Coiled Tubing Operations From Monohull Floating Production Units

Of the three subsea wells, drilled so far at the Oseberg field, two wells (drilled in 87/88) have a slight deviation to the true vertical, while the third well has been horizontally drilled (91) in the Gamma North Reservoir. This well will be producing gas for injection into the Oseberg Alpha Reservoir, To enable service of horizontal parts of this last drilled well, use of coiled tubing operations will be necessary. When introducing coiled tubing in operations with X-mas tree and completion/workover riser from a floater, a safety problem occurred with respect to shut in of the well, This ended up with the Subsea Well Intervention BOP (SWIB) where Ram Blow-out-preventer technology was used. Additionally, in order to ensure safe operation in case the floating rig drifting off location, an Emergency Quick Disconnect Package (EQDP) was placed on top of the SWIB. INTRODUCTION The Gamma North reservoir was developed by Norsk Hydro and its five partners*, as part of the Oseberg phase two development, and completed in October 1991. The Oseberg Field is located in blocks 30/6 and 30/9 in the Norwegian Sector of the North Sea. The Gamma North Structure, part of block 30/6, was decided to be developed with one subsea well, in order to exploit its gas reserves for reinfection into the main Oseberg reservoir. However, the nature of the structure also allowed the development of a thin oil layer, which required the drilling of a horizontal section of approximately 700 m. This means that the subsea well, located approximately 9 km. away from the Oseberg C platform as shown in Fig. 1, initially will be producing 10.000bbl/d (max) of oil through an 8" pipeline before the gas production starts. Additionally a 3" service line and an electro-hydraulic umbilical were installed connecting the Gamma North satellite to the Oseberg C platform. The philosophy for all the subsea equipment in the Oseberg Field is to be able to interchange the equipment between the various wells (two subsea wells B49 and B50 were put in operation in 1988). When completing the horizontally drilled Gamma North well, only minor wireline operations were possible, To be able to service the horizontal part of the well, use of coiled tubing operations are necessary. When this was brought forward, the equipment did not comply with the operating philosophy safetywise. The need for more sophisticated cutting mechanism to cut coiled tubing was looked for. Since the similarity between drilling operation and coiled tubing operations are striking when coming to pressure control, it was obvious to use the same well-known drilling BOP technology for coiled tubing operations. This led to the development of the SWIB, Subsea Well Intervention BOP. The new Subsea Well Intervention BOP was put on order in May 1991.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180065, “Thermal Effects on Subsea Wellhead Fatigue During Workover Operations,” by L. Cantinelli Sevillano, J. De Andrade, S. Sangesland, and M. Stanko, Norwegian University of Science and Technology, prepared for the 2016 SPE Bergen One Day Seminar, Bergen, Norway, 20 April. The paper has not been peer reviewed. Intervention and workover operations can significantly affect the structural integrity of subsea-wellhead systems with regard to their fatigue life. The increasing frequency of these operations has called for a renewed focus on the fatigue capacity of subsea wells, which has greatly improved the overall methodology used for wellhead-fatigue analysis. However, thermal effects along the well have yet to be incorporated. This paper analyzes wellhead-fatigue damage during a workover operation considering the thermal effects. Methodology The goal of the present study is to investigate the effects of the temperature variation along the well on wellhead-fatigue- damage rates by incorporating the temperature profiles of casing strings and cement into the fatigue-damage assessment of a particular wellhead system during a workover operation. In this study, a decoupled approach is proposed. The temperatures of riser, wellhead, and well components are calculated for different instants during the workover operation using a finite-difference method. Then, the temperature profiles for a given moment during the operation are incorporated into a 3D finite-element model (FEM) of the wellhead system. A structural analysis with focus on stresses at the fatigue hot spots is performed. Subsequently, a dynamic analysis of the riser provides the loading time history to which the wellhead is subjected; finally, combining the results of the structural analysis and the riser-response analysis enables the fatigue damage during the simulated operation to be estimated. The well adopted in this study follows a conventional subsea-completion program on the Norwegian continental shelf, with four casing strings and a production liner. Temperature Calculations. It is assumed that enough time has passed—between the shutting down of production and the moment that the workover riser is connected to the wellhead and the workover operation begins—for the temperature in the well to reach the undisturbed geothermal temperature profile. The workover operation simulated for temperature calculations consisted of injecting and circulating a heavy fluid until the hydrocarbons in the well were displaced. After that, circulation was stopped. The temperature profiles were calculated with a finite-difference method. During the simulated cold-fluid injection into the well, the deepest sections of the well are subjected to the largest temperature drop, given that the fluid is at lower temperature than the surrounding formation and well fluid, while the uppermost sections experience the effects of a circulating fluid at a higher temperature. Circulation was deemed to last approximately 3 hours.

Since its discovery in 1969, the Ekofisk Area has developed into one of the most industrious oil centers in the North Sea. The Ekofisk Area presently encompasses twenty-five permanent platforms of which eleven are production/injection platforms with over 125 active wells. To date, 113 workovers have been performed on these wells. Production from the Ekofisk Area peaked on February 8, 1980, when 618,000 BOPD and 1,860 MMSCFD gas were produced. Development drilling activity peaked in late 1979 when there were ten active drilling or workover rigs on nine platforms. Today, there are four drilling and workover crews active in the area. Reservoir depletion and compaction and the resulting seabed subsidence have altered drilling and workover operations over the past six years. This paper discusses how current drilling and workover practices have evolved in the Ekofisk Area.

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

This paper describes an operational subsea wireline system that is self-contained and flexible and offers a safe, economical, and proven method for riserless re-entry into any subsea well. The system discussed here was developed over a number of years and has been used to carry out a comprehensive range of wireline tasks from floating vessels in the North Sea. Although generally deployed from a diving support vessel (DSV), the system has been successfully used from a drilling rig to conduct wireline operations in a well, simultaneously with workover operations in an adjacent well, on a subsea template.

The Morpeth field is developed using three satellite subsea production wells and one water injection well clustered together in a line with 50 ft well spacing. The cluster of wells produces to a SeaStar mini-TLP located approximately 1500 feet to the North. The satellite wells produce through individual flowlines linked near the trees by pigging loops, reflecting a concern with wax deposition and hydrate prevention and remediation. The subsea wells are controlled through two umbilicals from the SeaStar. Introduction Unlike a subsea satellite tieback to an existing surface facility, the Morpeth subsea production system is designed as an integral part of the initial field development influencing both the surface facility and the field layout. The design of the surface facility and hull reflect integrally designed provisions for flowline and umbilical installation. Dedicated space is provided for a coiled tubing unit to be used for removing flowline blockage. The field layout is designed to accommodate rig anchoring around all flowline, pipeline, and umbilical paths, for initial design and future tie-ins (Fig. 1). The schedules for installation activities and drilling and completion activities are integrated to optimize the time to first oil. A great deal of emphasis is placed on operability of the system and flow assurance. The system operating procedures were generated early, reviewed and revised periodically during the system design. An operations person was employed as part of the project team early in the project. The operations crews were mobilized as part of the site team during the shore integration of the facilities and all the subsea production procedures were reviewed and critiqued in detail. The selection of the subsea engineering group within the main field installation contractor extends a philosophy of minimizing the number of interfaces and contracts that the intentionally small BBEI team is required to manage. The installation contractor is responsible for the design of the subsea production system, purchase of the equipment and installation of most of the equipment, with an advisory role in equipment installed from the BBEI-contracted drilling rig. The Morpeth subsea production system comprises three subsea production trees, one subsea water injection tree, two direct hydraulic control umbilicals with individual wires for instrumentation, three insulated flexible production risers and one water injection riser. The wells are controlled at the surface facility using a PLC driven combination hydraulic power unit and well control panel. The "fast-track" nature of the project requires decisions on configuration to be made early. Long lead-time components have to be ordered based on non-optimized conservative criteria. Everywhere possible, field proven equipment and installation methods are utilized. No changes in concept and minimal changes or restarts of design effort were required during the project execution. Design Requirements Several key design requirements and philosophies are reflected in the design of the Morpeth subsea production system. Subsea wells. Utilizing subsea wells allows the SeaStar to be a smaller, more simple design. Flexibility in the project schedule is required so drilling does not have to be completed prior to facility installation. The project economics are aided by shorter time to first oil and by simultaneous drilling and production.

In an effort to minimize capital investment in platform installations there is an increasing trend towards drilling subsea satellite wells, with production tied back to an existing platform. A disadvantage with this type of well is that regular access for maintenance and reservoir monitoring is denied by the high cost of conventional techniques. This paper, which discusses some new techniques for economic monitoring and maintenance of subsea wells, is divided into two sections. The first section describes the installation and use of permanent gauges run with the completion in subsea wells. Methods of mounting the pressure gauge in the completion string and transmission of the data to surface are discussed. A field case is reviewed which highlights some of the advantages of continuous reservoir monitoring. The second section of the paper describes a newly-developed technique for wireline logging in wells completed subsea. The method involves a specially designed lubricator and pressure-control system which can be deployed from a dynamically positioned support vessel. The discussion is focused on the practical aspects of the technique, as well as giving an overview of the types of operations that can be performed.

A computer software package for simulating coiled tubing operations has been developed at Rogaland Research. The software is named CriTi-CAL, for Critical Coiled Tubing Calculations. It is a PC program running under Microsoft Windows. CriTi-CAL is designed for predicting force, stress, torque, lockup, circulation pressure losses and along-hole-depth corrections for coiled tubing workover and drilling operations. CriTi-CAL features an user-friendly interface, integrated work string and survey editors, flexible input units and output format, on-line documentation and extensive error trapping. CriTi-CAL was developed by using a combination of Visual Basic and C. Such an approach is an effective way to quickly develop high quality small to medium size software for the oil industry. The software is based on the results of intensive experimental and theoretical studies on buckling and post-buckling of coiled tubing at Rogaland Research. The software has been validated by full-scale test results and field data.

The introduction of the RamRig concept signifies, by its radical new design, a number of substantial savings to both the construction and operation of drilling and workover rigs for the petroleum industry. The RamRig can be used for floating and fixed installations and eliminates the need for large derrick with drawworks, drillstring compensator etc. This novel concept can be used as a small workover to full scale drilling rig and opens perspectives for new ways of drilling wells and for improved economy in future offshore field developments.

Oil fields in southern Iraq contain a wealth of the country's oil and gas reserves. Wells which were left uncompleted represent a valuable asset that needs to be utilized quickly and efficiently in order to increase the production of those fields. Through a carefully orchestrated operation involving workover rigs, rigless stimulation packages and gas lift packages, a complex project of completing key oil wells in one of South Iraq's oil fields was performed on time and with excellent results. Those results were achieved despite adverse technical, logistical and safety restrictions. The project scope involved the use of workover rigs then rigless operations for perforation, stimulation and gas lifting (if required) of 30 wells in West Qurnah oil field in southern Iraq. The operations scope covered the use of three workover rigs to pull existing completions, run cased-hole logs and set the permanent production packers. After the rig moves to the next well, the rigless team works on completing the job in terms of perforations, acidization, gas lifting (when required) and flowing the well for cleanup prior to being put back on stream. The project's operation phase duration was 5 months. Through the adoption of project management techniques, a rigorous project plan was set up aiming at aligning all involved parties towards successful implementation. The plan involved the alignment of facilities (camp and acid mixing plant), Equipment (4 workover rigs and 3 coiled tubing units), stimulation and gas lift packages (2 acid pumping units and 2 Nitrogen pumping units), consumables (completion strings, acid, additives and perforation) and personnel (12 different teams from operating and service companies) was essential for the successful implementation of the project plan. The project management had to keep the best means of coordination and communication with various parties involved at all times in order to orchestrate the project on time and minimize the non-productive-tine (NPT). Careful planning was applied to streamline the operations among all involved workover rigs and rigless operations units to optimize the operations while maintaining the highest standards of quality, health, safety and environment (QHSE) measures. The stimulation and gas lift part of the project was planned and deployed based on detailed well by well review of the wells under consideration. Fundamental well data (well design information, formation pressures and formation fluid information) were examined and quality assured before designing the suitable stimulation package aiming for a high success rate of the treatment.. Professional analysis of the operation results both on the job and after the job was used to improve the learning curve and obtain better results in the succeeding wells. This paper discusses how to apply novel project management style of planning complex field- wide workover operations to the highest quality and HSE standards, while managing to complete the project ahead of the planned project deadline

Offshore oil and gas production and processing facilities are prone to incidents such as leakage which may escalate thus causing major accidents. These accidents pose a serious threat to personnel and assets. Previously, accident modelling has relied on studying a single event and its impact. It has been witnessed from past events that accidents are caused by combinations of events and therefore, accident modelling must consider multiple sequences of events and interdependent factors. The Floating Liquefied Natural Gas (FLNG) is a complex processing facility where a leakage of liquified natural gas (LNG) may escalate to a range of events such as fire to vapor cloud explosion. The escalation of events is dependent on the multiple intertwined factors evolving with time and space. This study is focussed on developing novel methodologies and models to study the transitional events and their causation during a major event in complex LNG processing facilities. This thesis outlined an extensive literature review and analysis of offshore and marine safety from the perspective of fire and/or explosion accidents. It analysed various causes of fire and/or explosion accidents and proposed a series of countermeasures with respect to different causes. The impact of the cryogenic temperature of LNG on steel structure during its accidental leakage has not been extensively studied. This study modelled an LNG pool formation and the impact of cryogenic temperature on a structural material during an accidental release of LNG. The study confirmed that an instantaneous LNG pool formation does cause immediate failure, however, this may significantly minimise design life of the structure and due attention is needed throughout its service life particularly in the spilled area. Literature review showed that minor leaks occur frequently, and they are often overlooked assuming that they are inconsequential. However, in the case of LNG, it can be too simple to ignore small leak due to the potentiality of causing suitable scenario for fire and explosion event upon rapid vaporisation after the leakage. This study proposed a novel technique for modelling fugitive leakage of LNG in a processing facility. The developed methodology is applied considering three different degrees of congestion and revealed that higher congestion levels present higher flammable hazards than the lower levels of congestion within the acceptable congestion level. As fire is the main cause of accident in oil and gas processing facilities, this study proposed a novel methodology for modelling fire impact assessment in a typical FLNG processing facility using Computational Fluid Dynamics (CFD). Three most credible fire accident scenarios were chosen from among various fire scenarios considered in the FLNG facility. It is found that the scenario in the Mixed Refrigerant Module in the liquefaction process presents the highest risk of fire to both on-board personnel and assets. In a complex processing facility, there is a high likelihood of occurrence of transitional scenarios such as hydrocarbon release, fire, explosion and dispersion of combustion products. Finally, this study modelled potential transitional events and their integrated impact during an accidental release of LNG. This study revealed that in a complex processing facility, transition of events is highly possible, and the impact of such events can be more severe than that of the individual event. This study serves as a comprehensive source of knowledge and technique on which to model various accident scenarios. The study of these scenarios assists in better understanding of accident causation and improves design to prevent causation of such events. The study also provides a practical approach to design safety measure to control and mitigate hazards when prevention is challenging. This thesis will serve as a guiding book to better design of processing facilities and safety measures for a complex processing facility.

From September 2006 to a August 2007, a proof of concept test of ET-DSP ™ (Electro-Thermal Dynamic Stripping Process) was completed by E-T Energy Ltd. A numerical simulation study was done prior to the field test to quantify performance metrics, such as the amount of water usage per m3 of produced oil, the energy input requirements, kW-hr/m3 of oil (i.e. an equivalent Steam Oil Ratio value), green house gas emissions, drilling performance, operating costs, and process facility design. Field performance met or exceeded expectations. The recovery factor was greater than 75%, the energy requirement per m3 of oil produced was 23% less than calculated and peak production rates were greater than expected. The water oil ratio was one with no green house gas emissions in heating the oil. An insignificant volume of sand was produced and the oil recovered had very little to no emulsions. A comparison of the data with theory reveals that not all the drive mechanisms were considered in the initial numerical simulation. One of the more significant is the contribution of associated gas. Albeit in relatively small amounts, the gas evolving from the bitumen with rising temperature displaced the bitumen from the pore volume and accelerated recovery from the production wells. Introduction Electrical-thermal heating of the Alberta oil sands has been studied since the early 1970's [1],[2],[7],[6],[8],[4]. Heat is created in the bitumen reservoir as electrical current passes through the connate water as depicted in Figure 1. At low frequency, the reservoir behaves like a resistor, and the conversion of electrical energy to heat is by ohmic losses. This paper compares data from a pilot test of the Electro- Thermal Dynamic Stripping Process, ET-DSP ™ process [4] with numerical simulation (details are published in reference [5]. Construction and operations of the test was carried out from September 2006 to August 2007. The objectives of the proof of concept are to:Determine the percent Recovery Factor, Ro,Establish the Energy Oil Ratio (EOR), i.e., the kWh/bbl of produced bitumen.Determine the water consumption on a per barrel of produced bitumen, Water Oil Ratio m3/m3, (WOR),Confirm numerical simulation temperature predictions, AndDevelop equipment and facility design basis, well completions, operating procedures, and economic parameters for commercial development. Table 1 summarizes the comparison between numerical model predictions and results from the pilot test. The recovery factor achieved in the proof of concept was within the model prediction. The energy consumption was less than the model predicted by 23%. Converting the energy in terms of an equivalent Steam Oil Ratio, SORe = 0.49, or a Net Energy Ratio (NER) of 30 times more energy produced in the bitumen than used to produce it. The ratio of water used per produced barrel of bitumen was predicted to be one; slightly less than one was achieved in the proof of concept. A comparison of the modeled and actual temperature response at observation well (OB05) is shown in Figure 2. OB05 is located approximately mid way between the electrode wells.

Marlim Field is located in the northeastern portion of Campos Basin, offshore Brazil, in water depths ranging from 600 m(1,968 ft) to 1,100 m (3,608 ft). The field was discovered in September 1984 by the wildcat 1-RJS-219 A, in 853 m (2,800 ft) water depth. The areal extent of Marlim Field is 152 Km2(52 mi2). The main objective of this paper is to give a general outlook of the drilling, completion and workover operations in Marlim Field. It reviews well design development, drilling progress and the associated costs from the field earlier appraisal wells till the most recent development wells drilled in the area. The paper also describes the evolution of completion with emphasis in the work done in improving well design, minimizing problems and optimizing operations. The main causes of intervention are listed and described. Finally, the future plan for Marlim Field that includes the utilization of technologies such as extended reach, slender and multilateral wells is also depicted. Introduction Since the drilling of the wildcat well 1-RJS-219A in 1984, many developments related to drilling technique were obtained in Marlim Field. Improvements in well design, drill bits, drilling fluids and the use of new technologies helped to increase well safety, cut cost and raise oil production. The evolution of Completion on Marlim Field occurred basically on subsea tree installation systems and its connections to flowlines, methods of sand control, horizontal well completion and reservoir pressure monitoring with permanent downhole gauge. Installation of subsea tree and its connections has undergone three different techniques. It started with the Lay Away method, passed by the Vertical Connection method and nowadays it is being done with the Direct Vertical Connection method. Like in most very deepwater field, Marlim unconsolidated sandstone reservoir is a sand producer. Due to its peculiar characteristics, tools, procedures and technologies were customized to achieve good performance on sand control in vertical, directional and horizontal wells. To obtain regular pressure and temperature data from subsea wells with wire line gauges from a completion rig is economically unfeasible. The alternative is the permanent downhole gauge (PDG). At first the mean time before failure (MTBF) of the PDG systems installed in Marlim was very low. After changes on management and equipment the performance of this system improved a lot. The goal is to equalize the MTBF of PDG to the mean time before workover. Drilling Well Design and Operational Procedures - In the earlier stage of the drilling in Marlin, when few data were available, one of the main causes of preoccupation was related to the shallow and unconsolidated sediments. Initial designs used the common practice of jetting 48 or 46" pipes. The difficulty of handling and controlling the passage of these heavy pipes through the rotary table soon made the engineers look for other options. In 1992, the designers substituted the 46" pipes for a 42" housing and conductor pipe of 13 meters length resulting in reduction of time and consequently cost. In 1993, the designers decided to jet a 30" casing having a floating shoe at the end. This procedure not only proved to be better and more acceptable solution, but also reduced remarkably the time of the first phase as shown in Fig. 1.

Technology Update Intervention is necessary during the life cycles of most subsea wells. However, traditional methods can make it time consuming and very costly, with spread rates for drilling and semisubmersible rigs running at USD 1 million to USD 1.4 million per day. There are more than 4,000 producing subsea (wet tree) oil and gas wells worldwide, and the number is increasing by approximately 500 per year. With many wells more than a decade old, intervention is crucial to enable maximum oil and gas extraction. The sustained rise in deepwater exploration has made the need for cost-effective intervention on wet well trees even more pertinent. With the challenging conditions encountered in deep subsea settings such as Asia, Brazil, West Africa, and the Gulf of Mexico, many wells have produced for several years without necessary intervention. This often results in suboptimal production and reduced ultimate recovery. The AX-S system, developed by Expro, is designed to provide a safe, riserless, and remotely operated subsea well intervention method that can complete a typical deepwater intervention in six to eight days, compared with 10 to 12 days for a rig intervention, at a cost savings of approximately 75% to 80% based on lower day rates and speedier job completion. The system, designed and built over a seven-year development period with the input of more than 200 vendors, is in the final commissioning stage. Commercialization is expected later this year. Deployed from a monohull vessel (Fig. 1), the system is the first rigless intervention technology that can operate in waters up to 10,000 ft—several hundred feet deeper than the world’s deepest subsea well. The improved economics afforded by the system will allow operators to increase production and recovery rates in wet tree wells that otherwise might wait additional years for interventions. To enable deployment of the system, Expro has entered into a multiyear charter party contract with TS Marine Asia Pacific to use its dynamically positioned (DP) multiservices vessel Havila Phoenix for worldwide operations. The DP 2 Class vessel is 361 ft long and 75 ft wide with a moonpool of 23.6 ft by 23.6 ft, a 94-ton fiber rope drum winch with deployment tower, a 276-ton wire rope subsea crane, and two ultraheavy-duty Work Class remotely operated vehicles (ROVs) rated to more than 13,000 ft. The winch and crane are equipped with active heave compensation systems.

Deepwater technology has been creeping up the learning curve as the different oil and gas operators move out into deeper and deeper water depth. With the new technology comes new ways of performing older more routine jobs. EEX became the first company to decommission and abandon a deepwater development project. Being first, they had to find new and better ways to do the work. The use of a non-drilling intervention vessel that was self-powered and dynamic positioning simplified the project and allowed EEX to save money and time over the estimated time and money required for a conventional drilling rig and derrick barge approach to the problem. Discussion As the Gulf of Mexico development activity moves out into the deeper waters, operators must find more cost-effective ways to exploit the oil and gas resources. Service companies must also change to meet the challenges that are found in the deepwater Gulf of Mexico. In 1998 EEX Corporation (EEX) recognized that the Garden Banks 388 Field, in 2,100 feet of water, was maturing and would be reaching its economic limit by mid-1999. Management at EEX began reviewing the techniques needed to properly decommission and abandon the field. In shallower waters, the decommissioning and abandonment of a producing field has evolved from the use of large rigs and extensive management / logistics procedures to a more stream lined procedure with a turnkey or specialist in the decommissioning and abandonment process. The end result is the same, sometimes better, but the time required to complete the task and the cost of the operation is cut dramatically. In many of the cases the wells can be plugged and abandoned with a coil tubing unit and a wireline / logging unit, rather than using a large drilling or workover rig. The larger drilling / workover units could take one to two weeks to rig up and place in operation and many found that the equipment was overkill for the nature of the operation. Coil tubing and wireline / logging units often can be rigged up in a matter of hours and the plugging and abandonment operations could be completed in less time than it took to rig up the larger units. To say the least the time and cost savings were significant. EEX felt this same evolution was possible in the deepwater environment. Decommissioning EEX wanted to be able to have the FPF and the FSR decommissioned and brought back to the dock, by late August or early September, to avoid the peak of the hurricane season. By doing so, it would reduce the risk of damage to equipment or the loss of valuable time due to possible bad weather. The Floating Production Facility (FPF) was used to decommission the production equipment, riser, manifold, jumper lines, flowlines and sales lines running to Eugene Island 315. Seawater was used to flush the system and it was pumped into the wells to push the wellbore fluids into the formation and establish the injection rates for each of the wells.