Single-Trip Subsea Completions

This paper presents an overview of the development of a Completion Riser and Workover Control System for use by Shell Offshore Inc. (SOI) in the Mensa Project located in 5,300 feet of water in the Gulf of Mexico. The system was developed as an upgrade to a system previously used for SOI's Popeye and Mars Projects in water depths of 2,040 feet and 3,150 feet, respectively. Major changes to the existing system were the development of a multiplexed electro-hydraulic control system, use of a monobore running string to land the tubing hanger running assembly and tubing string, construction of a modular BOP Spanner Joint, and new hydraulic and electrical umbilical systems for use in water depths up to 6,000 feet. Early resolution of system interfacing and start of manufacturing work were essential to meet the well completion schedule. Use of this Completion I Workover (CIW) System at world record water depths has expanded the envelope for which proven and practical technology can be used in a subsea field development. Introduction The C/W System for Mensa Project was a logical extension of the system initially built for the installation of the Popeye and Mars subsea wells. All subsea equipment for the two earlier projects was designed for water depths up to 6,000 feet. However, the original control umbilicals were limited to 4,000 feet. While application of the original piloted hydraulic control system at 6,000 feet was feasible, the preferred system for deeper water was an electro-hydraulic multiplexed (mux) control system. With a mux control system, the reduced umbilical size makes it more manageable and the response time for hydraulically actuated components is drastically reduced. One guiding philosophy from the outset of the project was that any required new equipment would be constructed as stand-alone units without any re-configuring of existing equipment. The goal was to allow the creation of the required new equipment to proceed on a development path independent of the field utilization schedule for the existing equipment. This concept was rigidly enforced as design alternatives were evaluated which would require modification of the existing equipment to incorporate the features of the new control system. By requiring that the new control system act as an overlay to the existing piloted hydraulic system, the ability to return to the former operating mode was preserved. Changes to the subsea hardware were driven by the performance on prior projects and new challenges of working at the greater water depth. Figures 1 and 2 identify the major components of the CIW System for the tubing hanger installation mode and tree installation mode, respectively. Experience gained working with the original BOP Spanner Joint prompted a redesign to simplify assembly and increase reliability of the tool. Evaluation of the limitations of the completion rig's hook motion compensation system led to the adoption of a lighter running string to land the completion string. Riser System Mechanical Components Apart from general refurbishment activities following the Mars subsea well completion, there were no initial plans to modify any of the mechanical components of the riser system.

This paper describes the state of the art of deep water subsea completion techniques and equipment, showing the milestones that were reached through the completion of wells placed in water depths beyond 700 m, namely MARLIM 03, 06, 07, 08, and 09 (the latter being the current subsea completion record, in 781 m). It also shows the expertise developed through the design and manufacturing of equipment to operate in water depths up to 1,800 m, as well as the future trends in subsea completion. The First End Vertical Connection, Tubing Packer Hanger, Shear able Riser Joint, Integrated Drilling and Completion Base (BINT), and the future use of centrifugal submersible pumps in subsea wells are some examples of the technical innovations that are currently being introduced. INTRODUCTION Since 1984, PETROBRAS' most significant oil finds are located in deep waters, beyond 300m. The Albacora and Marlim fields were followed by the Salema, Bijupira, Barracuda and the 382 Area fields, among others. Motivated by these discoveries, the company has been employing efforts to obtain the technological capability to produce economically and safely the immense reserves already discovered in water depths of up to 2,000 m. In this search for technological capability stand out the PROC.AP program, the Petrobras Technological Development Program on Deepwater Production Systems. The 6 years program that ended in 1991, allowed a coordinated and integrated action between all the different company's departments, suppliers and R&D Centers at low cost and within the time frame the company demanded. Deepwater production is a vital issue for Petrobras, because although presently only 8% of the average crude production (650,000 bpd) comes from wells that are located deeper than 400 m of water depth, this figure is expected to reach 61% by 2001 (barring any onshore or shallow water discovery). Furthermore, the deepwater fields account for 66% of total proved and potential hydrocarbons reserves in Brazil. This paper shows the state of the art of the Deepwater Completion Technology, achieved through the PROCAP or via products jointly developed by the Petrobras' Production Department and its suppliers, as well as the innovations that are that are being currently introduced and the future trends in the area. STATE OF THE ART COMPLETION OF THE MARLIM FIELD WELLS In March, 1991 the 3-MRL-3-RJS well was completed in 721 m water depth with a subsea Christmas tree specially designed for operations with a dynamically positioned (DP) drilling unit without guidelines. The success of the operation, the first in the world at that time, confirmed the technical feasibility of the lay-away operation with DP units and the following items summarize the main achievements:Subsea completion water depth record 721 m (2,365 ft)World's first purpose built guidelineless (GLL) lay-away subsea tree installedFirst well drilled with a DP rig completed in the world

Most of Brazilian oil and gas reserves are located in offshore deep waters. In this scenario, high well productivity is essential. Artificial lift will certainly play an important role in the exploitation of those deep water fields. This paper describes the most important artificial lift methods, their main characteristics and application niches. It also shows what Petrobras is currently doing in order to make them available for subsea use. The following methods are analysed:gas lift;electrical submersible pump;hydraulic jet pump;progressing cavity pump;multiphase pump;subsea separation system. Introduction Petrobras is the world leader in subsea completion. For subsea application only gas lift has been widely used as artificial lift method, due to its intrinsic similarity with onshore's gas lift method. This similarity comes from the fact that it is driven by a power fluid using roughly the same components for both onshore and subsea application. For this reason, gas lift is today seen as the subsea conventional artificial lift method. Sometimes, gas lift may not be the best method to fit specific field's requirements. This happens, for instance, when there are long distances between well heads and platforms, and the gas injected, even though helping the flow in the vertical sections (well and riser), increases pressure drops in the horizontal section (flow line). Additionally, this method demands compressors and an increase of gas facilities to handle the extra recycling gas, with consequent drawbacks on platform weight and area requirements, which have a high impact on offshore installations costs. Of course, there are other limitations for the gas lift method, but this will be addressed later. As a major oil company, with large offshore hydrocarbon reserves and more than 60% of nowadays' total production coming from offshore wells, Pepobras is currently feeling the need to adapt some artificial lift techniques, in order to make them available for subsea use as an alternative to the conventional gas lift method. Petrobras believes that each of these options may find some fields with adequate set of characteristics that make them the proper choice for their exploitation. This paper describes the major characteristics of each method currently under development for offshore use (focusing on subsea applications), the expected characteristics of theirs application niche (advantages and disadvantages), the probable major problems for their extension to subsea use and their current development stage at Petrobras. Artificial Lift Methods Description In this item it will be discussed the main characteristics of each method, as well as the difficulties to adapt them to subsea use. What Petrobras is currently doing and planning to do for each method will also be discussed.

This paper deals with the Gullfaks A Subsea Production Systems: Philosophy, development plan, technical and functional descriptions and Statoil's experience to date in the various phases, including start up. The wells are connected to the Gullfaks A platform, which is a PDQ (processing, Drilling and Living Quarters) Platform. Subsea operation were accomplished. THE GULLFAKS FIELD The Gullfaks field is situated 140 km from Norwegian mainland (Figure No. 1). The field appraisal drilling showed that the reservoirs are heavily faulted with a main north-south fault through the whole field. Recoverable reserves of the Gullfaks field are assumed to be 210xI0 6 Sm3 (1,320x106 Bbls) of oil and 23X109 Sm3 (812x109 SCF) of gas. The water depth at the field varies from 13(to 220 meters. GULLFAKS A SUBSEA DEVELOPMENT PLAN – Develop reservoirs outside the efficient reach of the platform wells. Figure No. 2. – Accelerate production and improve economic returns. – Gain information and experience for future field developments. The scope of the subsea part of the GullfakS A Project has changed from: (Information available in full paper) These changes are due to increased knowledge from the drilling of the subsea wells and new reservoir simulations. The subsea wells are of a wet satellite type non-TFL (non-thru-flowline); However, wireline serviceable. The same Christmas tree is used both for production and water injection. Each well is connected to the platform with a separate Flexible flowline, a hydraulic umbilical and an electrical umbilical. The system is designed to be diverless, i.e. a11 tools required for installation and workover are non-diver assisted. The design life of the subsea production system is 10 years. The plan for the development, installation at start-up of the Gullfaks A subsea systems are shown in Figure No. 3. SATELLITE SYSTEM The main components of the satellite system as shown in Figure No. 4. They consist of:protective structureChristmas tree Systemsatellite control moduleworkover systemtools allowing for diverless installation and workover. The Gullfaks A satellite system is a new development Protective Structure The protective structure is an open frame type structure allowing ROV access. It has been designed to deflect fishing gear, with a high probability, and is piled to absorb 100 tons anchor dragging loads. A removable roof is fitted to the structure to provide overhead protection. The structure is shown in Figure No. 5. Additional protection is installed in the pull in areas after pull in and connection. Wellhead & Tubing Hanger Prior to start of drilling operations, the protective roof is removed by a guideline establishment tool. In a single run, the tool establishes guidelines to the four main guideposts and retrieves the protective roof. An 18 3/4", 10,000 psi CAMERON WS-11 weight set wellhead system is used in the subsea wells. A 5-string casing programme is used, comprising 30", 20", 16", 13 3/8" and 10 3/4" casing strings. The tubing hanger system allows the tubing hanger to be run, orientated, tested and locked in one trip.

After several downhole sand control failures in subsea wells,1 the Okwori field development underwent a significant change of direction both topside and sub-surface. Numerous constraints were taken into account and successfully managed: tight rig schedule, complex logistics, contractual issues, etc…. Downhole, the original multi-zone, fully selective sand control completion system hat included sand screen expanded inside casing was abandoned. A new system was designed that allowed similar selectivity but with open-hole sand control. The new completion system implied a change in drilling practices, reservoir drill-in fluid and cake cleanup techniques that required simultaneous engineering. These in-depth modifications were designed and implemented in a matter of months. Topside, the FPSO had not been equipped to deal with sand production since downhole sand exclusion was assumed to be reliable enough. A sand management study recommended a series of modifications that minimized production shut-down while safely handling the produced sand and oil. Test de-sanding using a temporary sand trap determined that sand produced from weak formations could be stabilized. Severe service chokes were installed allowing production at a constant liquid rate. Experience accumulated to date highlights the importance of appropriate planning and application of reliable technical solutions in subsea completions. Introduction Due to the high associated costs, subsea well development concepts are usually "interventionless". The initial costs of these wells are mainly due to the mobilization and day rates of sophisticated drilling rigs. To re-enter subsea wells, similar rigs are required, hence the prohibitive cost of well intervention1. This is the driver behind declaring these wells "interventionless". Once the "interventionless" nature of these wells has been stated, it is presented as a challenge to well engineering. To provide a reliable solution, the most robust techniques for construction and completion are required. As subsea wells are expensive, each completion must give access to sufficient reserves for economical justification. in sacked and compartmentalized structures, sufficient reserve per completion means complex wellpaths penetrating multiple targets as beads threaded into a necklace. When co-mingling is not an option and sand exclusion is required, these wells also become host of expensive jewelry. We know since 1948 2 that more equipment is run in a hole, the more can and will go wrong. Hence the interventionless concept becomes the "Quest for the Holy Grail" of engineering. This pursuit translates into a risk based search for the best engineering practices and proven technologies that are compatible with the project economics, combined with best practice implementation. Risks that could adversely affect the project must be mitigated and required measures must be implemented so that the project remains economical throughout its life. In the Okwori project offshore Nigeria, the Addax Petroleum and service provider personnel tackled all of these issues in record time. A Complex Subsurface Okwori subsurface is far from the traditional image of a big oil anticline into which wells are positioned to maximize recovery. Okwori field is a chaotic ensemble of superimposed hydrocarbon and water bearing pools that are separated by faults3. Today, more than 250 fault-dip closures have been identified, 59 of them with proved hydrocarbon content. For additional information, please refer to references 3 and 4. Figures 1 and 2 illustrate the highly compartmentalized nature of the field both laterally and in depth. To access these scattered reserves the development plan called for dispersed well-head locations, hence a subsea development with each well being individually tied back to a central floating production separation and offloading vessel (FPSO).

Recent trends in offshore field development have been toward subsea completions, especially in the North Sea. It is estimated that the number of subsea wells in the North Sea will double by 1994. Since subsea wells are often completed in the same formations as conventional offshore wells and completion designs are the same, downhole service requirements for subsea wells are generally the same. Semi-submersible rigs using tensioned risers have offered the only practical means of performing vertical intervention services such as wireline and reeled (coil) tubing. A subsea reeled tubing system (SRTS) has been designed and manufactured that offers a more economical means of performing a range of reeled tubing services on subsea wells. The SRTS is operated from a diver support vessel (DSV) or other relatively small vessels in lieu of a rig which effects a considerable savings in cost and time. A tensioned riser is not required with the SRTS. This paper describes the SRTS in detail and discusses the reeled tubing services offered by the unit. Safety features and operational procedures are also discussed.

The Burullus Gas Company, a sister company of the Rashid Petroleum Company (Rashpetco), operates the West Delta Deep Marine Concession. (WDDM) on behalf of partners: Egyptian Government Petroleum Corperation (EGPC), BG Group and Edison Gas. This paper describes the first deepwater offshore completion operations conducted in Egypt as part of the Scarab/Saffron development. The two fields are located in water depths ranging from 400 to 650m and are situated some 90km offshore the Nile Delta. The development consists of 8 vertical sub-sea wells that were drilled and completed to depths ranging from 1800 to 2100 meters TVDSS. The original budgeted time for the completion operations was 36 days per well. The last well to be completed took less than 14 days, which approached the perceived technical limit for the operations. The paper will provide a detailed description of the completion operations and the lessons learned for this development. It will also identify a number of improvements and modifications that were implemented This paper will focus on the completion operations from sand phase completion to clean up and suspension operations Introduction The Burullus Gas Company, a sister company of the Rashid Petroleum Company (Rashpetco), operates the West Delta Deep Marine Concession (WDDM) on behalf of partners EGPC, BG Group and Edison Gas. The concession contains the Scarab and Saffron Reservoirs, discovered in 1997. The fields are located in water depths ranging from 400 to 650m and are situated some 90km offshore the Nile Delta. This is the first deepwater gas field development in Egypt. Phase 1 of the development consists of 8 vertical sub-sea wells that were drilled and completed to depths ranging from 1800 to 2100 meters TVDSS. (Figure-1) Scarab Saffron represents a significant milestone for the Egyptian Oil and Gas industry, as it is the first advanced subsea development. Development of the fields commenced in the later part of 1999. A number of the development wells were pre-drilled in 2001 to obtain early reservoir information to assist in the completions design. Completion operations commenced in April 2002. Considerable focus was given to the adoption of "best practices" for efficient drilling and completion installation through use of the BG Group's Total Value Drilling (TVD) initiative. With operating costs approaching US$200,0000 per day, a major part of the well cost is rig time. As a result, a considerable amount of time was spent optimizing the well design and thus reducing the operational sequence to minimize rig time. Completion operations have shown a significant learning curve and best in class performance resulting in the final sub-sea completion being run in under 14 days. This has resulted in estimated saving of over $20m in the overall drilling and completion costs against the overall project budget. (Figure-2) Completion Design Sand Control The reservoirs comprise a number of unconsolidated, highly permeable sand channels of plio-pleistecene age within El-Wastani formation. A comprehensive database of information on these formations has been collected during exploration and appraisal drilling. Data from logs and well tests has shown a tendency for sand production even at low drawdowns. Sand control therefore formed an integral part of the completion design.

Operators with subsea developments on the Norwegian Continental Shelf have the last 20 years aimed for better efficiency and reduce equipment and personnel needed on the rigs in relations with subsea completions. Drivers have been reducing HSE risk, reduce need for modifications on the rigs to accommodate for subsea related equipment such as reels and workover control systems, and reduce cost, rig time and emissions. Many measures have been implemented such as removing need for landing string and wireline operations with deep-set pump-open or disappearing barrier plugs, installing Intervention and Workover Control system (IWOCS) to operate all systems suppliers’ tools from same unit, use of ROV Workover Control System (RWOCS) subsea HPUs to control the Xmas Tree (XT) to remove the tree running tool (TRT) umbilical, developing a hydraulic-electric remote operated control system communicating on wired drill pipe to the tubing hanger running tool (THRT) to remove the need for THRT umbilical and IWOCS, to mention some. This paper describes one of the last inventions; a mechanical tool for installation of tubing hangers (TH) that also removes the need for remote communication and hence dramatically reduces complexity and potential for faults. The mechanical tubing hanger running tool is called THRUT and has been developed by CCB Subsea in cooperation with Equinor. First umbilical-less subsea completion ever run with a THRUT was successfully conducted on the Equinor's Heidrun field on well E-2 from the Transocean Encourage drilling rig in March 2022. Following the first well, the THRUT has been run on 8 more wells for Equinor and 3 wells for Norske Shell. The tool concept is accommodated to interface to any kind of subsea horizontal XT (HXT) systems delivered by either Aker Solutions, TechnipFMC, OneSubsea, BakerHughes, or other system suppliers. And also, the tool is operated offshore by the subsea system supplier in charge of the subsea completion, no extra personnel from CCB Subsea is required offshore. Result is an efficient and robust tool with profile of low risk, low cost and less personnel needed. The paper describes the philosophy and requirements for the system design, the device functioning, and method for mechanical umbilical-less installation of TH in subsea HXTs, and also summarizes the most important results and operational experiences with regards to the advantages related to HSE, time, cost, personnel need, logistics and rig interface.

Sex ratio plays a critical role in population survival. Dioecious plants may simultaneously display sexual dimorphism and deviations from the equilibrium expectation of 1:1 sex ratio in populations, that is, biased sex ratio. However, whether biased sex ratios can be attributed to sexual dimorphism has not been well investigated. Here, we conducted experiments using a three‐water‐depth gradient to examine sexual dimorphism performance and population sex ratios for Vallisneria natans , and investigated the variations in natural population sex ratios for it and two other congeners V. spinulosa and V. denseserrulata along water depth changes. Females of V. natans had higher reproductive investment than males, and the degree of sexual dimorphism increased with increasing water depth. At greater water depths, increased reproductive expenditure led to higher mortality in females, resulting in a male‐biased sex ratio. The sex ratios of natural V. natans and V. spinulosa populations did not significantly deviate from 1:1. In contrast, populations of V. denseserrulata exhibited markedly a female‐biased sex ratio, which may be attributed to female plants producing more clonal ramets. Furthermore, no evidence was found for variation in sex ratios along water depth gradients in natural populations of any of the three species. These findings highlight the plasticity both of sexual dimorphism and sex ratios in dioecious plants, indicating that sex ratios are species‐specific and depend on sex‐specific life‐history strategy shaped by their growth environments.

1. A quantile regression model for counts of breeding Cape Sable seaside sparrows Ammodramus maritimus mirabilis (L.) as a function of water depth and previous year abundance was developed based on extensive surveys, 1992-2005, in the Florida Everglades. The quantile count model extends linear quantile regression methods to discrete response variables, providing a flexible alternative to discrete parametric distributional models, e.g. Poisson, negative binomial and their zero-inflated counterparts. 2. Estimates from our multiplicative model demonstrated that negative effects of increasing water depth in breeding habitat on sparrow numbers were dependent on recent occupation history. Upper 10th percentiles of counts (one to three sparrows) decreased with increasing water depth from 0 to 30 cm when sites were not occupied in previous years. However, upper 40th percentiles of counts (one to six sparrows) decreased with increasing water depth for sites occupied in previous years. 3. Greatest decreases (-50% to -83%) in upper quantiles of sparrow counts occurred as water depths increased from 0 to 15 cm when previous year counts were 1, but a small proportion of sites (5-10%) held at least one sparrow even as water depths increased to 20 or 30 cm. 4. A zero-inflated Poisson regression model provided estimates of conditional means that also decreased with increasing water depth but rates of change were lower and decreased with increasing previous year counts compared to the quantile count model. Quantiles computed for the zero-inflated Poisson model enhanced interpretation of this model but had greater lack-of-fit for water depths > 0 cm and previous year counts 1, conditions where the negative effect of water depths were readily apparent and fitted better with the quantile count model.

The performance of single slope basin type solar still is low and the efficiency is in the range of 30%. Experimental investigations were carried in a basin type solar still varying water depth from 2 cm to 10 cm under the open environmental conditions. The effect of basin water salinity on the performance was also tested for 3000, 5000, 10000, 15000 and 20000 ppm. It is observed that with increase in depth of water and salinity thermal efficiency decreases. The convective, radiative and evaporative heat components from water surface to glazing were evaluated. It is found that evaporative heat component decreases with rise in depth and salinity of the basin water, which has the key role to enhance the yield.

Traditionally any re-entry of a subsea completion for downhole maintenance or data gathering has involved the use of a semi-submersible drilling rig or Through Flow Line (TFL) techniques. The drilling rig is slow to mobilise and is generally over equipped for the task, reducing its cost effectiveness. The TFL option increases the complexity of the well, requires a high initial capital outlay and is unsuitable for production logging. This paper describes a subsea wireline system which can be deployed from a dynamically positioned monohull vessel providing a low cost, flexible alternative. This system has been used in an extensive wireline and production logging operation in the UK northern North Sea, demonstrating its versatility and its potential for providing a fast response with major cost savings. INTRODUCTION There are currently some 400 subsea completions worldwide and with the trend towards subsea production systems, particularly for marginal field developments, this number is predicted to increase significantly over the next decade. The use of a drilling rig with a conventional BOP stack and a tensioned tie-back riser has a number of significant drawbacks when used for well servicing. Transit speeds are slow, anchor handling operations are time consuming and support vessels are required. Hence the overall cost is high and has precluded all but the essential work required to maintain production. Consequently the procurement of reservoir data has generally not been attempted unless it could be combined with infrequent mechanical work on the well. Permanent downhole gauges have been used, however their long term reliability is unproven and the resultant data has been limited to pressure and temperature measurements at a single depth. The expansion in subsea developments has created a need for a cost effective, self contained, well service system which can be rapidly mobilised to carry out a wide range of well intervention tasks. The subsea wireline lubricator system was developed to meet this need and allows a complete range of slick line and electric line downhole operations to be carried out on subsea wells from relatively smaller dynamically positioned vessels. In fact the development of a subsea wireline system has been ongoing for nearly 20 years. In 1970 joint trials were carried out by BP, ADMA and CFP (Totan, using a Flopetrol designed Subsea Wireline Lubricator (SWL), which was deployed on a subsea well in the Zakum field, offshore Abu Dhabi, in 65 ft of water. It was not until 1984 that a SWL was deployed commercially in the much harsher environment of the North Sea. This SWL was developed by BP, using some of the Flopetrol components, to service the subsea wells on the template beneath the Buchan Alpha moored semi-submersible production platform. The Buchan field is located in a water depth of 375ft, in the UK central North Sea. Following successful wireline operations on the template wells in the field in 1985, a project was initiated with a wireline company (Camco) and a vessel operator (Stena) to develop a handling system to enable the Buchan SWL to be deployed on satellite wells from a dynamically positioned Diving Support Vessel (DSV).

Introduction Atlantic Richfield Co. is now operating eight subsea wells offshore Louisiana. These wells are in the Eugene Island Block 175 field, about 70 miles southwest of Morgan City, La. Average water depth for the field is 85 ft. These wells were among the first to be installed as subsea completions in the Gulf of Mexico. The wells were drilled and completed as three-string completions between 1966 and 1968. All wells are producing from multiple pay zones and are flowing to a common production platform located 1 to 3 miles from the wells. production platform located 1 to 3 miles from the wells. Routine service work on these wells, such as pulling and inspecting storm chokes, cutting paraffin, etc., is done by the flowline pumpdown techniques from the production platform. The wells were originally completed with special platform. The wells were originally completed with special cross-over ports that allow the tubing strings to communicate in the well just above the top packer. This feature allows tools, similar to wireline tools, to be pumped down the flowline and into the tubing strings of pumped down the flowline and into the tubing strings of the wells and to be pumped back out and returned to the production platform. Three subsea wells required production platform. Three subsea wells required remedial work because of normal reservoir depletion and various mechanical problems. This paper presents basic assumptions in the planning phase and summarizes the work performed to move in the workover rig and to establish contact with the well. Planning Phase Planning Phase In the planning phase, rig selection was of major importance. A three-leg jackup rig without a bottom barge was selected as the best rig for this job. One of the prime reasons in selection of this rig was its ability to cantilever the derrick 25 ft beyond the hull of the barge. Equally important was the ability to skid the derrick in a lateral position 16 ft. This feature allowed the barge to be positioned 15 to 20 ft from the well and eliminated the dangerous positioning of the rig with tugboats. Another problem concerned how to establish contact with the well after the Christmas tree was removed. Two alternatives were available:utilize underwater blowout preventers and bring a low-pressure riser from the blowout preventers to the rig, orconnect a highpressure riser to the wellhead and use standard blowout preventers on top of the riser. The latter method was preventers on top of the riser. The latter method was selected, but a high-pressure riser was unavailable and one had to be built. The wells had to be in a safe condition to move the rig on location in the event of an accident. Drilling fluid was to be circulated down the wells to kill the well before moving in the rig. This was done from the production platform by circulating the fluid down the production platform by circulating the fluid down the flowlines and into the wells. Several planning meetings were held with the drilling contractor, the subsea Christmas tree manufacturer, and the diving company. These meetings were not only beneficial to company personnel but essential in teaching the divers the tools and techniques to be used to establish contact and to remove the Christmas tree from the water. Moving Workover Rig on Location Before moving the rig on location, divers were sent to inspect the sea bottom in the immediate vicinity of the well and in the area where the rig would be stationed. At this time, flowlines leading away from the wells were buoyed and the Christmas tree was marked with a buoy. JPT P. 445

Offshore operators tie successful subsea exploratory wells into field plans when possible and have used a variety of adaptation bases to complete the wells. The expense and complexity of these bases led to redesign of the subsea wellhead/- guidebase system to make completion less expensive and easier. Equipment described includes a universal 30" housing, retrievable drilling guide structures, and completion guide structures. Styles and procedures for diver/Remote Operated Vehicle-assist, diverless guideline, and diverless guidelineless installation are reviewed. In addition to achieving cost savings by reusing the retrievable drilling structures, two-stage guide structure systems described here allow custom design of the completion structure/ flowline assembly after the field development plan is finalized. INTRODUCTION (Figure 1) Subsea wellhead systems have been used for over 20 years for exploratory and development drilling. Two recent changes in operator's standard development programs have required design changes in the wellhead system to make exploratory well drilling equipment adaptable for subsea completion without large initial capital investment. The first change in common development programs has been to incorporate successful discovery wells into field development plans. In diver depths, these wells have been historically completed subsea with relatively simple adaptation bases landed over the existing guide base that include flowline connection and tree alignment provisions. Beyond diver depth, adaptation bases are complex and expensive, sometimes requiring a tubing spool adapter. This requires an additional wellhead connector and introduces a new set of seals with consequent leak path potential. The second change is to include satellite subsea completions in field development plans. When drilling a subsea well with completion a certainty, a flowline receptacle adaptation system can be incorporated in the drilling guide base. However, the well is usually drilled 6 to 12 months in advance of completion equipment manufacture. Close manufacturing tolerances and expensive test jigs are required to insure fit-up of the completion tree and flowline receptacle. Adaptation systems, whether for wells preplanned for completion, or discovery wells, also have the disadvantage of potential tree landing problems if excess cement or other debris has collected around the permanent guide structure during drilling. For these reasons, new retrievable drilling and completion guide bases were designed to simplify completing subsea wells, making the operation less expensive and more reliable. After drilling a well, the drilling base is retrieved, leaving the 30" housing ready to receive a completion base. The universal 30" housing provides a simple interface with known manufacturing tolerances. The completion base is manufactured as a part of the completion system, allowing complete fit-up testing at the factory and on the rig installing the completion equipment. Several types of retrievable drilling and completion bases have been designed allowing for diver/ROV assist and diverless guideline and guideline less drilling and completion.

The present paper describes the basis and applications of some gas lift troubleshooting techniques being used in the production operations of Lake Maracaibo field, Venezuela. By integrating simple physical models and analytical procedures, engineers are able to diagnose a broad range of gas lift wells. The presented techniques have been applied successfully on a large amount of gas lift wells, making them an alternative to some methodologies that appear in the literature. Representative field cases have been included to illustrate the explanations.