Subsea Flowlines Research Articles

Development of a high pressure micromechanical force apparatus

The formation of gas hydrates and subsequent plugging of pipelines are risks that need to be well understood during the production and transportation of oil and gas in subsea flowlines. These flowlines are typically operating at low temperature and high pressure conditions, which are well within the hydrate formation stability region. One of the key processes for hydrate plugs to develop is the agglomeration of hydrates. To obtain a more comprehensive understanding on this problem, we have developed a high-pressure micromechanical force (MMF) apparatus to directly measure cohesive forces between gas hydrate particles. The MMF system is housed in a stainless steel vessel that can withstand pressures of up to 10 MPa, thereby facilitating studies on a broad spectrum of hydrate formers and conditions. The MMF apparatus comprises of two cantilever fibers: one is stationary and another is manipulated via a nano-manipulator. Water droplets (~500 μm in diameter) are placed at the end of the each cantilever fiber so that they can be converted to hydrate. In order to demonstrate the stability of this apparatus, CH4/C2H6 (74.7 mol. %/25.3 mol. %) mixed hydrates were prepared at 2 MPa and -5 °C and annealed at 0 °C for 15 h. Subsequently, the hydrate particle cohesive force was measured at 2 °C. Compared with the cohesive force of cyclopentane hydrates in cyclopentane liquid (~4.3 mN/m), the average cohesive force of gas hydrates was about 10 times higher, ~43 mN/m. Studies using this new high pressure MMF apparatus will be central to better understand the agglomeration of hydrates in multiphase flowlines.

Case Study: Foaming During Startup of Karan Nonassociated Gas

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 17175, ’Khursaniyah Gas-Plant Experience With Foaming During Startup of Karan Nonassociated Gas,’ by Mohammed Hussain Al-Qahtani, Saudi Aramco, and Paul Garland, INEOS, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. Copyright 2013 International Petroleum Technology Conference. Reproduced by permission. All amines are subject to foaming in industrial applications given certain conditions and circumstances. Methyl diethanolamine (MDEA) is like other types of amine that can experience major foaming upset, especially in high-pressure sweetening units. However, MDEA is one of the most popular solvents for gas treating, with several advantages over other amines, particularly its ability to remove hydrogen sulfide (H2S) and slip carbon dioxide (CO2) from sour gas. This paper describes Saudi Aramco’s efforts to eliminate early foaming incidents during the commissioning stage of the Karan nonassociated (NA) sour-gas field. Introduction The Karan field was discovered by Saudi Aramco in 2006. This newly developed offshore field is located 120 km northwest of Jubail Industrial City in eastern Saudi Arabia. Produced sour gas is coblended at a tie-in offshore platform through five 20-in. subsea flowlines. From the tie-in offshore platform, the gas is sent through a 38-in. subsea pipeline to the onshore gas-treatment facilities at the Khursaniyah Gas Plant. Karan facilities consist of three gas-treatment-processing trains, each designed to process 620 MMscf/D of NA sour gas, producing sales gas and acid gas. Karan NA sour gas is a CO2-rich stream. Formulated MDEA was selected for sweetening in Karan gas-treating facilities to enhance the H2S / CO2 ratio in acid gas and to meet the required sales-gas specification before sending the gas to the Saudi Master Gas System. The Problem of Foaming Karan’s three gas-treating trains have a total rated capacity of 1.86 Bcf/D of sour feed gas. Each train consists of an MDEA-based acid-gas-removal (AGR) unit, a triethylene-glycol (TEG) dehydration unit, and an acid-removal (AGE) unit (Fig. 1). In addition, propane is used for process-stream cooling at various points throughout the process, where temperatures of less than 140°F are required. A dedicated propane-compression system runs continuously to cool each process train.

Dry tree well flow assurance challenges and solutions for offshore gas condensate field development

Offshore field developments usually conceive that the dry tree wells (DTW) have less flow assurance challenges when compared with subsea development options. The relatively short vertical flow path for the DTW production risers causes fewer issues with respect to hydrate and wax management; however, the DTWs have particular flow assurance challenges due to dry tree well platforms design constraints. This extended abstract presents the various flow assurance challenges associated with the design and operation of DTWs for deepwater gas-condensate field developments, including: the impact of production riser annulus thermal behaviour and soil modelling uncertainties on the topsides materials selection; the coupling of low temperature propagation and cold liquid management issues topsides during cold well start-up; and, the narrow operating window to establish the forward flow for the downstream systems following cold well start-up. The absence of the capacity provided by subsea pipelines and flowlines, thus, leads to the requirement for integrated consideration of the DTWs and downstream topsides and potentially pipeline systems. The coupling for low temperature and liquid management issues, particularly for transient operations, requires rigorous flow assurance analysis. This extended abstract summarises the analytical solutions developed, applying the advanced flow assurance tools available, by considering the operating constraints, with the downstream process and export systems, to determine practical design solutions and operating philosophies.

Multiphase flow modeling of gas hydrates with a simple hydrodynamic slug flow model

The formation and accumulation of natural gas hydrates in deep subsea flow lines are one of the most challenging flow assurance problems. Typical high pressure/low temperature operation conditions in deep subsea facilities promote rapid formation of gas hydrates. Recent observations in flow loop experiments in gas/water systems suggested a relationship between hydrate volume and flow regime on pressure drop. In the current work, a simple hydrodynamic slug flow model, based on fundamental multiphase flow concepts, is coupled with a transient hydrate kinetics model to study the effect of hydrate formation on slug flow in gas/water systems.

Dynamic-Simulation Applications Support Challenging Offshore Operations

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156146, ’Dynamic-Simulation Applications To Support Challenging Offshore Operations: A Kitan Oil Field Offshore East Timor Case Study,’ Ryosuke Yokote, SPE, and Vanni Donagemma, Eni Australia, and Juan Carlos Mantecon, SPE, SPT Group, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October. The paper has not been peer reviewed. The Kitan oil field consists of three subsea intelligent wells. The intelligent completions were modeled in detail using commercial dynamic-simulation software to establish a sound and safe operating procedure for the well cleanup and well test. The simulation results provided the petroleum engineer on the rig with key operational information, such as the time for the oil to arrive at surface and expected pressure at the downhole gauges (DHGs) and upstream of the choke manifold. This enhanced the ability of rigsite supervisors to anticipate well behavior, enabling a significant risk reduction. Introduction The Kitan oil field is approximately 200 km south of the East Timor coast and 500 km offshore of the northern coast of Australia (Fig. 1). The Kitan field development consists of three vertical producing wells, 6-in. production subsea flowlines and risers, 2-in. gas-injection lines, umbilical lines, and a floating production, storage, and offloading (FPSO) vessel. Each well has a designated flow-line and riser tied back to the FPSO vessel (Fig. 2). Fig. 3 shows the intelligent completion for the Kitan development wells. The intelligent completion was de-signed to control flow from two separate zones, upper and lower. Flow from each zone is controlled by flow-control valves (FCVs) that have eight positions (fully opened, fully closed, and six intermediate choke positions). Pressure and temperature for each zone are monitored by three DHGs. The FCVs have a fail-as-is design and stay in the last position should a communications problem be encountered. Because of the remoteness of the location, the functionality of the intelligent completion and the well performance needed to be confirmed with a minimum degree of uncertainty. To establish a sound and safe operating procedure for the well cleanup and well test, commercial dynamic simulation software was used to model the intelligent completion and selected operations. A few different well-cleanup procedures were investigated to predict cleanup time, pressure and temperature at different points of interest, and flow rates on the rig. The simulation results provided valuable information, enabling the petroleum engineer on the rig to predict flow conditions of the well during the operations. Following the successful well-cleanup and well-test campaign, the well models were validated with actual well-cleanup and -test data.

HIPPS-Based No-Burst Design of Flowlines and Risers

Summary A methodology is proposed for design of subsea flowlines and risers coupled with a subsea high-integrity pressure protection system (HIPPS) for fields with high shut-in tubing pressure (SITP). The proposed approach uses a design pressure that is lower than the SITP while maintaining a high reliability against burst failure. This approach enables an inherently safer design and ensures that the system integrity is not compromised in the unlikely event that HIPPS valves fail to close upon demand. The proposed design methodology is supported by a combination of analytical and experimental results. Further, an example is provided for demonstration purposes.

Direct electric heating: an environmentally friendly flow-assurance tool

In subsea flowlines, water in the line can form an ice-like structure called a hydrate plug. Wax appearance in flowlines also is a common flow assurance issue. Hydrate and wax appearance can reduce or stop production for weeks. Preventing hydrate and wax in pipelines is a major concern for the oil and gas industry. Direct electric heating (DEH) is a modern and environmentally friendly flow-assurance tool that can reduce capital expenditures (CAPEX) and operating expenditures (OPEX) in field development, reduce the probability of pollution, and reduce handling of toxic disposals as a result of traditional chemical flow assurance methods. DEH is based on using the pipeline as part of the electrical circuit, generating losses in the steel pipe to keep the pipeline and its content above the critical temperatures. Use of DEHs also increases the efficiency at the process plant after planned or unplanned production stops. For marginal fields and fields with heavy or waxy oil, DEH is a flow-assurance method that can enable these fields to be developed profitably. DEH is now a mature technology used for 13–14 years on the Norwegian continental shelf and technology implemented and used in West Africa recently. How successful this technology has been can be summarised by the Tyrihans field where Statoil quoted that they—on this project alone—saved about $USD175 million by implementing DEH. Wärtsilä has been part of the DEH development in Norway since the 90s, and undertakes design and supply of the complete topside power package in addition to electric and optical protection specially developed for DEH systems.

Integrated Production and Reservoir Modeling To Optimize Deepwater Development

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 131621, ’Application of Integrated Production and Reservoir Modeling To Optimize Deepwater De velopment,’ by R.F. Stoisits, SPE, and H.M. Bashagour, ExxonMobil, and C.G. Su, SPT Group, originally prepared for the 2010 CPS/SPE Oil and Gas Conference and Exhibition in China, Beijing, 8-10 June. The paper has not been peer reviewed. A deepwater satellite-field project encompasses two fields that are in the general vicinity of two existing floating production, storage, and offloading (FPSO) vessels. A number of development architectures that include various subsea tiebacks to two existing FPSOs were potential candidates for development. To establish an optimal subsea umbilical, riser, and flowline (SURF) architecture, a method to forecast production behavior of the various architectures is required. To achieve this objective, an integrated-production-modeling (IPM) tool was developed. Introduction A deepwater development in West Africa consists of five fields that send production to two FPSOs. Two more fields currently are under development. The basis for the satellite project is a blockwide study (BWS). The objective of the BWS was to assess how best to develop the two discovered, but so far undeveloped, assets in the vicinity of the two existing FPSOs. The BWS concluded that these assets could be commercialized most economically in a common development as subsea tie-backs to the two FPSOs, filling processing ullage. The BWS identified a high level of uncertainty involved in developing the satellite fields. In particular, both the resource base of the assets and the ullage expected to be available on the FPSOs are difficult to assess, with estimates varying considerably. The two target fields comprise complex, compartmentalized reservoirs with lower resource density and poorer-quality crude than the other existing developments. The BWS along with a parallel study, the execution breakthrough task force (EBTF), examined numerous development architectures. Analysis of these architectures concluded that an all-subsea-tieback development provided more-favorable economics and greater flexibility in responding to changing resource assessments than did concepts that included another FPSO. It also pointed to the concept developed by the EBTF which consisted of a loop flowline system connected to both existing FPSOs, as providing the greatest resource, ullage, and operational flexibility. Fig. 1 shows the final selected development concept that forms the basis for the satellites project. The satellite loop consists of a single 27-mile production-flowline loop connecting the two FPSOs and includes the development of the two fields with 17 subsea wells drilled from four drill centers. The 10-in.-inner-diameter pipe-in-pipe (PIP) flowlines are connected to each FPSO by a newly installed 12-in.-diameter gas lifted PIP single hybrid riser (SHR). Two 12-in.-diameter water-injection flowlines (a 9-mile line from FPSO 1 to satellite Field C and a 7-mile line from FPSO 2 to satellite Field M) are connected to the FPSOs by existing water-injection risers. All gas is injected down existing FPSO gas-injection wells. All processing occurs on the FPSOs with additional I-tubes installed as required and various modifications made to their topsides to accommodate the increased infrastructure.

B306 サブシープロダクションシステムの最近の動向(OS10 海洋におけるシステムと制御2)

Subsea production system, also named as subsea tie-back or subsea, consists of subsea wells, subsea processing facilities, subsea flow-lines, subsea controls, and surface Host, has capability to product oil & gas without an offshore structure straightly up the subsea wells. Offshore oil development field is reaching around 3000m and SPS technology is essential. This paper introduces recent trend in the development of SPS from the viewpoint of control engineering application.

Intelligent-Well Completions in Agbami: Value Added and Execution Performance

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 20191, ’Intelligent-Well Completions in Agbami: A Review of the Value Added and Execution Performance,’ by Adekunle Mojeed Adeyemo, Chris Aigbe, Ike Chukwumaeze, SPE, David Meinert, SPE, and Steven Shryock, SPE, Chevron Nigeria, prepared for the 2009 Offshore Technology Conference, Houston, 4-7 May. Use of intelligent-well-completion (IWC) technology has grown, even with perceived risks associated with installation and longevity of the systems. In the Agbami field, offshore Nigeria, for which 80% of the development wells are planned with IWC installations, understanding these risks was key in justifying IWCs. The methodology used to quantify the realizable value from zonal control and data acquisition and a review of the execution performance for the initial IWC wells are presented. Introduction First production from the Agbami field was 29 July 2008, and it was producing at 140,000 BOPD at the time of writing. Peak production of 250,000 BOPD (not accounting for facilities downtime) was expected by the end of 2009. The Agbami field, discovered in 1998, is 70 miles offshore Nigeria at a water depth of approximately 5,000 ft. The field is a northwest/southeast-trending doubly plunging anticline, with a significant thrust fault through the crestal axis of the structure. As Fig. 1 shows, the field has four main reservoirs: 17MY, 16MY, 14MY, and 13MY. Approximately 80% of the field in-place volume and reserves are in the deepest sand (17MY), having average porosity of 18% and average permeability of 270 md. The field-development plan has 38 subsea wells (including 20 producers, 12 water injectors, and six gas injectors) tied back to a floating production, storage, and offloading (FPSO) vessel through subsea flowlines. The drilling-and-completion program is spread over three development-drilling stages. The project is in Stage 1, with eight producers and two gas injectors on line. Pressure maintenance will be by peripheral water injection and crestal produced-gas reinjection to ensure compliance with a “no flare” policy. Geologic and Engineering Considerations The field has multiple lobes within each major reservoir. Although these sand lobes, or zones, are in pressure equilibrium geologically, the vertical/lateral connectivity under dynamic conditions is uncertain. Therefore, waterflood and gasflood fronts are likely to advance through the reservoirs at different rates, leading to conformance issues. To optimize field performance and recovery, IWCs with downhole control valves are installed in the Agbami wells. The system will provide zonal information and control of production from and injection into the completed subreservoir zones. IWCs will enable zonal production/injection management for optimal field development and oil recovery.

Presalt Santos Basin - Extended Well Test and Production Pilot in the Tupi Area: The Planning Phase

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 19886, ’Presalt Santos Basin - Extended Well Test and Production Pilot in the Tupi Area: The Planning Phase,’ by Celia M.F. Nakano, Antonio C.C. Pinto, SPE, Jose L. Marcusso, and Kazuioshi Minami, SPE, Petrobras, prepared for the 2009 Offshore Technology Conference, Houston, 4-7 May. Petrobras is assessing the potential of the Santos basin presalt reservoirs offshore Brazil. Three integrated ultrafast-track projects were planned to start production of the giant presalt reservoirs in an area known as Tupi. The objective of the three projects is to obtain relevant reservoir and production data to support the design phase of the remaining production units of the full-field development. The main technical challenges addressed include drilling complex wells, use of intelligent completions, qualifying ultradeepwater risers, establishing flow assurance through long subsea flowlines, and CO2 capture and sequestration. Introduction The Tupi area is in the central portion of the Santos basin, approximately 290 km offshore Rio de Janeiro State, at water depths of approximately 2200 m. The first well drilled in the block was Well RJS-628, completed in August 2006. The well was designed to test the carbonate section of an Aptian reservoir. It found a primary hydrocarbon-bearing reservoir in carbonate having microbial origin, named the SAG reservoir. A secondary microbialite reservoir, named the RIFT reservoir, also was found. Both reservoirs are below a thick regional layer of salt that occurs in this portion of the basin. Therefore, these reservoirs were classified as presalt reservoirs. The well was tested and produced after an acid stimulation. The choke-constrained production rates were 378 m3/d of 28°API crude oil with a gas/oil ratio (GOR) of approximately 220 m3/m3. To verify the continuity of the SAG reservoir to the south, Extension Well 3-RJS-646 was drilled in July 2007, 10 km from the wildcat. The well, in the Tupi Sul area, confirmed expectations of the SAG and RIFT carbonate oil reservoirs, and reservoir characteristics were better than those of the previous well. Another oil-bearing carbonate reservoir, the Coquina reservoir, also was found. The well tested a choked rate of 445 m3/d of 27°API oil from the SAG reservoir with a GOR of 230 m3/m3. Because of logistics constraints, the deeper reservoirs could not be tested. The reservoir area was covered completely by 3D-seismic data. High-resolution seismic is being acquired in the Tupi area.

Brazil Parque das Conchas Project Sets Subsea Separation, Pumping Milestone

As first oil flowed on July 12 at the Shell-operated deepwater Parque das Conchas development offshore Brazil, it marked a major advance in the production of Brazil's abundant heavy-oil reserves and became the world's first full-field development based on subsea oil and gas separation and subsea pumping. Situated 75 miles southeast of Vitória, off Espirito Santo state, Parque das Conchas (formerly known as BC-10) lies in approximately 4,900 to 6,500 ft of water at the northern edge of the Campos Basin (Fig. 1). Parque das Conchas in its first phase will produce from three fields, with oil ranging in gravity from 17 to 42°API. The fields will produce through subsea trees and flowlines tied into the centrally located floating production, storage, and offloading vessel (FPSO) Espirito Santo(Fig. 2). Turret-moored in 5,840 ft of water, the double-sided FPSO is equipped to process peak daily project production of 100,000 BOE, with 1.4 million bbl of oil-storage capacity. Parque das Conchas is a joint venture of Shell (50%), Petrobras (35%), and ONGC (15%). The development grew out of a substantial exploration and appraisal program, in which Shell drilled 13 wells and made six discoveries. The project was declared commercial in 2005, and major contracts were awarded in November 2006. For Shell, Parque das Conchas is the first Brazilian project the company has taken all the way from exploration to production, as opposed to inheriting a project from another operator or initiating a project that it had to turn over to someone else to operate. Challenges to Project's Economics "There were a number of challenges we faced to make the project economic," said Kent Stingl, Parque das Conchas project manager for Shell. "We had heavy oil in relatively low-pressure reservoirs in an ultradeepwater environment. Hence, we had to determine how to pump from this depth and process on the production facility. But there was more to it than that. There are four dispersed reservoirs, small to medium in size, with widely divergent oil gravities and different gas/oil ratios (GORs). We needed to find an economic way of commingling and bringing production from the various reservoirs back to a central facility, with artificial lift (AL) required and subsea gas/oil separation for some reservoirs." A further challenge was that the reservoirs, though in deep water, are only approximately 3,300 ft beneath the mudline. "Starting from vertical at the seafloor, we had to kick the wells out at a tremendously high angle to drill the horizontal wellbores required to drain these reservoirs," Stingl said. "We operated from only a few drilling centers to minimize the need to move the rig. So these horizontals extended more than 3,000 ft, and all were completed with gravel packs."

Paraffin Cleanout in a Single Subsea Flowline Using Xylene

Summary Paraffin deposition was found in the RedHawk #2 subsea flowline and was successfully removed using a xylene slug swept by produced gas from the well. Testing indicated that the problem resulted from the interaction between glycol and produced condensate. Overtreatment with glycol and low produced water volumes contributed to the precipitation of paraffin and eventual plugging of the flowline. The objective of this procedure was to clear the restriction by pumping a slug of xylene into the flowline and producing the well to carry the solids to surface. Glycol can react negatively with the condensate in some dry gas wells, resulting in paraffin precipitation. When there is sufficient water present to mix with the glycol the problem does not occur; however, a lack of water causes the glycol to react with the condensate and form paraffin. Clearing the restriction would eliminate a pressure drop in the flowline, thus allowing the well to produce at optimal rate and prolonging the well's life. All work was performed from the host spar facility using temporary separation equipment and platform methanol pumps. The RedHawk flowline restriction was successfully removed using two 25-bbl xylene slugs which were swept from the flowline with produced gas from the well. With the restriction removed, 982 psi of frictional loss was regained and the well was returned to optimal production. The deposition appears to be reoccurring, although at a much slower rate than before. However, any further reduction in glycol usage would not guarantee effective hydrate inhibition. Changing hydrate inhibitors is impractical because of platform equipment, and annual cleanouts are a more cost effective option. It is quickly becoming critical to develop means of cleaning single flowline systems with highly efficient and low-cost methods. By understanding new problems that arise and putting new solutions into practice, operators can extend the life of some wells and avoid significant downtime and workover costs.

To SSIV, or not to SSIV: that is the question

Sub Sea Isolation Valves (SSIVs) are normally considered for installation on the majority of facility builds. They first started coming to prominence in the world of safety following the Piper Alpha tragedy in 1988, where 167 people died and the platform was destroyed as a result of an explosion and fire. The aim of SSIVs is to protect the people on the platforms by limiting the amount of hydrocarbon available for a jet fire. Reducing the severity of a jet fire protects the integrity of manned living quarters in the event of an issue with the pipeline. This theory still holds true today but twenty plus years on SSIVs are not always included in new facility designs. Oil and gas fields developed in the future are more likely to be in more remote locations with large diameter pipelines tied back to onshore processing facilities. With well bays being replaced by subsea wells and flowlines it would be thought that the SSIV would now be man’s best friend; however, with the oil and gas industry showing a declining trend in fatalities around the world and with design improvements preventing and mitigating the occurrence of major accident events, many operators are questioning the added benefits of the SSIV. This paper debates the use of the SSIV and explores the issues over which many design teams deliberate. It considers the positives and the negatives associated with the SSIV and illustrates why an SSIV installation is a case-by-case prospect. A case study using a risk-based approach for installing the SSIV as part of a design concept is used to help illustrate this point.

Improved UOE Pipe-Manufacturing Process Helps Meet Deepwater Pipeline Challenges

Technology Update Conventional pipeline design, although concerned with many factors, generally centers on the need to withstand the internal pressure in the line. The higher the pressure at which throughput can flow, the higher the flow rate, and the greater the revenue potential for the operator. However, when considering the factors critical for deepwater pipelines, much of the focus shifts to the need to withstand the external pressure on the line, particularly during installation. With local "infield" lines, such as subsea umbilicals, risers, and flowlines, the challenge is modest because the lines are small in diameter and, thus, inherently resistant to hydrostatic collapse. These lines are generally produced as seamless pipe, which in smaller sizes is readily available and generally a suitable economic solution. However, deepwater trunklines, especially with long-distance tiebacks, present a greater challenge. These lines must be wider in diameter to meet the production demands of large-scale, high-cost projects. Thicker pipe wall is required to ensure that pipes can withstand the hydrostatic pressure and bending that affect them as they are laid to the seabed. Often, these are 16- to 20-in.-diameter lines, which places them at the economic limit for seamless pipe production methods. A project table including some typical deepwater pipe properties is shown in Fig. 1. It is possible to produce thick-walled, seamless pipe at these diameters by means of the Pilger process, in which hot round steel billets that have been hollowed in the initial phase of production are rolled and stretched until the desired length and diameter are achieved. However, the manufacturing process is slow and the cost of material high. The most economic method of manufacturing pipe at these wall thicknesses and diameters is the UOE process, in which steel plate is pressed into a U and then an O shape and then is expanded circumferentially. (This process was used in the projects shown in Fig. 1.) The advantages of the UOE process notwithstanding, the current wall-thickness and diameter requirements for deepwater trunkline pipe still have proved challenging from the standpoint of manufacturing economics and installation capabilities. Only a handful of manufacturers are capable of supplying double-submerged, arc-welded (DSAW) pipe that meets specifications for the deepest projects, such as the Shell Perdido development in the Gulf of Mexico. The acceptability of a pipeline design for a given water depth is determined by means of standard equations that measure the relationship between outside diameter, wall thickness, pipe shape, and material compressive strength.

A Case Study in Wax Removal From a Subsea Flowline

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 105048, "A Case Study in the Removal of Deposited Wax From a Major Subsea Flowline System in the Gannet Field," by H.A. Craddock, SPE, K. Mutch, and K. Sowerby, Roemex Ltd., and S. McGregor, J. Cook, and C. Strachan, Shell UK Ltd., prepared for the 2007 SPE International Symposium on Oilfield Chemistry, Houston, 28 February–2 March. The following stages were key to the successful wax-removal operation: selection and design phase of the chemical application, the environmental chemical-selection criteria, the development of the work scope, and the logistics of the chemical application. The wax-removal process was deemed successful and offered the client significant benefit in terms of increased oil production. Reduced pipeline differential pressure and increased fluid arrival temperatures also indicated that the wax restrictions in the flowlines had been removed. Introduction The control and mitigation of wax deposition and its concurrent problems rapidly are becoming critical challenges facing the oil- and gas-production industry as the industry explores and develops in increasingly challenging environments, such as deepwater and subarctic conditions. Wax deposits can occur widely in the production process and often are considered the organic equivalent of scale formation. Field Description The Gannet field is 180 km east of Aberdeen in a water depth of approximately 90 m. Since the field was originally discovered, in the 1970s, several satellite fields have been tied into the Gannet facilities. Gannet D is an oil field 16 km northeast of Gannet Alpha. Production is from five wells, with oil transported back to the Gannet Alpha facilities by two looped 6-in. subsea flowlines referred to as Riser 31 and Riser 32. The crude from these reservoirs typically is 41°API, with a wax content of approximately 7% and a wax-appearance temperature of approximately 35.5°C. The Gannet G field also is produced by this system with a single 6-in. flowline tied in at the base of Riser 32, 0.5 km from the Gannet Alpha platform. Riser 31 carries Gannet D crude only, and Riser 32 carries Gannet D and G crude topside onto the Gannet Alpha processing facilities, where the oil is commingled with other Gannet fluids before being exported to the Fulmar platform.

Akpo: A Giant Deep Offshore Development

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18816, "Akpo: A Giant Deep Offshore Development," by F. Rafin, A. Laîne, and B. Ludot, Total, prepared for the 2007 Offshore Technology Conference, Houston, 30 April–3 May. Deep offshore developments are difficult to implement and often are beyond the limits of proven technologies at their inception. At plateau production, Akpo field, 200 km offshore Nigeria in 1400 m water depth, will produce and export 175,000 B/D of condensate and will export at startup 320 MMscf/D of gas to the Bonny liquefied-natural-gas (LNG) plant, onshore Nigeria. Introduction The Akpo development experienced several challenges. A hybrid condensate-production/gas-export development scheme maximized hydrocarbon recovery. Reservoir management required massive pressure-maintenance facilities, extensive use of intelligent and selective completions, and subsea multiphase-flow measurements. A drilling strategy and well architecture had to be developed that maximized reliability and availability of the subsea layout. An extensive qualification and testing program of equipment was needed to meet the reservoir conditions. Also, the FPSO concept pushed the limits for handling the high volume of high-pressure fluids and gas inventory. Akpo Development Wells are in water depths ranging from 1300 to 1440 m across the block, and there are areas where the subsurface geology challenges drilling and completion capabilities. A total of 44 subsea wells (22 production, 20 water injection, and 2 gas injection) will be drilled in dispersed clustered groups, as shown in Fig. 1. The production wells will maximize the duration of the condensate-production plateau. Reservoir management will be applied to produce condensate from low gas/liquid ratio (GLR) reservoirs initially and control the arrival of water in the wells. In addition to reservoir constraints, well-target locations for the field were derived, taking into account such factors as drilling and completions, seabed topography, shallow gas, flow assurance, and flow-line laying and stability. The field is developed with a complex subsea infrastructure, having a network of flowlines, umbilicals, and production facilities. The 110 km of subsea flowlines are connected to the surface production facilities by 14 steel catenary risers hanging off both sides of the floating production, storage, and offloading (FPSO) vessel. The subsea network comprises four production loops, one gas-injection line, four water-injection lines, one gas-export line, and 65 km of static and dynamic umbilicals. The subsea production and gas-injection wells are connected from 10 manifolds (nine production, one gas-injection) installed on the seabed. Condensate production will start in 2008, and plateau production of 175,000 BOPD will be reached within 90 days. In addition, up to 320 MMscf/D of gas will be delivered to the Bonny LNG plant, onshore Nigeria. Complex Reservoir Fluid The reservoir fluid in Akpo is a critical fluid; therefore, whether it is liquid or gas depends on pressure, temperature, and depth. Consequently, no sharp gas/liquid contact exists within the hydrocarbon leg. The produced liquid is light oil and condensate (42 to 53°API gravity), with a high GLR of 1,600 to 7,300 scf/bbl).

Dalia Subsea Production System

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18541, "Dalia Subsea Production System, Presentation and Challenges," by J.L. Lafitte, M. Perrot, J. Lesgent, J. Bouville, and S. Le Pennec, Total E&P Angola; P. Dahl, Hydro; and S. Lindseth, AKS, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May. In 2002, the Dalia subsea production system was the largest subsea order placed with a single contractor in off-shore history. The production system had 71 wells, 71 drill-through horizontal trees, nine six-slot production manifolds, two workover systems, flowline-connection systems, and a complex control and chemical-injection system. Heat conservation and hydrate prevention were paramount concerns during the subsea-production-system detailed-design and construction phases. Subsea Production System Fig. 1 shows the general field layout with the 71 subsea wells and nine production manifolds and the flowlines, risers, and control umbilicals that cover a subsea footprint of approximately 100 km2. Production-Well-Cluster Layout. Various layouts were examined during detailed design to find the optimum solution. A typical production-well cluster comprises the manifold with three wells on one side and three wells on the other, all connected by rigid jumpers between the Christmas tree and the manifold. When the manifold is in the center of a flow loop, rigid spools connect production flowlines at both ends of the manifold. If the manifold is at the end of a flow loop, a pigging loop is mounted on the open side of the manifold, permitting roundtrip pigging. The control umbilical essentially is daisy chained from one manifold to the next. The rigid jumpers are not in contact with the seabed but float approximately 2.5 m above it because of attached buoyancy aids. Advances in directional horizontal drilling and the use of simplified completions have enabled the wells to be grouped in six-well clusters, which not only facilitates batch drilling, where necessary, but also reduces the number of subsea flowline and umbilical connections. Water and Gas Injection. Similar to Girassol, the same single-line header design is used to bring water and gas to the relevant wells. Control umbilicals are laid adjacent to the flowlines with subsea distribution units (SDUs) connecting the trees by electrical and hydraulic flying leads deployed by a remotely operated vehicle (ROV). Wellhead, Christmas Tree, and Tubing Hanger. Horizontal-Christmas-tree technology has been selected that is compatible with a 7-in. full-bore completion and permits an efficient sequence of operations, giving the possibility of batch drilling with a minimum number of rig moves. Additionally, the trees have the drill-through capability that for a light-architecture-type well, lets the tree be run before the blowout preventer (BOP). With the tree and BOP in place, the well then can to be drilled, cased, and completed.

Technology Update: Oil-Soluble LDHI Represents New Breed of Hydrate Inhibitor

Natural-gas hydrates may stand alone among oil and gas production problems in both the rapidity with which a severe problem can develop and the potentially catastrophic safety, environmental, and financial risks raised by worst-case scenarios. Unlike corrosion or scale or paraffin buildup, which typically take months or years to evolve into production problems, gas-hydrate plugs have been known to form in subsea flowlines and pipelines in an hour or less. Fig. 1 depicts a gas-hydrate plug that has been removed from a production line by means of pigging. Once a hydrate plug has formed, it can take weeks or even months to dissociate it safely. Meanwhile, downtime and production losses mount day by day, and this impact can be huge, compared with other production problems. Gas hydrates are ice-like crystals composed of water and natural gas, in which methane or carbon dioxide has become trapped in hydrogen-bonded cages. Unlike ice formed from H2O, though, gas hydrates are quite flammable and explosive. A cubic foot of gas hydrate at standard conditions contains 0.8 ft3 of water and 182 ft3 of methane. The hydrate plug can explode with a huge destructive force that may rupture subsea flowlines, damage production equipment, place workers at high risk, and endanger the ocean environment. Given these risks and the difficulty of remediating gas-hydrate plugging, most operators view prevention as their only real strategy for dealing with the problem. Hydrate Conditions in Deep Water Hydrates are formed thermodynamically whenever natural gas and water are present in the right combinations of low temperature and high pressure. Unlike pure ice, hydrates can form at temperatures much greater than 32 degrees Fahrenheit (°F). Hydrates have been shown to form in gas/water mixtures at temperatures of 40°F with pressure as low as 166 psi. It has been demonstrated, furthermore, that if pressures are great enough, hydrates can form in some gas/water compositions at temperatures as warm as 80°F. The extreme temperature and pressure regimes encountered on the world's ultradeepwater exploration and development frontiers combine to create almost perfect conditions for hydrate creation. In thousands of feet of water with long subsea tiebacks, production cools rapidly as it travels through flowlines from the well to the producing facility. The farther the flowstream travels, the more it is cooled by the surrounding seawater and the greater its risk of gas-hydrate formation somewhere within the production system.

Subsea Development of Okwori and Nda Oil Fields, Niger Delta

Summary Addax Petroleum's operated Okwori oil field, offshore Nigeria, illustrated the benefits of reviving shelved projects, because of an insufficient return on investment using more traditional approaches, by applying more recent technical and contractual solutions. The Okwori project demonstrated the feasibility of developing small and geologically complex offshore oil fields in medium water depth of 440 ft with subsea technologies traditionally used for large fields. In the subsurface, the Okwori wells combined multiple selective completions hydraulically controlled from the surface with expandable sand screens as the downhole sand exclusion solution. This combination of equipment in subsea wells used to fully develop a small offshore oil field marked another technological first in Nigeria. Far away from pre-existing facilities and with less than 50 million bbl of median technical reserves at the time of project sanction, the Okwori oilfield development went a step further than the more usual subsea tieback to a pre-existing offshore production facility. The Okwori development plan was based on horizontal subsea trees flowing to a leased spread-moored floating production storage and offloading (FPSO) vessel by means of (6-in.) flexible subsea flowlines and risers. The Okwori leased production facilities had a built-in capability for additional tiebacks such as the Nda oil field, whose development was completed in October 2006, or for later redeployment in other parts of the acreage depending on further exploration and appraisal drilling. A review of the field operations to date highlighted a steep learning curve in the formulation of completion design, completion fluids, stimulation, downhole sand exclusion systems, and bean-up/bean-down procedures.