surv DE vendors15.doc 7 of 27 1/14/04

8 Drilling Equipment Market Survey Derrick Traveling Equipment Crown Block Crown block is split to allow the coring wireline to pass through Traveling Block Traveling block is split to allow the coring wireline to pass through Drill String Compensator The Drill String Compensator (DSC), which includes a Passive Heave Compensator (PHC) and an Active Heave Compensator (AHC), will be used while coring in water depths from 100 m to 7000 m (drill string lengths to 11,000 m). The DSC system needs To control the drill string motion to within 4 in. (+/-2 in.) of deviation relative to the seafloor (within three vessel heave periods). To remove greater than 95% of the ship s heave from the absolute motion of the drill string. To operate with vessel heave of 25 ft, roll of +/-4, pitch of +/-5 and heave velocity not exceeding 5- ft/sec (assume minimum heave periods of 6 sec). To operate with a hanging load of 1,000,000 lb of drill string and BHA. To have load rating (1,000,000 lbf) that does not include any derrick traveling equipment above the top joint of the drill string such as the swivel, traveling block, top drive, or any other hardware in the derrick that will contribute to increased hook load indication. A configuration in the derrick that will accommodate the top drive handling triple stands of pipe. To operate in an ambient temperature ranges from 40 C to 50 C. To include hydraulic lines in the derrick instead of hoses, wherever possible. To have a minimum stroke of 25 ft. The following configurations will be considered for the DSC: In-line or piggyback, where the Active Heave Cylinders are retrofitted to an existing derrick with PHC cylinders. Design emphasis is to be placed on reducing the number of hydraulic and electric service loops required in the derrick. Crown mounted, where the PHC cylinders and AHC cylinders are packaged into the crown. Hydraulic derrick, where the DSC is integrated into the derrick design, thereby minimizing derrick traveling equipment, derrick mass, and wind load. Compensated drawworks, where the drawworks has increased horsepower to act as the DSC for the required 5-ft/sec vessel heave velocity. The Active Heave Compensator will be used for the following tasks during scientific coring operations: Piston Coring; the drill string and the coring line must be compensated at the same rate so no relative motion exists between the drill sting and core line Landing of wellheads. Drill bit reentry. Running casing. Cementing operations. Bare rock spud on hard rock. Drilling operations with a hydraulic hammer to install casing in hard rock (e.g., basalt). Completion operations on a cased hole. To be able to accomplish the above tasks, the driller needs to adjust the AHC to operate with a range of landing and coring weights for the BHA, equipment modules, casing strings, or downhole tools by making adjustments to the AHC output (pressure of the hydraulic power unit and the setting of the pressure relief valve if the unit is hydraulic) to allow the driller to adjust the maximum force from the AHC when reentering the guide cone or landing equipment and for coring operations. Design parameters for the DSC should take into consideration the following components of friction force on the system: 0_Market Surv DE vendors15.doc 8 of 27 1/14/04

9 Drilling Equipment Market Survey Active compensator hydraulic seals 5,000 lb Passive compensator hydraulic seals 20,000 lb Guide Horn Friction 6,000 lb (maximum); this is a device to reduce bending stress of the drill string, installed beneath the rotary table, through the moonpool to the ship s keel. The hydraulic system should have the capability to bring a spare motor/pump on-line, and accordingly remove a motor/pump from service for maintenance without interruption to DSC service. In the event of a mechanical or electronic system failure with the AHC controls, the DSC should revert to a PHC system. The DSC driller s controls should have a safety interlock to shut down erratic oscillations in the DSC. The operator s panel shall be easily accessible to the driller with simplicity of operation, have readable gauges in bright sunlight, and operator friendly in cold weather. The control panel shall be user friendly related to shutdown and start-up of the AHC and PHC when connections are made Hook Requires a hole for the coring wireline Swivel, Wireline BOP, and Oilsaver Requires a hole for the coring wireline Top Drive Requires a hole for the coring wireline Unique Coring Equipment Required by Scientific Operations Coring Winch and Wireline A split crown and traveling block permit a high-speed coring wireline to be run through the drill string. An inline drill string compensator, the hook, top drive, and swivel will need 5-in. openings on the centerline to accommodate core barrel operations. The drill floor will need to be equipped with a double-drum highspeed drawworks for core barrel retrieval by coring line. This system allows core barrels and tools to be run and retrieved by wireline at rates of ~200 m/min, which permits rapid continuous coring. The control cabin needs to have a clear view of the drill floor, the derrick, and the driller. The core winch controls could be integrated into the driller's doghouse. The coring wireline winch and wireline needs to be sized for the following core barrel weights based upon three different drill string configurations (Table 1). The core recovery speed needs to be a minimum of m/min ( ft/min) with a depth capacity of 11,000 m (36,000 ft). Each drill string can accommodate a different diameter 9.5-m length core barrel as shown in Table 1. Table 1. Drill String Options vs. Core Diameters Drill String Drill String Sizes (in.) Clearance ID (in.) Recommended Core Barrel OD (in.) Core Diameter OD (in.) Core Weight (lb) 5 x 5-1/2 (existing) / / Recommendations would be appreciated on the wireline size and an assessment of core barrel recovery times for the above coring winch for the three drill string configurations shown in Table 2: the three water depths and total depth scenarios shown in Table 3 (Subsection 4.4 below) and a core barrel pullout force of 12,000 lb is required on a 30,000-ft wireline with a 1500-lb wireline load (sinker bars and overshot). 0_Market Surv DE vendors15.doc 9 of 27 1/14/04

10 Drilling Equipment Market Survey Heave Compensator for Coring Line The heave compensated coring winch should control the coring line motion to within 4 in. (+/-2 in.) of deviation relative to the seafloor (within three vessel heave periods). The requirement is to remove greater than 95% of the ship s heave from the absolute motion of the coring line. The heave compensator needs to operate with vessel heave of 25 ft, vessel roll of +/-4, vessel pitch of +/-5 and with vessel heave velocity not exceeding 5 ft/sec. Minimum heave periods of 6 sec are to be assumed. In the event of a mechanical or electronic system failure of the heave compensator, the winch shall be able to operate as a standard core winch. The coring line winch control panel shall be easily accessible with simplicity of operation and with the capability to read the gauges in bright sunlight, and operator friendly in cold weather. The control panel shall be user friendly related to shutdown and start-up of the drill string compensator when pipe connections are made. The relative motion between the actively compensated drill string and the actively compensated coring wire line should be minimized. The heave compensated coring wireline is required for piston coring, for retrieving core barrels and for landing special downhole in-situ sampling tools in the drill string Iron Roughneck Capable of handling 5-in. to 9 1/2-in. diameter range drill pipe and drill collars. Capable of making up casing (10-3/4 in., 13-3/8 in., 16 in., and 20 in.) Core Barrel Stabbing Guide Please refer to Attachment III for background information on the core handling routine used by ODP. Because of the scientific coring operations, all derrick traveling equipment and the crown were designed to allow access into the drill string by a wireline winch. Core barrels were free-fall deployed by breaking the pipe at the rig floor and inserting the barrel into the drill string. A coring-wireline-packoff/air-wiper system above the top drive allows the hole to be circulated (at up to 500 psi) and allows the pipe to be rotated slowly with the wireline in the pipe during inner core barrel deployment and retrieval. If circulating pressures exceed 500 psi, the sinker bar system must be removed prior to the connection. A man must go up in a riding belt to the traveling block (above the wireline BOP on the top drive) to insert the wireline/sinker-bar/overshot assembly into the pipe. We would like to change this from a manual to an automated process using the optimal means to mechanically stab a sinker bar/wireline jar assembly into the top of the drill pipe. The proposed mechanical wireline-tool stabbing system would be installed to: Remove the wireline sinker-bars/overshot from the pipe through the top drive, wireline BOP, and split traveling block. Hold the wireline sinker-bars/overshot while removing the inner core barrel on the rig floor and making up a new drill pipe connection, Reinsert the wireline sinker-bars/overshot into the pipe through the split traveling block, wireline BOP, and top drive. Please supply recommendations for a mechanized stabbing guide in the derrick to insert the coring wireline tools into the drill string at the top of the traveling block Mechanized Core Handling System This technology was not available on the ODP research vessel. Please refer to Attachment III for background information on the present core handling routine. The scientific community is interested in increasing the amount of recovered core by increasing the drill pipe size (possible drill pipe sizes are listed in Table 1). The APC piston-coring shoe has 2.44-in. ID; however, the soft sediments expand or are sucked in by the piston to fill the 2.62-in. ID plastic core liner. The ODP XCB/RCB rotary coring systems cut firm to hard formations to in. OD core diameter. The ODP cores are removed from the inner core barrel in a 32-ft long butyrate plastic core liner tube, which is in. OD x 2.62-in. ID (0.092 in. thick wall). A full 9.5-m ODP core weighs ~135 to 176 lb, depending on rock density and type (i.e., 2.5 g/cc sediment to 3.25 g/cc peridotite). A larger 4.00-in. OD core would weigh 428 to 556 lb with the same rock types. The plastic core liner tube would be heavily loaded and would have to be held straight (i.e., supported to avoid core distortion) as it is removed from the inner core barrel and transported to the adjacent core handling area (for sampling and 0_Market Surv DE vendors15.doc 10 of 27 1/14/04

11 Drilling Equipment Market Survey sectioning). Bending the core liner around corners could distort the core inside the liner, which would also reduce the scientific value. In the core handling area, the core liner is manually cut into 1.5-m long sections for sampling and is moved into the lab. The proposed mechanical handling system for core removal would: remove the core liner/core from the inner core barrel on the rig floor, support the core liner to prevent buckling or bending, move the core liner/core to the core handling area (~75 ft), and allow core sectioning and sampling to take place Dual Elevator System i) Recommendations on a dual elevator design to eliminate slip damage to the drill pipe. ii) Recommendations on integrating the dual elevator system for drill pipe into a rig floor system that improves safety and operational efficiency. iii) Cost for 350 and 500 ton dual elevators for the 5 in. x 5-1/2 in., 5-7/8 in., and 6-5/8 in. drill pipe Rig Instrumentation The IODP Rig Instrumentation System should have the following features: Capable of recording various drilling and ship motion parameters from standard measuring devices. Parallel recording of data in two different domains minutes and seconds. Capable of two-way communication with various data acquisition systems (i.e., MWD/LWD). Capable of providing large, easy-to-read, user configurable display of real-time data. Capable of providing multiple displays (rig floor and remote stations). Capable of providing real-time and historical views of data. Easily configured print formats and printing capability. Capable of recording selected data at 1-sec rate. Print daily geolograph format logs. Recommendations on a rig instrumentation system for gathering and displaying critical drilling data in real time to the driller and remote positions on the ship Subsea Television System A subsea television camera with zoom capability rated for specified water depth complete with pan and tilt assembly, light assembly, and protective guide frame. Television camera should be capable of detaching from a protective frame on a 50-m tether. A TV monitor located at Driller's control and in DP control room. A surface control console with power supply, lighting and focusing and zoom control, pan and tilt control and winch control. Winch unit with line tension/depth readout and data feed into rig instrumentation system. A heave compensated subsea winch capable of handling a minimum of 9,144 m (30,000 ft) of cable is needed to reduce the effect of ship's heave on the subsea reentry system. The heave compensated subsea winch shall control the TV and sonar motion to within 4 in. (+/-2 in.) of deviation relative to the seafloor (within three vessel heave periods). The requirement is to remove greater than 95% of the ship's heave from the absolute motion of the subsea cable. The heave compensator will operate with vessel heave of 25 ft, vessel roll of +/-4, vessel pitch of +/-5 and with vessel heave velocity not exceeding 5 ft/sec. Minimum heave periods of 6 sec are to be assumed. In the event of a mechanical or electronic system failure of the heave compensator on the subsea winch, the winch shall be able to operate as a standard winch. The subsea reentry winch control panel shall be easily accessible with simplicity of operation, operator friendly in cold weather, and with the capability to read the gauges in bright sunlight. TV cable having sufficient length for the specified water depth and suitable for re-termination on rig. Color sonar system (Mesotec color or equivalent) mounted with TV camera for search capability (for structures or holes) of large areas or in turbid water. The TV and sonar information is used to assist in locating objects on the seafloor and in reentering seafloor structures and holes. 0_Market Surv DE vendors15.doc 11 of 27 1/14/04

12 Drilling Equipment Market Survey A shock protected frame (to support the TV and sonar system) that is clamped around the drill pipe and deployed by running it up and down the drill string on the coax cable winch. The split guide that goes around the drill string is ~9-in. ID to go over drill pipe and ~18 in. to go over 16-in. casing. Recommendation and cost for a subsea television system Guide Horn A drill pipe guide horn (Fig. 1) is a flared tubular (cone-shaped) structure located in the moonpool of a drill ship composed of an upper and lower section. The upper section extends from just below the rotary table at the rig floor elevation to the moonpool doors on the main deck. The lower section continues as a tapered split cylinder from just below the moonpool doors to just slightly past the keel of the drill ship. The tapered internal diameter is narrow at the top, starting at ~9 in. (ID) and flared at the bottom. Depending on the movement of the drillship, the horn design allows a gently curved contact to occur with a major 350 ft radius, thus, providing a minimal bending stress riser on the drill string as it rotates. Normal bending stress in drill string is 60,000 psi; with bending limiters ~30,000 psi; with knobbies ~20,000 psi. By reducing stress risers, fatigue life of the drill pipe can be increased during normal operations. The upper and lower sections of the guide horn are connected by means of a Cameron 18-3/4 in. 10 kpsi Hub Clamp. The lower section of the guide horn is split into two halves and is designed to clam-shell around the drill string. When the two split-halves are mated, hydraulically actuated locking pins, with tapered profiles, positively lock both halves together. The entire lower section of the guide horn is supported by spider-beams. These sliding beams are mounted to and controlled by the moonpool doors located at the main deck level. This feature allows for deployment of large equipment and seafloor structures (e.g., reentry cones). i) Recommendation and cost for a guide-horn configuration for the proposed drillship. ii) Are both the lower and upper guide horn necessary to minimize drill string stresses? Synchronous Condenser (Power Factor Correction) A synchronous condenser is required to provide a capacitive load to offset the lagging phase angle created by the power control circuitry, which optimizes the main engine load factor and fuel efficiency. The synchronous generator requires a continuous duty rating, a soft starter, an exciter regulator/power factor controller with maximum kvar limiter rated for ~3000 kvar, 4 pole, 1800 rpm, 4160 volts, 60 hertz. Recommendation and cost on a synchronous condenser package Integrated Drill Pipe Handling, Racking, Laydown, and Storage Your guidance and experience on the options available for drill pipe handling would be valuable to our understanding of the current state of the art. We request that vendors provide options for both the post-1995 and pre-1995 drillship configurations listed in Attachment II for the following equipment Pipe Racker System Please provide recommendations for: i) Ensuring the safety and efficiency of handling drill pipe and collars on the rig floor. ii) Ensuring the safety and efficiency of handling drill pipe and collars to the rig floor from the storage area. iii) Integrating the pipe handling system into a derrick and substructure. iv) Storing the drill string in singles or triples. Drill pipe may be laid down for transits and picked up for drilling up to eight times per month. v) Upgrading the driller's controls on a pre-1995 drillship as part of the pipe racker system. 0_Market Surv DE vendors15.doc 12 of 27 1/14/04

13 Drilling Equipment Market Survey Pipe Storage and Laydown A horizontal drill pipe laydown system that handles pipe in triples may be the most efficient system for a scientific coring vessel. Most new pipe handling systems store pipe as singles. Thus, IODP may have to break triples into singles for storage during transit. In addition, pre-1995 drillships may not have enough stability to transit with pipe in a triple configuration in the derrick. However, the selected IODP drillship may benefit from laying down the drill string in triples. Recommendations on optimal means for pipe storage and laydown for the post- and pre-1995 drillships Derrick Modification for Tripping Drill String The nonriser vessel used by ODP was restricted to handling the drill string in doubles (with the top drive) during drilling operations, because of the addition of a passive heave compensator and a top drive inside the existing Dreco 147-ft derrick. i) Recommendations on the optimal means of handling 90-ft triples using the top drive. A shorter top drive/traveling block/wireline BOP or compensated drawworks may be considered for the post- and pre-1995 drillships. ii) Recommendations on racking stands of drill pipe in the derrick during bit trips Pipe Handling Options for Various Drill String Sizes There are three potential drill string configuration scenarios for IODP operations as shown in Table 2. The drillship would carry a working drill string and a back-up string on board at all times. The ship will also carry drill pipe with bend limiters, which are knobs (similar to tool joints or heavy wall drill pipe) fabricated on the pipe at 10-ft centers. The bend limiters, similar to heavy-wall pipe, may affect pipe handling. IODP would run the lower string of drill pipe to the seafloor or to the crossover point before running the middle string. IODP would operate with the middle or upper string in the water column and through the moonpool. In heavy weather, knobbies (similar to heavy wall but cut from drill collar stock) are run through the moonpool to help handle bending stresses at the top of the drill string. The upper string with bend limiters could be used for coring operations in good weather vs. picking up the knobbies and it can also be used for running heavy casing strings. i) Recommendations on the optimal drill string for scientific coring operations and its integrated drill pipe handling system. ii) Various pipe handling configurations that could be considered (e.g., the drill string and/or BHA stood back in the derrick, laid down in singles, or laid down in triples). iii) The derrick rating, set back capacity, and pipe handling system requirements should be defined, documented, and costsed for the following three drill string options (Table 2) with the three water depths and total depths shown in Table 3. Table 2. Drill String Options Drill Pipe Size, Nom. Wt., Grade (in., lb/ft, API Grade) Lower String w/o Bend Limiter (meters) Middle String w/o Bend Limiter (meters) Upper String w/ Bend Limiter (meters) Drill String Total Length (meters) 5 in lb, S /2 in lb S , /8 in lb Z /8 in lb Z /8 in lb Z /8 in lb Z _Market Surv DE vendors15.doc 13 of 27 1/14/04

14 Drilling Equipment Market Survey Driller's Controls The driller's controls require readouts on information that will assist the driller in handling the pipe on board and to expedite tripping pipe, along with monitoring drilling parameters during coring and drilling operations. i) Recommendations on optimal driller's controls to monitor drilling parameters and operate the pipe handling system. ii) Recommendation on integration of the coring winch controls in the driller's dog house Miscellaneous Drilling Equipment Requests for recommendations and costs are also requested for various items of drilling equipment described in this section Drawworks i) Cost to upgrade the lifting speed of the drawworks by the addition of a third 1000-hp motor. ii) Cost to upgrade the drawworks with disc brakes Triplex Mud Pumps i) Recommendations and costs on upgrading the capacity of the mud pumps on the rig. ii) Recommendation and costs on the size and material specification for the mud supply lines in the derrick to be rated for 5,000 psi and to match the triplex pumps pressure and rates Mud Mixing Centrifugal Pumps i) Recommendations and costs on mud mixing systems to improve the fluid shearing of sepiolite clay when mixed with sea water to obtain a yield point >120 and to maintain the yield point in the active mud pits. ii) Recommendations and costs on a minimum mud separation system (shakers, desander, and desilter) for top hole drilling package (THDP) Rotary Table Recommendations on the rotary table configuration to be compatible with and to handle the upper guide horn Remote Drilling Equipment and Technical Support Recommendations and costs on capability to monitor performance of drilling equipment in real time on shore and supply technical support Cranes Recommendations and costs on new cranes for pre-1995 drillships INSPECTION AND SERVICING OF EXISTING DRILLING EQUIPMENT i) Vendor is to supply documentation and a cost estimate to inspect, service, and upgrade (as possible) the existing drilling equipment on any pre-1995 drillship(s) to provide continuous service for another 15 years. ii) Vendor is to supply information on the serviceability, maintainability, and reliability of the recommended equipment on the drill floor and derrick, focused on the top drive, crown and traveling equipment, drill string compensator, iron roughneck and compensated winches TRIP TIME ASSESSMENT A drill-string trip-time assessment is requested for the three potential drill strings vs. the three water depths and total depths shown in Table 3 below, comparing the:results using a drawworks with two (2) vs. three (3) drawworks motors 0_Market Surv DE vendors15.doc 14 of 27 1/14/04

15 Drilling Equipment Market Survey Note that Attachment VI analyzes the trip time restrictions on the JOIDES Resolution due to the top drive. Table 3. Total Depths (Water and Pipe) Scenarios Water Depth Crossover Below Seafloor Total Depth 6560 ft (2000 m) 6200 ft (1900 m) 5000 ft (1500 m) 11,560 ft ft (4000 m) ft (3900 m) 5000 ft (1500 m) 18,120 ft ft (6000 m) ft (3900 m) 5000 ft (1500 m) 24,680 ft 4.5. TOP HOLE DRILLING PACKAGE Introduction The purpose of the Top Hole Drilling Package (THDP) is to increase hole cleaning capability and to maintain a required borehole pressure gradient in a riserless drilling mode, using a rotating head with a mechanical seafloor pump and mud return line to the ship to: Mitigate various pressure related geotechnical hazards at shallow penetration depths, such as pressured water and gas sands, by imposing the optimum circulating pressure to improve wellbore stability and hole cleaning without increasing mud weight; Mitigate formation fracturing and mud loss by controlling the pressure on the wellbore, using a seafloor pump either as an annular choke (i.e., to increase wellbore pressure) or as a mud lift pump in riserless mode (i.e., to eliminate the hydrostatic pressure effect of the mud column that would be in a riser); Reduce the seafloor pollution and loss of mud caused by the "dump and pump method;" Reduce the number and size of casing strings required during drilling operations (i.e., by extending casing setting depths to cover problem formations with fewer casings); and Improve the ability to successfully wireline log the open hole Top Hole Definition Surface casing (13-3/8 in.) set <5000 ft below the mudline Equipment Handling System The THDP stack requires a handling system to facilitate transport and mating of the Lower and Upper THDP from their storage to running positions. Recommendation and layout of a handling system for the Upper and Lower THDP in the moonpool to facilitate transport from the storage to an operational position THDP System Configuration (Figs. 2, 3, and 4) The reentry, casing, and THDP system would consist of the following elements: Guide Base and Conductor The rig s normal drill string would be used to run a subsea guide base with a small structural casing (maximum 20-in.) jetted-in using normal offshore practice. A low-pressure housing suitable for 20-in. structural casing would be integrated into a temporary guide base (TGB). The housing would be able to accommodate 16-in., 13-3/8 in., and a third smaller casing. The 16 in. is for use as a contingency structural/conductor casing string Lower THDP The Lower THDP consists of a dual ram package of blind/shear and variable pipe rams. It allows the operator to drill below the surface casing and mitigate potential hazards. Formation evaluation would be done using electric logs and downhole sampling tools run through the drill string. A 13-5/8 in. dual ram 10,000-psi BOP system with an extension spool to land the lower THDP into the structural casing will be used to maintain well integrity and safety. Wellbore circulating pressure control would be imposed by a seafloor-mounted mud return pump, which also acts as a choke. The mud would be pumped up a return riser pipe to the vessel, where it would be 0_Market Surv DE vendors15.doc 15 of 27 1/14/04

16 Drilling Equipment Market Survey conditioned for recirculation. The THDP would have a minimal seafloor BOP (two rams) and Rotating Head. The mud return riser (RR) pipe would require an offset rotary and tensioning system to tension and secure the mud RR string beneath the drill floor during operations. A master hydraulic control panel would be provided with a hydraulic power unit. The master control panel would be capable of operating all functions of the THDP and providing readouts for all major systems. Hydraulic power would be supplied by electrically driven pumps on the master unit. The hydraulic power system would be designed such that each pump could be isolated for repairs without interfering with the operation of the other pumps. Sufficient accumulator capacity would be provided to meet the criteria in API RP 16E (Control Systems for Drilling Well Control Equipment), October The control fluid would be biodegradable and protected against freezing to the environmental limits specified. A driller's THDP control panel would be capable of operating all functions of the THDP and would give a clear indication of the status of the various functions on the THDP. A mini-remote control panel would also be located a suitable distance from the driller's panel in a nonhazardous area and capable of operating major THDP functions. A battery bank and battery charging system would be capable of providing standby electrical power to the driller's panel and the mini-remote panel in the event primary rig power is lost. A hydraulically powered control umbilical reel containing an adequate length of umbilical would be required to run the control umbilical in up to 4000-m water depth. The hydraulically powered reel would be located in the moonpool area. A single THDP control pod would be located on the Upper THDP Return Riser for Mud Circulation A second rotary set up on the rig floor would allow the 5-in. mud RR to be run from the rig floor. The 5- in. mud RR could be supported by a hydraulic tensioner system in the moonpool area. A power umbilical cable, to supply power and control to the Upper THDP, could be strapped to the 5-in. mud RR. Mud would be pumped down the normal drill string, and the seafloor pump speed (output) would be controlled to either add wellbore pressure (i.e., acting as a choke) or reduce wellbore pressure (i.e., acting as a lift pump). A mud RR flexible hose would connect the mud return riser of the THDP to the mud treatment and choke manifold. The mud RR system consists of: A 5-in. drill string to act as a mud RR and to be used to run the THDP (maximum WD = 4000 m). A tensioning system would compensate the mud RR. An offset rotary and the iron roughneck could be used to makeup and run the mud RR while the drill string is in the hole. The coring winch could be modified to include a third drum for use as a drawworks for the mud RR. The derrick could incorporate a second crown and traveling block to run the mud RR. The Upper THDP would fit within a standard BOP footprint (10 ft x 10 ft), be ~20 ft tall, and weigh ~75,000 lb in air. Recommendations for the THDP handling equipment, including an offset rotary and tensioning system, elevators, iron roughneck, and derrick modifications to run, makeup, and retrieve the mud RR string beneath the drill floor Upper THDP The Upper THDP, consisting of a rotating head and seafloor dual gradient pump package, could be run over the drill string suspended on the 5-in. drill pipe mud RR. It would contain: A twin duplex mud-lift pump system, with subsea electric motors for hydraulic power, properly sized and packaged for subsea operations. The Upper THDP would land and lock out with the rotating head and reduce the mud column gradient for the wellbore to the hydrostatic gradient of seawater at the seabed. Valve manifold for suction and discharge of two duplex pumps, mud RR, and seafloor dump valve. A control system to operate the Upper and Lower THDP packages. Recommendations and layout for storing and handling the Upper and Lower THDP. 0_Market Surv DE vendors15.doc 16 of 27 1/14/04

17 Drilling Equipment Market Survey Mud Processing Equipment A mud processing system is required for the Top Hole Drilling Package. The circulating rate could range from 750 to 1200 gpm with a maximum circulating pressure of 3500 psi. A mud/gas separator of the atmospheric-pressure type with a closed bottom needs to be provided. Linear or elliptical motion shale shakers are required for the THDP with a maximum capacity of 4550 lpm (1200 gpm). A vacuum type degasser may be required in the mud return system immediately downstream of the shale shakers with its vent piping arranged to alleviate hazard from gas accumulation. The maximum throughput capacity would be 4550 lpm (1200 gpm), and the equipment needs to be rated for H 2 S service. Solids control equipment (e.g., desander and desilter as a minimum) may be required downstream of the shale shakers. The suction and discharge lines and tanks related to this equipment must be properly arranged for maximum solids control effect. Minimum throughput capacities are 3800 lpm (1000 gpm) and 3000 lpm (800 gpm) for the desander and desilter, respectively. Recommendations and layout of a mud processing system for a THDP Choke Manifold, 3 in. I.D., H 2 S Service A choke manifold would consist of a minimum of two chokes with at least one power (remote) operated choke and one manually adjustable choke. In addition, it should include one straight bypass through the manifold, which should be rated for 5000 psi. Recommendations and layout of a choke manifold for a THDP Control Equipment for the Drilling Fluid System Recommendations and layout of the control equipment for the drilling fluid system needed with a THDP, including: level totalizer, trip tank, drilling fluid return indicator, alarms for PVT, and a flow returns indicator THDP Operational Procedure (Figs. 2 and 3) The following operational sequence is envisioned for THDP operations: Run the guide base on 5 x 5-1/2 in. drill pipe and jet-in 20-in. structural casing to a depth of ~100 mbsf. Run the Upper THDP (rotating head and seafloor pump package) on the mud RR pipe either using the drill string as a guide or with the THDP run as a guide-lineless package. Core a test hole with a 9-7/8 in. bit through the Upper THDP and log. Underream to 20-in., and set a 16-in. intermediate structural/conductor casing (if required by hole conditions). Drill and core to targeted surface casing depth utilizing the Upper THDP. Kill the well and pull the Upper THDP. RIH and cement 13-3/8 in. surface casing above the formation interval. RIH with the integrated Lower and Upper THDP (13-5/8 in. dual rams and dual gradient pump package). Drill and core into the formation. Evaluate the formation with wireline electric logs and downhole tools run through the drill string ( in. pass through ID). Abandon the hole in compliance with regulations. Recover the integrated THDP Recommendations Please provide recommendations on the following items. i) The configuration and spacing of an offset rotary with access to the iron roughneck on the rig floor for running the mud Return Riser of the THDP. ii) The ability to accommodate a dual elevator system on the offset rotary table to minimize drill pipe damage when tripping the Return Riser. 0_Market Surv DE vendors15.doc 17 of 27 1/14/04