An Operational Subsea Wireline System

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).

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.

This paper presents the concept and the technical solutions developed and applied to the Ormen Lange subsea production system. First, the key technical challenges related to the subsea system are presented. Thereafter the paper describes the extensive design, fabrication and testing processes undertaken in order to verify correct functionality and gain confidence in the applied solutions. Finally the paper summarizes achievements and key success factors for the project. Introduction The Ormen Lange field is located in the Norwegian Sea, approximately 100 km off the northwest coast of Norway. The field is located within a prehistoric slide area, the Storegga Slide, with water depths reaching 850 meters in the main production area. The selected development concept for Ormen Lange comprises a subsea tieback to an onshore processing plant at Nyhamna as shown in Fig. 1. Fig. 1 Ormen Lange initial subsea development (Available in full paper) The gas will be produced from up to 24 subsea wells. The well fluid will be transported to the Nyhamna plant via two 30" multiphase lines. After processing, the dry export gas is transported from the onshore plant through a new 42" pipeline via the Sleipner riser platform and further through a new 44" pipeline to the gas-receiving terminal in Easington, England. Overall project schedule. The conceptual engineering of the subsea production system was initiated in 2002. The main contracts for subsea equipment supply, umbilical fabrication and template installation were awarded between the autumn of 2003 and the summer of 2004. The main part of fabrication and testing took place during 2004/2005 with the subsea templates installed offshore in the late summer of 2005. Umbilical A and remaining subsea equipment were installed during the summer of 2006 and the first Xmas tree was installed on Template A in December 2006. Completion of the first subsea well on Template A is scheduled for spring 2007 and subsea production start-up scheduled for autumn of 2007. Subsea system configuration. Due to the large geographical extension of the Ormen Lange reservoir and the risk of reservoir segmentation, the subsea system design has a high degree of flexibility with four planned template locations. For this reason, a phased development scheme has been chosen. The phasing and location of the subsea wells will be timed to maintain plateau production as the field depletes. Initial development. The initial subsea development consists of two 8-slot production templates (A & B), located approximately 4 km apart in the main production area. Each template is tied back into the two 30" multiphase pipelines to shore. The two 30" lines are interconnected via a pipeline end termination system (PLET) as shown in Fig. 2. Two main control umbilicals link the onshore plant to the subsea production system; one is connected to template A, and the other to template B. A crossover control umbilical interconnects the two production templates, providing redundant hydraulic supply to all the subsea wells. For prevention of hydrate formation, all wells are continuously injected with monoethylene glycol (MEG) via two 6" pipelines from the onshore plant.

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.

The North East Frigg (NEF) gas reservoir is a small satellite of the giant Frigg gas field located in the North Sea in 100 meters of water. NEF gas reserves are to be developed using a subsea production system, this being the first major underwater gas production project ever attempted in the North Sea. The purpose of this paper is to describe the NEF subsea development concept, to explain the ration for its selection and to mention possible applications of this system in the development of other marginal fields. The NEF subsea production facilities comprises of four major components:–a subsea template which houses and protects six wells and a manifold–a 16" gas line which links the manifold to the Frigg Field Treatment platform (TCP2)–a Field Control Station (FCS) whose main function is to control the subsea equipment–treatment, metering and boosting modules installed on the TCP2 platform to process the 6 million cubic meters per day of NEF gas. Different development schemes were evaluated during the preliminary selection studies:–conventional fixed steel structure–subsea wells drilled and controlled from a permanent semi submersible platform moored above the wells–subsea wells and manifold remotely controlled from Frigg field–subsea wells remotely controlled from an unmanned articulated column installed close to the well cluster. The last scheme was selected as being the best optimization in terms of:–Operational safety mainly due to separation of critical functions–Reliability of gas production by extensive use of conventional and tested equipment although assembled in a novel configuration–Investment costs–Potential adaptation of the concept to future developments of marginal fields To date, detailed engineering of project components is completed, fabrication and drilling are in progress. The production start-up is scheduled in 1984. Introduction Recent shortages and uncertainties in oil/gas supplies and the related price increases have transformed some unprofitable, marginal and/or difficult fields into commercial ones. In this context Elf Aquitaine Norge (EAN) and its Partners initiated the NEF development studies for producing a satellite of the giant Frigg gas field. This opportunity combined with the present necessity to develop economically attractive concept for producing marginal fields in a difficult environment led to an unconventional approach. Preliminary studies began in 1979 with final decision being made mid 1980. Detailed engineering design of the various sub-systems is now completed. Fabrication of NEF components and the drilling of the wells are in progress. Production start up is expected in 1984.

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.

Heave motion of supporting ships deeply affect the normally operating, safely launching and recovering of remotely operated vehicles when the sea state becomes rough. A heave compensation system can uncouple the heave movement between supporting ships and remotely operated vehicles. An active heave compensation system which includes a measurement unit, a controlling unit and a hydraulic winch is researched in the paper. For attaining the efficiency of the active heave compensation system, simulating model is built and the computer simulation is achieved. The computer simulation proved the effectiveness of the active heave compensation system. For verifying the correctness of the simulating model and acquiring the efficiency of the real active heave compensation system, an active heave compensation experiment system which includes a heave motion generating unit, a load and an active heave compensation system is built. The movement which created by the heave motion generating unit simulates the heave motion of the supporting ship. The load is a substitute of the underwater vehicle. The result of the active heave compensation experiment certifies the correctness of the simulating model and the effectiveness of the active heave compensation system.

One of the largest components of the cost of deepwater (greater than 1,500 ft water depth) subsea developments is the day-rate of the drilling rig spread, combined with the substantial costs of the normally required installation tools and other equipment that must be installed on the rig during completion work. In an effort to reduce these substantial capital costs, Shell has used several combinations of drilling vessels (mobile offshore drilling units - MODUs) and construction vessels over the past several years and has rented and in some cases purchased some specific pieces of equipment. Shell has also studied the entire completion process thoroughly, identifying opportunities for improving effiency and eliminating all but essential activities. These efforts have proved worthwhile, saving literally millions of capital dollars over four most recent major subsea projects in the Gulf of Mexico and promising to greatly improve the profitability of its future subsea projects. Introduction Shell began estimating the costs of the first deepwater subsea developments in the early 1990s and several portions of the cost areas were highlighted for immediate further study. As these study efforts grew, standardization of subsea equipment and value engineering quickly began to show promise, but it was evident that this would require a substantial investment of time and considerable cooperation from the leading industry suppliers. However, investigating the more efficient use of existing equipment -- such as the MODU spread itself and improvements in the design/use of the existing equipment that have been historically required during well completions -- promised immediate substantial savings. After its initial experiences with Tahoe, 1,500 feet water depth (fwd), Popeye, 2,040 fwd, Mars, 2,900 fwd, and Mensa, 5,200 fwd, Shell continued its focus on improving the profitability of subsea developments, capturing the learnings from these projects and applying them to the early planning stages of the next group of subsea projects. Specifically, Shell concentrated its efforts at several specific targets, such as:Efficient utilization of the MODU on location (deck layouts, subsea tree handling equipment capabilities, interfaces with completion tools/equipment)Proficient use of existing tools and procedures ("Technical Limit Completion" exercises)Development of new more efficient tools (more efficient completion riser designs, use of a larger winch for lowering subsea equipment packages to the seafloor, a subsea-releaseable blowout preventer [BOP] funnel)Overall technical review of the entire completion process (unloading the well to the pipeline, instead of conventionally unloading to the rig) This paper will present the results of the work in these target areas, highlighting the successes and describing in detail the extraordinary breakthrough engineering ideas that surfaced during this effort. Background Shell completed its first Tahoe deepwater subsea development project utilizing 4th generation MODUs built in the mid-1970s. The next several subsea projects utilized similar MODUs with variable deck loads averaging from 3,000 tons to 4,500 tons. With the Popeye and Mars subsea wells at 2,040 fwd and 2,900 fwd, respectively, deck space was already a critical issue, along with limited crane capacities for lifting the required equipment onto the rig from supply boats.

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18965, "Ormen Lange Subsea Production System," by Thomas Bernt, Hydro, and Endre Smedsrud, FMC Technologies, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May. The Ormen Lange field, in the Norwegian Sea, approximately 100 km off Norway, is within the prehistoric Storegga slide area with water depths reaching 850 m in the main production area. The gas will be produced from up to 24 subsea wells. The well fluid will be transported to the Nyhamna plant through two 30-in. multiphase lines. After processing, the dry export gas will be transported from the onshore plant through a new 42-in. pipeline by way of the Sleipner riser platform and further through a new 44-in. pipeline to the gas-receiving terminal in Easington, England. Introduction Fig. 1 shows the development concept selected for Ormen Lange, which comprises a subsea tieback to an onshore processing plant at Nyhamna. Conceptual engineering of the subsea production system was initiated in 2002. The main contracts for subsea-equipment supply, umbilical fabrication, and template installation were awarded between the autumn of 2003 and the summer of 2004. The main part of fabrication and testing took place during 2004–05, with the subsea templates installed offshore in late summer 2005. Umbilical A and the remaining subsea equipment were installed during the summer of 2006, and the first subsea tree was installed on Template A in December 2006. Completion of the first subsea well on Template A was scheduled for spring 2007, and subsea production startup was scheduled for autumn of 2007. Subsea-System Configuration With the large geographical extent of the Ormen Lange reservoir and the risk of reservoir segmentation, the subsea-system design has a high degree of flexibility, with four planned template locations. Therefore, a phased-development scheme was chosen. The phasing and location of the subsea wells will be timed to maintain plateau production as the field depletes. Initial Development. The initial sub-sea development consists of two eight-slot production templates (Templates A and B), approximately 4 km apart in the main production area. Each tem-plate is tied back into the two 30-in. multiphase pipelines to shore. As Fig. 2 shows, these lines are interconnected through a pipeline-end-termination (PLET) system. Two main control umbilicals link the onshore plant to the subsea production system; one is connected to Template A and the other to Template B. A cross-over-control umbilical interconnects the two production templates, providing redundant hydraulic supply to all the subsea wells. To prevent hydrate formation, all wells are injected continuously with monoethylene glycol (MEG) through two 6-in. pipelines from the onshore plant. One line is connected to Template A and the other to Template B. A 6-in. crossover-MEG line interconnects the two production templates for added flexibility.

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 project was initiated in 1987 to develop the Turret Moored Production System (TUMOPS) concept for:developing offshore fields in remote locations where in-field storage with shuttle tanker export is required,early/phased developments, andshort-term field developments, where relocation is possible. During the first phase of the project, alternate configurations for the system with varying water depths, number of wells, storage capacities, and drilling/workover facilities were investigated [1]. This paper provides a follow-up to [1] and describes the second phase of project which focused on further defining key system components, including the subsea system, the turret and fluid transfer systems, and the combination mooring/thruster stationkeeping system, for one set of field parameters; and culminated in the development of a conceptual design for an example field offshore Norway. INTRODUCTION TUMOPS represents the combination of technologies developed during years of industry experience with ship-based floating production systems, turret-moored drillships, and the existing turret-moored production test ship [2]. The basic system arrangement consists of a production ship, which supports a full drilling/workover system and process facilities, positioned over subsea template wells, as shown in Figure 1. Flexible risers connect the production ship to the subsea wells. The turret mooring system allows the vessel to maintain the best heading relative to the wind, wave, and current conditions, thereby providing good motion characteristics for both production and drilling/workover operations. The ship also provides crude oil storage for up to seven days of production. The produced crude is offloaded to a shuttle tanker for transportation to shore. During Phase I of the project, various configuration alternatives of the system were developed for water depths of 125, 300, and 500 meters, and production rates of 25,000, 50,000 and 75,000 barrels of oil per day (BOPD). Subsea systems for both a manifolded subsea and a non-manifolded subsea case were designed. Facilities required for a range of drilling/workover capability, from "light" workovers (wireline and coiled tubing) to a fully equipped drilling facility, were also investigated. The main conclusions of Phase I were as follows [1]:The basic TUMOPS concept is technically feasible.Full drilling capability can be supported by the production ship.The turret can support up to 20 flexible risers.Further work is justified to refine designs and confirm costs for key system components. The second phase of the project focused on the design of key system components, including the subsea system, the turret and transfer systems, and the stationkeeping system, for a given set of field parameters. Additionally, offshore installation activities and operation of TUMOPS were investigated. Completion of the Phase II work, as described herein, provided a conceptual design basis for an example field offshore Norway. TUMOPS CONCEPTUAL DESIGN BASIS The Phase II TUMOPS conceptual design is based on development of a representative oil field offshore Norway in a water depth of 125 meters. The production ship will accommodate the facilities to support simultaneous production, drilling/workover, and offloading operations for up to 42 subsea wells.

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.

After most operators quit using Pin connector, Riser and Diverter for safety reasons, when drilling the tophole section of subsea wells, the use of seawater and sacrificial mud with return to seafloor has to date been the only available practical method. The development of AGR's Riserless Mud Recovery System (RMR) enables drilling the tophole section using weighted inhibited drilling mud. Hence, a number of benefits, such as: Improved hole stability, reduced wash outs, improved well control both with regard to shallow gas and shallow water flow are obtained. Also clay and sand deposits from the boreholes on subsea production templates are prevented. A Demo 2000 project to qualify the RMR System was therefore approved and a Joint Industry project (JIP) was established funded by the Norwegian Research Counsel, Hydro, Statoil and AGR. The JIP was established to qualify the RMR technology for use in 450 meters of water depth. The Demo 2000 project objective was to enable drilling tophole sections collecting returns subsea, and returning to surface in a closed system. A Suction Module with a low pressure rotating control head was installed on the template. This Suction Module collected and diverted the well return into a subsea mud pump lifting the stream of mud and cuttings to the rig processing system. The RMR spread was run through the moon pool on a single derrick rig, and guided and stabilized by a heave compensated guide wire extending to a subsea anchor. Ref. System Schematic, Fig 1. The equipment was engineered and manufactured within an 8-month period, and the field trial took place in December 2004. The paper also discusses the fluid system used, the operational benefits and limitations by applying the RMR technology. Introduction Most operators have abandoned the use of Pin Connector, Riser and Diverter when drilling surface holes for both safety and operational reasons. Especially when drilling deep-water wells, using seawater and gel sweeps being dumped on the seafloor has to date been the only viable solution. In production drilling this has led to the use of Cutting Transport Systems (CTS) or subsea ejector pumps to remove the well returns to a distance from the subsea templates. To allow the use of weighted and inhibited mud for improved bore hole stability, well control and preventing the drill cuttings and cement returns to be dumped on the subsea template and or seafloor, AGR developed a Tophole Drilling Package named RMR - Riserless Mud Recovery System. A Pre- Engineering phase was completed in 2002. This served as basis for establishing the design basis and defining the scope of work when applying for Demo 2000 funding in 2003, to demonstrate and qualify The RMR system for 450 meter water depth by offshore field testing. At the same time as the RMR Demo 2000 project was initiated, AGR was requested to design and build a Riserless Mud Recovery System for BP to be tested on the West Azeri field in The Caspian Sea.

Handling drilling and production waste associated with oily contaminated drill cuttings, NORM and produced water is an environmental and economic issue in offshore drilling and production operations. There are a number of waste management options and subsea injection into suitable geological formations can be a preferred one. This is because it can achieve zero discharge operations; eliminating transportation and spill risks. It can also be economically favorable. Although subsea drill cuttings and produced water re-injection operations have been conducted in an environmentally acceptable manner, system design and operational experience are limited. A few worldwide drill cuttings re-injection operations from mobile offshore drilling units are reviewed first in the paper. Lessons learned from these and other system design and operational experience include a detailed subsurface study and careful engineering, wellhead and injection system design and effective communication to handle emergency disconnect, quality control on well integrity and slurry injection procedure. Challenges and best practice guidelines for waste injection operations from subsea wellheads are given to minimize failure and maximize success. Introduction Growing environmental regulations and constraints put pressure on drilling operations to find environmentally friendly and economically sound solutions for handling drilling waste. Drill cuttings re-injection (DCRI) operations into suitable geological formations have been successfully implemented all over the world.1–13 Figure 1 shows a schematic of DCRI process. Briefly, the drill cuttings from shale shaker are milled to small particles (300 microns or less), in the presence of water, usually seawater or other wastewater. The resulting waste slurry is pumped into sub-surface fractures created by injecting the slurry under high pressure into the disposal formation. Depending on drill cuttings generation rate, the waste slurry is injected either continuously or intermittently in batches. A continuous slurry injection scheme is expected to lead to an extended disposal fracture, while periodic re-injections would promote the development of multiple fractures and thus a compact domain of smaller multiple fractures from the wellbore. The batch process consists of intermittent injections of roughly the same volumes of slurry and shutting-in the well after each injection. This allows the disposal fracture to close onto the cuttings and to dissipate any build-up of pressure in the disposal formation. This may be impractical when re-injecting into low leak-off shale as the target disposal horizon when drilling rates and thus the slurry generation rates are relatively high. In practice, therefore, re-injections may shift from essentially continuous mode during drilling of large hole sections to periodic as the cuttings generation rate declines with the well approaching TD. Although drill cuttings re-injection has been applied since early 1980s, these operations have mostly been restricted to fixed platforms; annular re-injection into subsea wells, where drilling operations were in progress, had not been feasible until early 1993. BP, through a Drilling Engineering Association (DEA) JIP, conducted the first field trial DCRI operation in March 1993 into the annulus of a subsea well from a mobile offshore drilling module unit (MODU).14, 15

Block H, located in 1,300 meters of water depth at offshore Sabah, consists of Rotan and Buluh fields. The subsea trees, jumpers, manifold, umbilicals, risers and flowlines were installed and tied-back to an FLNG facility. The objective of this project was to develop most practical and effective solutions to overcome flow assurance challenges owing to low seabed temperature and high-pressure gas to achieve 1st gas from the first deepwater gas field in Malaysia. A model was built in OLGA software with all field conditions to run simulations and predict process parameters at every critical point in subsea wells, risers and flowlines as well as topside facilities. Besides, all constraints from the subsea wells, jumpers, risers and flowlines all the way to topside inlet receiving facilities were carefully reviewed and optimized with an abundance of caution to determine the stepwise approach by utilizing the high-pressure gas from wells to remove around 1,000 m3 of pre-filled MEG fluid out of the flowline, called ‘DeMEG operation’ before feeding gas to LNG process operations. With 200-230 barg pressures from deepwater gas wells and 2-4°C temperature at seabed as well as pre-existing water content in saturated gas given by reservoir aquifer, this start-up operation would expect to be in the hydrate zone. One of the unavoidable potential consequences was a hydrate formation and could result in plugging of jumpers, risers or even flowlines. The DeMEG operation results indicated the lowest temperature at the downstream of the subsea choke was −23°C due to Joule-Thompson cooling during the cold start. One mitigation strategy was to inject a batch of MeOH at the subsea wellhead until the temperature is above the hydrate point. After the gas flowed along the flowlines, it would cool down to the seabed temperature during the steady state condition. Hence, additional mitigation was to continuously inject Mono Ethylene Glycol (MEG) as another thermodynamic hydrate inhibitor mixed with gas stream. The MEG affixed water molecules and thus deterred them from forming a cage around gas molecules to prevent hydrate formation. A multi-stage DeMEG operation was carefully planned to overcome liquid handling capacity at topside and eventually executed at offshore until the remaining MEG in the flowline was as low as reasonably practical to proceed with gas production from the field. With an excellent collaboration from the team and proper planning, the DeMEG solution together with hydrate mitigation strategy were proven to be effective and the commissioning operation was successfully completed as per the plan until the 1st gas was achieved on 6-Feb-21 and supplied to FLNG. The 1st LNG drop subsequently came in 7 days later. This field has increased production volume around 270MMSCFD, equivalent to 45,000 barrels of oil per day to PTTEP and JV partners.