Today's need to provide deepwater subsea well servicing has created many new challenges for the industry. For example, pulling a deepwater subsea wellhead or crown plug can require an extreme pulling force. The difficulties experienced can be compounded by conditions when the plug has been in place for extended periods of time as well as the more demanding deepwater conditions, such as high differential forces and settlement on top of the plug that contribute to the need for the higher pulling forces. These conditions often exceed the capabilities of conventional slickline services. As exploration continues to venture into more challenging environments, service companies have had to increase the scope of capabilities of their equipment to meet the challenges brought about by the new environments that require capability for tools to pull high tensile loads. The deepwater subsea arena has been particularly challenging, and this paper will focus on a slickline innovation ? an extended-stroke electro mechanical device ? that can provide deepwater subsea well interventions more cost-effectively than other service alternatives. The tool is a slickline-deployed electro-mechanical device that is operated by batteries rather than explosives or hydrostatic pressurized tools and can produce a high linear pulling force. Since first being introduced, the electro-mechanical device has undergone several changes that have increased its capabilities and functionality. For example, it has recently been configured for pulling subsea wellhead plugs. This paper will present three case histories that discuss the first use of the ‘extended stroke’ electro mechanical device in the Gulf of Mexico in which it was capable of pulling plugs at a water depth of 5,339 feet as well as several subsequent case histories. Using the slickline electro-mechanical device rather than coiled-tubing resulted in substantial savings in both the cost of deployment and rig time. Introduction Subsea well intervention can be costly when one considers that the first task often required is to pull the subsea crown plugs in the wellhead. The hydrostatic pressure associated with the fluid in the riser creates the large pressure differential across the wellhead plugs that seal the cross sectional area. Conventional slickline services have limited constant pulling force due to the finite strength limits of the wire. Deepwater and debris above wellhead plugs often compound the required pulling force because of the additional hydrostatic pressure across the plugs. These forces are well above the tensile-strength limit of slickline wire. A subsea wellhead plug requires a steady pull along the entire length of the seal bore as it is withdrawn. Conventional slickline is limited to creating extremely high but short-duration impact loads; however, brief impact loads are not suitable for unseating subsea wellhead plugs, because they have a tendency to reseat after each impact load and are forced back on seat by hydrostatic pressure from above. Therefore, using mechanical or hydraulic jars to simplify the delivered force does not effectively retrieve the plug from the wellhead. When conventional slickline service is not capable of pulling a subsea wellhead plug, coiled tubing service methods may be used. However, the cost of the service can be compromised significantly because of the additional deployment time, rig up time, and additional tripping time required. Since slickline is usually considered to be the most economical method for well intervention, the need for a system that could pull subsea well head plugs using slickline became more apparent.

The loss of brine to the hydrocarbon formations has been one of the major concerns during well completion operations. Fluid-loss control pill scontaining sized particulates, such as CaCO3 or sized salt, have often been used. However, damage to the formations and gravel packs by the solids due to solids invasion often causes reduced production and an expensive workover. The cleanup of the carbonate pill is often ineffective, especially in long intervals, since the reaction between acid and carbonate is too fast for the acid to cover the entire zone. Therefore, a reliable viscous fluid system without solids is more desirable than a particulate system. In high-permeability reservoirs, a highly crosslinked gel is needed to achieve good fluid-loss control hydroxyethylcellulose (HEC) is known for its low residue content and difficulty to be crosslinked. A highly elastic zirconium crosslinked HEC gel is achieved by using an activator and a chelant. A delaying agent is used to adjust the timing of the crosslink process. The gel is capable of stopping fluid loss in formations of 2 darcies and above at temperatures upto 290 F. Internal and/or external breakers can be used to reduce the gelviscosity to near water consistency. P. 215

Gulf of Mexico deepwater drilling activity has increasingly discovered economic hydrocarbon deposits lying below salt formations. Subsalt reservoir development is becoming one of the major challenges for operators, with the salt providing challenges in both seismic interpretation and drilling.1 This paper looks at how one operator successfully undertook a subsalt development in Mississippi Canyon. The project covered the completion of an exploratory well and the directional drilling of two development wells which produced from a state-of-the-art subsea system of wells, manifold and flowlines. The Gemini development was one of the first deepwater subsalt projects in the Gulf of Mexico and provided unique challenges for the directional drilling operations. These challenges included kicking off the well riser less in large-diameter hole, controlling wellbore trajectory through more than 3000 ft of salt and executing sidetracks to revised bottom hole targets after initial geological evaluation Success was achieved through detailed planning from a directional drilling aspect that considered the geological, engineering and economic requirements and novel application of technology. In this paper we describe how these challenges were met from the standpoint of wellbore trajectory, bottom hole assembly design and operational procedures, and we review the performance of the directional drilling operations. Introduction The Gemini field is a joint subsea development between Texaco (60%) and Chevron (40%) in the Gulf of Mexico in Mississippi Canyon Block 292. The development is approximately 90 miles southeast of New Orleans in a water depth of 3400 ft (Fig. 1). Gemini is a subsalt field that was discovered in 1995. In May 1996 the interval to be developed was tested in the No. 1 exploratory well at a rate of 32 MMcf/D of natural gas and 627 B/D of condensate. The subsea development consists of three production wells tied into a four-slot cluster manifold; each well was approximately 50 ft from the manifold. The development plan called for the drilling of two additional wells and completion of all three wells during the period of January 1999 to September 1999. The Diamond Offshore Ocean Star semisubmersible drilling rig (Fig. 1 inset) was utilized for the drilling operations and was also used concurrently to install the subsea system components (manifold, trees, and jumpers). The production from the field flows through two 12-in. flowlines back to the Chevron VK 900 platform located 27.5 miles northwest of MC-292 in 340 ft of water (Fig. 1). Initial Well Planning Initial targets allocated for the two new wells were based on results from the No. 1 exploratory well. These two wells would become the No. 3 and No. 4 development wells. Surface locations were dictated by the need to tie into the four-slot cluster manifold and by the anchor pattern of the Ocean Star. Maximizing operational efficiency, the surface locations were spaced at 50-ft intervals because the rig was required to move from each wellhead without pulling anchors. The targeted production zone was in the Allison sand at approximately 11,300 ft TVD RKB. Both wells included additional appraisal drilling for deeper targets, namely the Dean sand and the Erin sand at a depth of 15,000 ft TVD RKB. These targets lay directly below the Allison sand, and reaching them would dictate an S-shape directional profile for each well. Fig. 2 illustrates the target and wellhead locations.

Asphaltene deposition can greatly impair production rates, and even with sound prevention and remediation measures, can still lead to a reduction in production rates or even well failure. An intervention to repair a subsea failure is often times more expensive than the original completion cost, and can greatly affect the overall project economics. The prevention of asphaltene with chemicals will work to a certain extent, but only from the chemical injection point upward. Remediation efforts such as the bullheading of chemicals will help to restore production to previous levels, but can cause complications in wells with sand control equipment. Anadarko recently experienced a subsea completion failure due to excessive asphaltene deposition. Xylene was used to remediate the asphaltene, but the buildup continued below the injection point. Ultimately, a gravel pack failure occurred after a bullhead remediation effort. During the intervention, it was determined that the blockage in the wellbore region below the chemical injection point was the cause of the well failure. A new methodology and hardware were incorporated into the sidetrack, which should eliminate bullhead treatments while still preventing asphaltene deposition from the bottom perforation to surface. Preventing a sidetrack or intervention is a huge monetary savings. This paper will demonstrate the theory, hardware and application of new completion tools and methods which can prevent costly interventions or sidetracks. This system can also assist with scale, organic deposits, hydrate accumulations, corrosion, or liquid loading at or below the point of entry of hydrocarbons, which previously was not possible on subsea completions. Introduction The Ticonderoga field is located in 5,250 feet of water in the central Gulf of Mexico, 170 miles south of New Orleans. The original subsea project consisted of two wells located in Green Canyon Block 768, tied back to the host facility, the Constitution Spar, located in Green Canyon Block 680. The initial completion design and philosophy for the field were based on samples and cores from exploration wells. The presence of asphaltene was not a concern based upon the anticipated strong water-drive mechanism. Both wells were set up as two-zone intelligent wells in the Amp 6 and Amp 7 sands. Each zone was gravel packed and had an internal isolation assembly across the gravel pack screens to isolate the flow paths of the two zones. Since asphaltene deposition was not a concern in the initial design basis, both wells were configured with two chemical injection mandrels (CIM's) set at depths designed to prevent paraffin and hydrates. Figure 1 shows the subject well completion prior to sidetracking. As can be seen, chemical can be applied into the tubing via the CIM at 9,927 feet. The distance from the lower CIM to the upper sand screen was over 2,200 feet and to the lower screen was over 2,400 feet. Should problem depositions occur in this region, the operator has few avenues to remedy this build up.

The paper reviews the planning and execution of the Gemini completion activities and the subsea system installation from the Ocean Star semi submersible drilling rig. The completion philosophy and design, including wellbore preparation, perforating, gravel packing, completion string design, and well flow and clean up, are discussed. The installation operations include the manifold, trees, 12" jumpers, and 4" jumpers.This paper describes the rig and equipment modifications implemented to provide clear access for the 4-slot manifold and trees, maximize the benefits of simultaneous operation, and optimize the completion installation. The modifications, combined with jointly developed procedures, enhanced the overall safety on the jumper installations simultaneous with drilling/completion operations.The paper provides details of the installation of the subsea trees and the completions. This includes the deployment of the multiplexed Electro/Hydraulic Installation/Work Over Control System (E/H IWOCS) and the inaugural running of the Enhanced Direct Hydraulic ( E-D-H) Schlumberger SenTree 7 subsea test tree.The paper includes an overview of the operation scheduling issues including the identification of primary and secondary simultaneous operation windows.