Technology Focus: Offshore Production and Flow Assurance

Technology Focus Creativity and innovation have long characterized production and facilities, and this year is no exception. Much of the work reported this past year was conducted during the recent period of low oil prices. The economic challenges of the oil industry clearly have provided a strong stimulus for even more creativity and innovation. The use of big data and analytics appeared in a number of papers with an emphasis on the use of artificial intelligence (AI) for building databases used to monitor the health of equipment and structure risk-based-inspection (RBI) strategies. Monitoring data inputs from thousands of sensors (paper OTC 28990) allows an AI application to predict an impending failure and notify operators by text or email when the incipient problem is detected so that proactive maintenance can be scheduled to avoid an unplanned shutdown or catastrophic failure. This strategy is being successfully applied to compressors but no doubt will be used to monitor other high-cost, critical service equipment as well (paper SPE 188803). Progress continues on the design and application of inflow-control devices (ICDs). Introduced only a few years ago, these devices are still in a rapid development stage for both design and application. Now, ICDs are applied successfully to improve the fluid-injection patterns for both steamfloods and waterfloods, the latter being described as a successful field application (paper SPE 189824). For steamfloods, passive and autonomous ICD designs were evaluated and their performance modeled using computational fluid dynamics (paper SPE 189721). The integration of subsurface modeling and surface-facility design by the development of a data-driven stochastic work flow (paper SPE 187462) demonstrated a means to reduce both subsurface and facility costs by reducing the biases that inevitably come into play during the generation of a field-development plan. Other innovative work was reported on field optimization, the prediction of asphaltene precipitation, and the integration of RBI with vibration-induced fatigue failure of installed piping systems. Interesting work not discussed here includes evaluating corrosion under severe conditions and the development of an oil-droplet-coalescing pump for use in water treatment. Recommended additional reading at OnePetro: www.onepetro.org. SPE 188803 Machines Performance Algorithmic Modeling for Anticipating Machines Health Using Real-Time Condition-Monitoring Data by W. Almadhoun, ADMA-OPCO, et al. SPE 189721 Evaluation of Inflow-Control-Device Performance Using Computational Fluid Dynamics by M. Miersma, University of Alberta, et al. SPE 187256 Production Optimization of Shenzi Field in the Deepwater Gulf of Mexico by P. Ashton, BHP, et al. SPE 190149 A Diagnostic Approach To Predict Asphaltene Deposition in Reservoir and Wellbore by Davud Davudov, University of Oklahoma, et al. OTC 28352 Integrating an RBI Approach for Vibration-Induced Fatigue Into a Mechanical-Integrity Program by Paul Crowther, Wood, et al.

The enormous cost of handling the challenges of flow assurance in subsea wells, flowlines, and risers, especially in deepwater applications, has necessitated a proactive approach to prevent their risk of occurrence. To ensure that transportation of the hydrocarbon is economical and efficient from the subsea wellhead to the processing units, a flow assurance heat management system is relevant in the design and planning of a fluid transport system. Consequently, the advancement of new technologies to serve the increasing need by exploring the technologically challenging and hostile subsea fields is of great importance. A comparative study on heat management systems in flowlines was conducted from the top five publishers (Elsevier, Springer, Taylor & Francis, Wiley, and Sage) based on the number of publications to determine the level of work done by researchers in the last decade, the figures from the study showed the need for scientific research in the field of active heating. Additionally, a review was implemented to ascertain the likely advantages and drawbacks of each technique, its limitations concerning field applications and then recommend suitable cost-effective technique(s). The active heating system gives the most cost-effective solution for subsea deepwater fields.

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.

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.

The Ursa and Princess oil fields lie in the Mississippi Canyon (block 810) of the Gulf of Mexico about 130 miles south east of New Orleans. Both fields produce to a common host, the Ursa Tension Leg Platform, moored in approximately 3,800 ft of water. Ursa production wells were completed with dry tree direct vertical access (DVA) while Princess utilizes wet tree subsea wells tied back about four miles to the host through dual insulated flowlines and risers, as shown in Figure 1. Production at Ursa began in 1999 and Princess in 2004 with both fields producing from the main Lower Yellow (LY) and secondary Sub Yellow (SY) reservoirs. Currently, seven wells are producing from the LY and two from the SY. A waterflood of the LY, comprising four subsea injectors (two in Ursa and two in Princess), was initiated in 2008 in order to replace voidage and improve sweep efficiency and hydrocarbon recovery. Recent successful production wells in Princess coupled with the waterflood response have created a bottleneck at the subsea flowlines. At current operating conditions, this restriction means that future projects would be have to be deferred as they cannot fully deliver gains due to the back out of existing production. In addition, an earlier screening study had identified Princess as a strong candidate for subsea boosting in order to increase production from existing wells. The asset team therefore initiated a de-bottlenecking and subsea boosting assessment that was carried out by a multidisciplinary team. A subsurface team formed a part of the greater multidisciplinary team. One of the tasks of the subsurface team was to deliver production functions for each of the screened re-development concepts. Production was one of the key inputs in evaluating economics which in turn was a primary driver of the concept selection decision. While the re-development concepts were specifically for the Princess field, the expectation was that changes there would influence hydrocarbon recovery from Ursa as the two fields are in pressure communication within the main LY reservoir and both benefit from waterflood support. This study also needed to include future Princess subsea wells targeting additional accumulations not in communication with the LY or SY as part of the re-development. These reservoirs are expected to have a range of different initial pressures and contain hydrocarbons of varying properties. Hence, it became clear at the start that there were several dependent and independent moving components and constraints that had to be considered together to get an accurate assessment of the systemic effects that would influence total production. The team therefore decided to build an integrated production model, containing the entire production system from reservoirs to topsides, to obtain production functions for the screened concepts.

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 132909, ’Sand Settling and Locations of High Erosion in Subsea Production System,’ by S.A. Shirazi, SPE, and B.S. McLaury, University of Tulsa; E. Sow, SPE, BG Group; and M. Butter, SPE, A. Folefac, SPE, and S.A. Hassaballa, Rashpetco, originally prepared for the 2010 Trinidad and Tobago Energy Resources Conference, Port-of-Spain, Trinidad, 27-30 June. The paper has not been peer reviewed. When higher-than-expected sand volumes were produced from Gas Field 1 after a second well group was brought on line, it was believed initially that the sand production came from these new wells. Sand-transport studies demonstrated that the sand was produced by the first well group, rather than the second, but that the sand was not being transported through the main export lines until after the second well group came on line and gas velocities through the flowlines increased. Introduction The subsea wells in Gas Field 1 are completed with downhole sand control because of the unconsolidated nature of the reservoir sands. The gravel-pack completions are designed to stop sand but allow some fines production to prevent plugging of the gravel packs and screens and, hence, loss of productivity. Some solids production was expected over the life of Gas Field 1. However, after a second well group was brought on line in 2005, higher-than-expected sand production was observed. The first effect of sand production was the erosion of a valve downstream of a 36-in. slug catcher 6 months after the first well of the second group came on line. Because the produced solids may cause further erosion damage at locations of high production velocities, it was essential that the sand production be investigated and acceptable erosion rates be determined. A fines-management program was put into place following the first detection of solids production. Sand-Settling Calculations Studies were conducted to determine if there is a potential for sand to settle inside flowlines and transport pipelines. Calculations were performed for producing wells in the first group and second group and for the transport and export lines. Initial calculations were conducted in the production system for the second group of wells because sand production was observed first soon after these wells came on line. Earlier calculations showed that sand was not settling anywhere in the wells or in the subsea infrastructure from the wells in the second group to onshore. Therefore, the calculations focused on wells from the first group that had been produced since 2003. The first step in the sand-settling calculations was to gather historical production information and determine gas- and liquid-flow rates and the appropriate flow regimes in various pipe sections. The findings indicated that there are primarily two possible flow regimes in horizontal sections—stratified flow and slug flow. Experience with flow loops has indicated that sand settling is more prominent in stratified flow than in the slug-flow regime. Therefore, calculations assumed a stratified-flow regime. To make sure that sand can be transported even if a liquid film does not exist in the pipe, calculations also were performed for a mist/gas-flow regime.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 183383, “Integrated Off-Bottom Cemented Inflow-Control-Device System Design Toward Well-Delivery Optimization,” by Mohammed A. Al Madan and Mazen Bu Khamseen, Saudi Aramco, and Hedy Suherdiana and Ahmad Al Abdulmohsen, Baker Hughes, a GE company, prepared for the 2016 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 7–10 November. The paper has not been peer reviewed. Off-bottom-cementing (OBC) operations are unique to Saudi Arabia and represent a very challenging approach to drilling and workover operations when deployed in combination with inflow-control devices (ICDs) across horizontal sections. The multitasking-valve (MTV) feature in upgraded ICDs offers safe, simple, and cost-effective deployment operations. This paper discusses the first deployment of an ICD system combined with an OBC system for a workover operation in a mature producer well in the Kingdom of Saudi Arabia. Introduction In wells where an OBC liner is required to cover nontargeted formations above the production zone, two methods of deployment can be used: the one-trip system and the two-trip system. These refer, respectively, to whether the OBC components are deployed in a single trip along with the ICD or in a second trip with string in the previously deployed ICD completion. The one-trip OBC ICD completion does not allow an inner-string application. Therefore, circulation while running in hole was ineffective in this producer, which caused deployment problems. The two-trip OBC ICD completion was then considered. The idea was to split the completion into a lower ICD completion, which is dropped off inside the openhole horizontal section with a setting sleeve. The earlier two-trip OBC ICD completion used an inner string, a circulating system, and an openhole-packer-setting tool. This allowed 100% circulation from the shoe during deployment of the lower ICD completion, although circulation rate is limited because of pumping through the small internal diameter (ID). The upgraded ICD with an MTV allows the lower completion to be deployed without an inner string while achieving 100% circulation at the shoe, which smooths operations and saves up to 24 hours of rig time. The MTV temporarily blocks the communication between string and annulus while running in hole. Once reaching the setting depth, MTVs are actuated by hydraulic pressure. All hydraulically set equipment can also be set at this point. Ultimately, in the case outlined in the complete paper, it was decided to combine once again the separated deployment into a single system by use of the MTV feature, which provides important functions for the one-trip OBC ICD completion—the ability to perform 100% circulation from the shoe and to set all hydraulic downhole tools with one setting ball.

This paper presents experience of subsea and marine systems gained from the first four years of production from the Ivanhoe/Rob Roy fields focusing particularly on those areas which are different from a fixed platform development. As an introduction the overall field layout is described and the success of the development is demonstrated by summarising availability of the facilities. The paper then describes the field development work since first oil, together with the inspection, repair and re-design work that have been necessary to ensure this success. The description includes work on all facilities on the sea bed, work on marine systems, and subsea well servicing. It thus includes the hull, stability and damage stability, bilge and ballast systems, subsea Christmas trees, moorings, flexible risers, flowlines and jumpers, valves, chokes, electro-hydraulic control system, umbilicals, downhole gauges, etc. The information can be used to lead towards more cost effective developments in the future.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 208988, “Novel Application of Abrasive Jet Perforating To Restore Productivity of a High-Potential Inactive Horizontal Oil Producer,” by Sadaf S. Chishti, SPE, Steven H. Craig, SPE, Baker Hughes, and Edward J. Wheatley, SPE, ADNOC, et al. The paper has not been peer reviewed. The complete paper illustrates a novel methodology that enabled the safe application of coiled tubing (CT) abrasive perforation to increase production in a sour horizontal extended-reach (ER) oil producer. The well was underperforming at 10% of the anticipated production rate because of a damaged lower completion. To avert a costly workover, abrasive perforation with CT was selected as a safe alternative to conventional explosives-based perforating conveyed on electric line. Introduction An offshore horizontal ER producer well was drilled with a total depth (TD) in excess of 24,000-ft measured depth (MD). During the completion phase, a 4.5-in. liner with 16 inflow control devices (ICDs) and eight swellable packers was run with the ICDs in the closed position. Swellable packers were placed after every two ICDs. To open these ICDs, an internal pressure of 2,500 psi was required, achieved by dropping a ball that would seat in the float collar. Multiple attempts were made to pressure up and open the ICDs without success. The decision was made to run the upper completion with a plan to activate the ICDs using rigless CT intervention. After a drift CT run, multiple attempts were made to run a through-tubing inflatable packer bottomhole assembly (BHA) on CT to isolate and pressure up the well. All attempts failed to reach target depth, with repeated holdup at approximately 20,273-ft MD. Production-logging passes performed in injection mode determined that the well interval between 20,262 and 20,300 ft was taking more than 80% of the injected fluid. In a subsequent CT logging run, a caliper log identified that the liner section in this interval was parted and identified an openhole section with washouts in excess of 7-in. inner diameter. The results from the log are shown in Fig. 1, with the enlarged section representing the parted liner/openhole interval. Because the ICDs remained closed along with a damaged liner section, the options of recovery leaned heavily toward a rig-based workover for sidetrack and recompletion. Considering time and cost constraints, studies commenced to identify an efficient alternative to establish flow contribution from the inactive compartments by adding perforations. CT was chosen as the conveyance method based on previous success in reaching TD, and three options were evaluated. Based on the lowest risk level and availability of resources, the safest and most-viable option was abrasive perforation with CT. This technique uses a sand jet perforator, a downhole tool that uses high-pressure abrasive-laden fluids to penetrate the casing, liner, and cement and extend a cavity into the reservoir.

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212939, “A Proven and Versatile Coiled Tubing Live-Well Intervention Solution From a Monohull Vessel in the Norwegian Continental Shelf,” by Kjetil Austbø and Stein Kristian Andersen, Equinor, and John Stuker, SPE, SLB, et al. The paper has not been peer reviewed. _ The complete paper describes the use of a riser for coiled tubing (CT) operations from a monohull vessel already performing riserless well interventions (RLWI). The project was developed by the operator, an intervention-vessel company, and several service providers. The solution covers 200- to 500-m water depths and converts back to riserless operation after CT operations. Introduction The operator has more than 600 subsea wells globally in multiple countries and more than 550 subsea wells on the Norwegian Continental Shelf (NCS), which accounts for more than 83% of all subsea wells in the area. Successful interventions here using RLWI vessels encouraged the operator to investigate the possibilities of also performing CT operations from a vessel. The best option was found to be a strategy that included a monohull vessel that could perform both RLWI and CT operations. The analysis of operations in rough-weather conditions in the NCS showed that riser-based CT operations from such a vessel could be performed in the summer season only. Thus, the operator required a flexible solution such that the same RLWI vessel could cover both year-round RLWI and summertime riser-based CT interventions efficiently. The solution materialized when a larger vessel was engaged to expand the usable weather season and allow year-round RLWI operations. Description and Application of Equipment and Processes To enable riser-based CT intervention in the NCS, the chosen option required more equipment and interfaces than were required when performing RLWI. To conduct riser-based CT interventions in live wells, a way to handle, deploy, and tension the high-pressure riser was required, as was an interface for both wireline and CT equipment in the vessel. A system to handle live-well returns from the well also was necessary. After many engineering iterations, the RLWI vessel implemented a modular riser-handling package that could be installed and then removed when not needed. On top of the surface flow tree, a custom CT tension frame (CTTF) was developed for the CT and wireline stacks and pressure control equipment (PCE), each inside separate support frames within the CTTF. With the CTTF connected to the riser, each support frame could be skidded to the well center, eliminating the need for crane lifts while changing between wireline and CT. CT Planning Well Control and Barriers. Because of limited space on the RLWI vessel, only one dual-ram blowout preventer (BOP) would fit in the CT support-frame cartridge within the CTTF. In addition to the dual strippers, the rest of the PCE requirement considered the subsea emergency disconnect package (EDP) and lower riser package (LRP) to complete the well-control equipment. The EDP and LRP included a safety head, a production isolation valve, and a retainer valve, all capable of cutting wireline and CT.

Presently, several large deep water natural gas fields are designed to produce over 1000 MMSCFD of gas with low liquid content <20 BBL/MMSCF. Such deep water facilities are typically comprised of ~8-10" diameter well manifolds and 30-40" in diameter 100 mile long flow lines that are operated at high pressure and temperature conditions. Key CAPEX and OPEX decisions for deep water gas facilities include: wellbore tubing and subsea flow line sizing, subsea flow line routing, pigging frequency, pipeline materials, range of allowable operating rates and large production rate variations, and subsea asset integrity management. Key design decisions require knowledge of variations in flow regime over field life, liquid hold-up in the flow lines, liquid entrainment and sand in the fluids in the subsea facilities that may result in erosion at the high operating limit and sand deposition concerns at low operating limit. Given the scarcity of data at conditions similar to wet gas field conditions, current industry-standard multiphase flow simulators predict flow behaviors with a high degree of uncertainty and hence, are known to have been inadequately validated. This paper presents a unique set of high quality wet gas multiphase flow data in a 16" diameter flow loop operated at ambient conditions including several salient measurements such as pressure drop, liquid hold-up, liquid film velocity as a function of liquid film depth, average liquid film velocity, etc. using state-of-the-art instrumentation.

In December of 1988 a joint venture led by Freeport Sulphur Company discovered a major brimstone deposit of 67,000,000 long tons twenty miles offshore in the Gulf of Mexico. At a production of 2 million tons of sulphur per year this facility will be in operation for the next 30 years. This paper will cover the process of automating the frasch sulphur mine including design and planning, redundancy, reliability, training and configuration. A description of system architecture which allows information for production to be gathered and handled at the facility from process control, production and drilling will be presented. The ability to monitor and control the offshore platform from an onshore facility via satellite communications and the ability to network the process control system with a local area network of host and personal computers will be discussed. INTRODUCTION Main Pass Block 299, is located (Fig. 1) in 210 feet of water, 20 miles east of the mouth of the Mississippi River in the Gulf of Mexico. The production facilities will incorporate the latest technology based upon previous applications, the company's expertise in offshore sulphur mining and on proprietary mining techniques that use seawater in sulphur mining. The offshore production facility will be installed on a series of offshore platforms (Fig. 2) linked together by more than a mile of bridges. The Main Pass facilities are scheduled for completion in late 1991 with sulphur production beginning soon thereafter. One of the greatest tools in assisting operations achieve high safety and efficiency goals is through production automation. Improved productivity as well as improved management of production information can be realized from a modern process control system. Through automation and remote monitoring, operating costs can be reduced and production revenues increased. The strategy was to implement a completely integrated information system - one that gives the association of the process operations data with management and business systems data. AUTOMATION PROCESS Planning There are a great number of factors to consider when developing a plan for plantwide process control and flow of information. The needs and requirements of production planning, engineering, maintenance, material handling, scheduling and overall management are unique when it comes to process control data and business information systems. The first step in the planning of the control system was assembling a team of people from the various areas listed above. The company had to make a decision to make available the best that the company has to offer in the areas of production, maintenance and engineering to be a part of the team. Because of their other responsibilities in construction of this facility as well as running existing facilities it is almost impossible for them to spend a majority of their time on process automation alone. Once a team was established then the next step was to set the criteria for controlling the process and the handling of production data.

One of the largest Umbilical, Flowlines and Risers project ever awarded to a single Contractor for deepwater installation, the network to connect and control the 71 wells and 9 manifolds is extensive:40 km of insulated pipe in pipe (12" into 17") production flowlines45 km of 12" water and gas injection lines6 off 1.7 km flexible water and gas injection risers8 off 1.65 km flexible Integrated Production Bundle (IPB) risers75 km of control umbilicals Insulation of the production transport system was the challenge. With a crude temperature of 45°C at the wellhead and the required minimum temperature of 35°C on arrival at the FPSO, the problem was complex. Understanding that, due to the Joule Thompson effect of the riser gas lift, a "built in" loss of 5°C is induced and together with further losses through the subsea pipelines, some up to 6 km long, the agreed solution was "pipe in pipe" for the production flowlines. The innovative flexible IPB riser incorporating gas lift and heating "on demand" was the selected riser solution. The IPB is new technology for deep water, developed by Technip for Dalia, and consists of a 12" nominal central flexible, surrounded by layers of heat tracing cables; small bore gas lift lines, optical fibres and many insulation layers with an Overall Heat Transfer Coefficient of approximately 3 W/m2K. After an earlier research and development programme, a further extensive qualification programme was conducted during the course of the project, culminating with the deep water testing phase offshore Brazil. The IPB was then approved for fabrication and installation. This paper will describe the many challenges met during the project. Dalia Overview (Figures 1 to 5) For further details refer to Dalia Paper OTC 18538. Figure 1 gives the general field layout, showing the subsea wells, manifolds, flowlines, umbilicals and risers up to the FPSO. It is a large and complex network of various pipelines and umbilicals within an optimised design responding to the reservoir, well architecture and the operation parameters required. Figure 1 - General Field Layout with Flowlines and Risers (available in full paper) As the result of a design competition comparing several concepts offered by different contractors, the selected solution is different from Girassol. The overall flowlines layout covering an area of 100 km2 comprises:4 × 12" production loops connecting two or three production manifolds to the topside facilities using pipe in pipe insulated lines and 8 × 12" flexible IPB risers4 × 12" rigid water injection lines incorporating inline Tees to connect the wells and 4 × 12" flexible risers to connect to the topsides2 × 12" rigid gas injection lines incorporating inline Tees to connect the wells and 2 × 12" flexible risers to connect to the topsides Figure 2 - Seabed Production, Water Injection and Gas Injection Lines Layout (available in full paper) Figure 3 - Production Loop with 2 manifolds and Topside (available in full paper) Figure 4 - Typical Production Loop Layout incorporating Manifold and Well Cluster (available in full paper)

The world's first Arctic subsea producing gas well was successfully completed and produced to shore by means of a wet Christmas tree in April 1978. This paper describes the unique design of a combination land and offshore drilling rig and air transportable subsea blowout preventer for drilling and completing subsea wells from a floating ice platform. The drilling and completion of Panarctic Drake F-76 is described. The design of a prototype subsea wet tree and diverless flowline connector is also discussed. The well was drilled and completed as a demonstration well in 181 feet of water, 3,050 feet from shore using a rig supported by a floating ice platform. The operation demonstrated techniques which could be used to develop extensive gas reserves in water depths to 1,500 feet located up to 15 miles offshore in the Canadian Arctic Islands. INTRODUCTION In 1973 Panarctic Oils Ltd. developed a system of drilling exploratory gas wells offshore between the Canadian Arctic Islands. Exploration had been taking place onshore since 1961 and it became evident that the six gas fields which were discovered onshore all extended offshore, under ice covered waters. As conventional offshore drilling techniques could not be used in the area, a drilling method was developed wherein the ocean ice was flooded and thickened, developing sufficient strength to support a land type of drilling rig, modified for offshore drilling. The major area of current drilling activity is centered at about 760N latitude and l080W longitude. Fig. 1. The area covers a 450,000 square mile sedimentary basin of which about 70% is covered by ice year round. Reserves totalling approximately 13 trillion cubic feet of sweet natural gas have been found and eventually will be connected to markets via a proposed 2,300 mile Polar Gas Pipeline. Starting in 1974 and until the end of the 1979 drilling season a total of 13 offshore wells have been drilled using offshore drilling systems adapted to land rigs supported from floating ice platforms. These systems have been effective in drilling in water depths up to 1,200 feet at locations up to 20 miles offshore at costs comparable to land drilled wells. In 1976 planning commenced to develop a system for drilling and completing an Arctic offshore gas well. This project involved the design and construction of a new and larger ice supported rig, a larger and more conventional subsea BOP stack, a subsea tree and flowline connector, flowlines and control lines to shore and shore based test facilities. DRILLING AND COMPLETION SYSTEMS A study was conducted in 1976 by Tri Ocean Engineering of Calgary to determine the most suitable means of drilling, completing and testing an offshore well to demonstrate and test technology that eventually could be used to develop the reserves commercially.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166266, ’The Role of Autonomous Flow Control in SAGD Well Design,’ by Sudiptya Banerjee, SPE, Robert Jobling, SPE, Tarik Abdelfattah, SPE, and Hang Nguyen, SPE, Baker Hughes, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed. One notable improvement originating from recent field experience is the novel use of injection-/inflow-control devices (ICDs) in a conventional steam-assisted-gravity- drainage (SAGD) well pair. The use of a properly designed ICD completion has proved beneficial to the processes of developing the steam chamber and improving the inflow profile of the producing well of the SAGD pair. Work conducted in the Surmont field of Alberta, Canada, provided an excellent starting point to optimize flow-control improvements to the SAGD process. Introduction To obtain high efficiency, the SAGD process demands a high degree of steam conformance along the wellbore. The better the steam conformance, the greater the amount of oil mobilized and the higher the potential for oil recovery. However, conformance should not come at the cost of excessive steam injection. A number of thermal inefficiencies (described in the complete paper) are unavoidable in the SAGD process. These collectively result in a deformed and nonoptimal steam chamber that undermines energy maintenance and lowers the ultimate recovery factor. By incorporation of flow-control devices (FCDs) into the injector or producer well, however, a more ideal, more desirable chamber shape can be realized. Overview of ICD Geometries Fundamentally, all flow-control devices operate by the same mechanism: They provide an additional pressure drop at select points in the completion string to complement the pressure drop of fluid moving through the reservoir as well as internal pressure drops within the completion itself. Despite this fundamental similarity, however, the methods by which different styles of ICDs create this pressure drop vary strongly with design. There are three distinctive categories of passive inflow-/injection-control devices (PICDs) available today. The two most common PICD geometries are orifice/tube/nozzle-based (restrictive) (Fig. 1) and helical-channel/baffled- pathway (frictional) (Fig. 2). The restriction-based PICD uses fluid constriction to generate a differential pressure across the device. This method essentially forces the fluid from a larger area through small-diameter ports, creating flow resistance. A frictional-pathway PICD relies instead on surface friction to generate a similar pressure drop. These designs produce a distributed pressure drop over a relatively long area, as opposed to the instantaneous loss through a restriction-style PICD. When fluid flows through the channel/ channels, fluid rheology and channel characteristics interact to create the designed pressure drop.