Subsea Production Facilities Research Articles

Optimization of subsea production facilities layout based on cluster manifold system considering seabed topography

High investment in deep-water development highlights the importance of optimizing the subsea layout, a properly optimized subsea production system reduces costs and contributes to production performance. Aiming at the minimum total construction cost of a subsea cluster manifold system, an integrated mathematical model considering the combination of subsea well grouping, cluster manifold layout, connection relationships, pipe routes and seabed topography is developed in this study. A modified adaptive particle swarm optimization (MAPSO) algorithm coupled with A-star algorithm, clustering algorithm and minimum spanning tree algorithm is used to solve the model by using a newly proposed process. The feasibility and practicality of the model is verified by designing the layout of a deep-water oil field, and the influence of manifold number and seabed topography is demonstrated by the difference in suggested cost. The model provides a new method which can be used to estimate costs more reliably.

Simulations of hydrate reformation in the water production line of the second offshore methane hydrate production test in Japan’s Nankai trough

Natural gas hydrates are a potential new energy resource, however, challenges for stable, long-term gas hydrate production remain. This study examines the flow assurance risk of hydrate re-formation in production lines during gas hydrate production, which is a key issue in designing reliable production systems and operations. The focus of this study is the second offshore methane hydrate production test conducted in the Nankai trough area of Japan in 2017, where the depressurization method with a pump, wellbore gas separation, and two production lines for gas and water was applied. In this field test, separation inefficiencies caused significant quantities of gas to be produced from the water production line, posing a risk of hydrate re-formation. To understand and aid in management of this risk, we have developed models of hydrate growth and dissociation in water-dominant flow and conducted flow simulations that were compared to field data from the water production line in this field case. The simulation predictions suggest that the hydrate re-formation was not significant in this production test due to use of flexible hoses with a low overall heat transfer coefficient. The thermal insulation of the flexible hoses contained the heat generated by hydrate formation inside the production lines, resulting in a heat transfer limited system with low hydrate volume fractions (<5.2 vol%). Further simulations were conducted to estimate the sensitivity of such systems to insulation and materials choice, where a system with the flexible hoses replaced with carbon steel pipes was predicted to experience volume fractions four times greater (<19.8 vol%). Given hydrate production test systems typically take the form of short vertical lines, this indicates that pipe insulation may be critical in managing the risk of plugging due to re-formation. This insight is particularly important given the widespread use of carbon steels in subsea production facilities. Simulations enabled by the algorithm presented in this work will inform design choices for future methane hydrate production facilities. The use of thermal insulators will likely limit the degree of hydrate re-formation in such systems, and enable the deployment of management strategies that minimize or eliminate chemical injection.

Design and Mechanical Characteristics Analysis of Deep Sea Manifold System

Subsea manifolds are important equipment for offshore oil and gas extraction. The layout of the manifold is related to both the difficulty of fabrication and the installation and maintenance of the manifold. Based on 1500 m deep sea conditions and 68.9 MPa pipeline fluid pressure, the overall design of a double well groove and double collector subsea manifold is investigated, the selection of specific parameters is discussed in detail. The arrangement of different valves and pipelines and the efficiency of space volume usage are discussed. Stress analysis of the designed manifold as a whole was carried out using AutoPIPE software and its strength was assessed according to the applicable American Society of Mechanical Engineers (ASME) standards. It was found that the maximum stress ratio was 0.9 for radial stresses and relatively small for axial stresses, but both met the design requirements for deep sea manifold piping. Finally, linear and nonlinear buckling analyses of circular arc pipes were carried out, the fifth-order linear eigenvalue buckling modes, linear critical buckling load and nonlinear critical buckling load were obtained. It is found that the nonlinear critical buckling load was 20.5% lower than the linear critical buckling load. The failure mode of post-buckling is local dimple, which is located at the initial defect, indicating that early geometric defects have a greater influence on the load carrying limit of the pipe. This paper can provide a reference for the study of common technologies for the design of deepwater subsea pipeline manifolds and subsea production facilities.

An Analytical Two-Phase Flow Model for Prediction of Leakage in Wet Gas Labyrinth Seals and Pocket Damper Seals. Is Simplicity Still Desired?

Abstract Current and upcoming two-phase pump and compression systems in subsea production facilities must demonstrate long-term operation and continuous availability. Annular pressure seals, limiting secondary flow, also influence the dynamic stability of turbomachinery. Hence, it becomes paramount to quantify the leakage and dynamic force coefficients of annular seals operating with two-phase flow, a liquid in gas mixture or wet gas. Until now, a simple model for labyrinth seals (LSs) and the more modern pocket damper seals (PDSs) is not available, though these seal types find wide applications in subsea machinery. The paper develops a simple analytical model predicting the leakage and cavity pressures for LSs and PDSs operating with two-phase flow. The model adapts Neumann’s leakage equation for use with the physical properties of a homogeneous two-phase flow mixture. Predictions of leakage for a four-blade, eight-pocket, fully partitioned PDS operating under a low supply pressure (PS = 2.3 bar and 3.2 bar) and a low rotor speed equal to 5250 rpm (surface speed = 35 m/s) agree well with experimental results procured for both a pure gas and a wet gas conditions (2.2% in liquid volume). Predicted leakage and cavity pressures also agree with those found by a multimillion node computational fluid dynamics (CFD) model. For an eight-blade, sixteen-pocket PDS supplied with air at PS = 62.1 bar, discharge pressure Pa = 31.1 bar, and rotor speed of 15 krpm (surface speed = 91 m/s), the analytical model predicts leakage that is just 2% larger than a published CFD prediction. For the PDS supplied with an oil in gas mixture having gas volume fraction βS = 0.92–0.98, the simple model delivers leakage that is up to ∼6% lower than published CFD results. An analysis of the two-phase leakage predictions via a modified flow factor reveals a loss coefficient (cd) impervious to the range of supply and discharge pressures considered and growing in proportion to the liquid volume fraction (LVF). Throughout the life of an oil well that sees radical changes in gas and liquid composition as well as pressure conditions, the expedient model, quick and accurate to estimate leakage in wet gases seals, can be readily integrated into an engineering routine or practice.

THE USE OF HYDRAULIC “LONG” LINES IN MODERN SUBSEA PRODUCTION FACILITIES

Describes and provides a brief description of the modern application of hydraulic “long” lines in a subsea production facility. The necessity and relevance of developing a mathematical model that allows us to predict and carry out practical calculations of ongoing processes in hydraulic “long” lines, spending the minimum amount of time and resources on this, is shown. In the article are provided general provisions and basic mathematical relationships for performing calculations and modeling unsteady processes in hydraulic lines with distributed parameters. Boundary conditions are given that make it possible to obtain a closed system of equations representing a mathematical model of hydraulic “long” lines. The scientific novelty of the results presented in the article is that the main criteria necessary for the design and operation of equipment containing hydraulic “long” lines were obtained and presented. Among which it is especially necessary to note, dependences for the unsteady coefficient of hydraulic friction resistance of the pipe λ. Criteria are also given for determining the amplitude of signal attenuation in the case of using a hydraulic “long” line as a line for transmitting information, as well as a criterion that allows to determine the minimum pump flow rate to ensure a given level of purity of the working fluid during operation and maintenance of equipment with hydraulic “long” lines, which It is especially important and relevant in practice for the selection of equipment and determine the minimum required power. The content of the article is interest to specialists involved in the development of hydraulic systems with hydraulic “long” lines.

New risk control mechanism for innovative deepwater artificial seabed system through online risk monitoring system

The current offshore field development concepts (dry tree or subsea tree) have limitations for petroleum production in ultra-deep water (more than 1500 m), where the challenges are characterized by the depth of water, remoteness and harsh environmental conditions. A new alternative offshore field development solution, termed as Deepwater Artificial Seabed (DAS) system, is proposed. The new DAS system offers improved technical and commercial performance, higher levels of safety, reduced interface complexity and improved development flexibility for field development in deep and ultra-deep water. Central to the evaluation and application of the new DAS system is the inherent risk relative to the acceptance level. Hence, barriers in the new DAS system are established and maintained to prevent, control or mitigate undesired events or accidents. This paper investigates a new risk control mechanism for the innovative DAS system in accordance with the online risk monitoring and decision support principle. Firstly, main characteristics and design principle of the DAS system are presented. On this basis, the main hazards for the DAS system are identified, which includes well incident/ loss of well control, mooring system failure, ballast system failure, leak from riser, flexible jumper and subsea production facilities, and damage to riser, flexible jumper and subsea production facilities. The risk level of the identified hazards related to offshore petroleum systems already in use is analyzed and presented by the results from the risk assessment for the Norwegian Continental Shelf (NCS) in the period of 2008–2017. It has been demonstrated that the risk associated with the key sub-systems including the ballast system, mooring system, well system and external impact protection system is at a level that calls for further risk reduction. This is followed by the barrier management principles as well as a discussion of existing and potential barriers in the DAS system. Improved barrier functions in the key sub-systems are analyzed systematically and proposals for alternative barrier functions are suggested based on the online risk modeling and decision support principle. Further, a case study in regard to the DAS mooring system failure event is conducted to demonstrate how the new risk control mechanism works. The proposed new risk control mechanism could improve the safety of the DAS system and convince the offshore petroleum industry for application significantly.

Leakage and Dynamic Force Coefficients of a Pocket Damper Seal Operating Under a Wet Gas Condition: Tests Versus Predictions

AbstractHigh-performance centrifugal compressors presently favor pocket damper seals (PDSs) as a choice of secondary flow control element offering a large effective damping coefficient to mitigate rotor subsynchronous whirl motions. Current and upcoming multiple-phase compression systems in subsea production facilities must demonstrate long-term operation and continuous availability, free of harmful rotor instabilities. Plain annular seals and labyrinth (LABY) seals are notoriously bad choices, whereas a PDS, by stopping the circulation of trapped liquid, operates stably. This paper presents experimental and computational fluid dynamics (CFD) results for the leakage and dynamic force coefficients obtained in a dedicated test facility hosting a fully partitioned PDS (FPPDS), four ribbed and with eight pockets per cavity. The test PDS, operating at a rotor speed 5250 rpm (surface speed 35 m/s) and under a supply pressure/discharge pressure ratio up to 3.2, is supplied with a mixture of air and ISO VG 10 oil whose maximum liquid volume fraction (LVF) is 2.2%, equivalent to a liquid mass fraction of 84%. When supplied with just air (dry condition), the measured leakage increases nonlinearly with supply pressure. Under a wet gas condition, the recorded mass flow increases on account of the large difference in density between the liquid and the gas. CFD-derived mass flow rates for both dry and wet gas conditions agree with the measured ones. The test dry gas PDS produces a direct dynamic stiffness (HR) increasing with frequency, whereas the direct damping (C) and cross-coupled dynamic stiffness (hR) coefficients remain relatively constant. The CFD-predicted damping agrees best with the test C albeit overpredicting HR at low excitation frequencies and hR at all frequencies (&lt;175 Hz ∼ twice rotor speed). Under a wet gas condition with LVF = 0.4%, the test force coefficients show great variability over the excitation frequency range; in particular, HR &lt; 0, though growing with frequency due to the large liquid mass fraction. The CFD predictions, on the other hand, produce a dynamic direct stiffness HR &gt; 0 for all frequencies. Both experimental hR and C for the wet gas PDS are larger than their counterparts for the dry gas seal. The CFD-predicted C and hR, wet versus dry, show a modest growth, yet remaining lower than the test data. The CFD-derived flow field for a wet gas condition shows that the seal radial partition walls (ridges) reduce the circumferential flow velocity and liquid accumulation within a pocket. Both the test data and the CFD prediction show that the magnitude of the flexibility function for the PDS test system reduces when the two-component mixture flows through the seal, hence revealing the additional effective damping, more pronounced for the test data rather than that from the predictions. Further work, experimental and CFD based, will continue to advance the technology of wet gas seals while bridging the gap between test data and computational physics model simulations.

A mathematical model of virtual simulation for deepwater installation of subsea production facilities

Virtual reality (VR) based on deepwater installation training provides new workers or inexperienced workers with rehearsing and training environment so that they can immerse themselves in this environment and improve their manipulative skills fast and efficiently. It can greatly cut down the training cost and decrease losses produced by mis-operations. In order to effectively achieve this training goal, it is crucial to express the response of multi-body system comprised of vessel, crane, cable and lifted equipment, truly and reliably. This paper proposes a mathematical model for the response analysis of multi-body system. The solution of the mathematical model for virtual simulation is also presented. The architecture of VR simulation system and the crane simulator are designed. A case study was performed to validate the feasibility of the proposed model. The results show the VR simulation training system has a high reality and response rate. This indicates the applicability of the proposed mathematical model and the VR system in deepwater installation simulation of subsea production facilities.

The Study on the SIT Technology of Subsea ILM

With the development of offshore oil and gas field enters into deep water constantly, subsea production system has become the main development mode in deep water development. Subsea Inline manifold (ILM) is common facilities in subsea production system and is used to gather oil and gas from the side subsea wells. Two subsea ILMs has been adopted in Panyu 35-1/35-2 Gas field with water depth range from 194 to 338 m in South China Sea. System integration test (SIT) is very important for the subsea production facilities. This paper states the flow chart, master equipment, purpose and precautions for each test of ILM SIT, which collects great technology for the development of subsea production system.

The Research on the Factory Accept Test Technology of Subsea PLET

With the development of offshore oil and gas field enters into deep water constantly, subsea production system has become the main development mode in deep water development. Pipeline End Termination (PLET) is common facilities in subsea production system and is used to provide subsea tieback interface. An embedded type PLET has been adopted in Panyu 35-1/35-2 Gas field with the water depth of 194 to 338 m. Factory Accept Test (FAT) is very important for the subsea production facilities, and the references is very limited due to technical security. This paper in detail states the flow chart, master equipment, purpose and precautions for each test of FAT for PLET, which collects great technology for the development of subsea production system.

Worst‐case design of subsea production facilities using semi‐infinite programming

The problem of designing novel process systems for deployment in extreme and hostile environments is addressed. Specifically, the process system of interest is a subsea production facility for ultra deepwater oil and gas production. The costs associated with operational failures in deepwater environments are prohibitively high and, therefore, warrant the application of worst‐case design strategies. That is, prior to the construction and deployment of a process, a certificate of robust feasibility is obtained for the proposed design. The concept of worst‐case design is addressed by formulating the design feasibility problem as a semi‐infinite optimization problem with implicit functions embedded. A basic model of a subsea production facility is presented for a case study of rigorous performance and safety verification. Relying on recent advances in global optimization of implicit functions and semi‐infinite programming, the design feasibility problem is solved, demonstrating that this approach is effective in addressing the problem of worst‐case design of novel process systems. © 2014 American Institute of Chemical Engineers AIChE J, 60: 2513–2524, 2014

Developing Long-Distance Power-Distribution Systems

The vision of installing large subsea production facilities in remote offshore locations is today, simply not feasible. The problem is that subsea power systems are not designed to transmit high-voltage electricity to a production facility or pipeline tieback that may be under thousands of feet of water and 100 miles away from the nearest power plant. Today’s subsea power-distribution technology is largely based on alternating- current (AC) technology, which, because of its electrical characteristics, can only be efficiently transmitted across a distance of 90 miles. In most cases, however, the effective distance is much less. On average, subsea tiebacks receive power from a platform or vessel located not more than 10 miles away and, in the case of most subsea processing systems, even closer. In an AC-supplied system, the flow of electricity alternates back and forth across the transmission line and is the form of electricity most commonly used in homes and businesses around the world. When long distances are involved, AC power distribution becomes a complicated operation and requires a great amount of attention to detail because of the physics involved with voltage regulation. The search for an alternative to conventional AC systems has revealed the need for multiple technological advancements, from pressure compensated electrical switches to highly-conductive cables able to deliver power more efficiently. About 5 years ago, “We were looking at going to farther distances with alternating current instead of direct current (DC) because most of the equipment we have right now is AC powered,” said James Pappas, vice president of the Research Partnership to Secure Energy for America’s (RPSEA) ultradeepwater program. He said that, after studying the issue, however, it was determined that using AC power could result in a 35% power loss in a 100-mile-long cable because of resistivity and other factors. Not long after that conclusion was reached, General Electric (GE) approached RPSEA with a concept to transfer all the power to a deepwater field with DC and then use a subsea transformer module located within the field to convert some of the power to AC. With this system, the expected power loss over 100 miles could be as low as 25%. “So, if you have AC components, it can convert power to AC for those components, and if you need DC, then it has DC components,” Pappas said. “It all sounds pretty simple until you want to put it in a package and then set it down in 10,000 ft of salt water.”

A mechanistic model for hydrocarbon plumes rising through water

For releases of hydrocarbons from a subsea pipeline, riser, or production facility, the shape of the plume rising through the water must be predicted prior to any assessment of gas dispersion, liquid pools, or fire above the water surface. The location and size of the plume at the water surface are key parameters for subsequent consequence modeling. A mechanistic model has been developed to predict the plume trajectory and size, based on mass and momentum balances and an empirical water entrainment ratio from the literature. With suitable physical property values available, the model is applicable to releases of gas and/or liquid hydrocarbons, predicting the vaporization and vapor expansion due to decreasing hydrostatic pressure as the plume rises through the water. Some validation of the model was obtained with 16 tests in a small-scale transparent tank. The data cover a wide range of flow rates, including both choked and unchoked flow. The predicted and measured trajectories (centerline displacement) agreed reasonably well. Predictions of the model are presented for three fluids. The model is valuable for assessing the consequences of underwater hydrocarbon releases, providing input for subsequent modeling of gas dispersion or liquid pools and pool fires.

The Application of ROV for the Subsea Christmas Tree Installation in the LiWan3-1 Deepwater Oilfield

Chinas offshore oil and gas has been developed from shallow water to deep water. Subsea production facilities play more and more role in deepwater oil and gas fields, in which Christmas tree is the key equipment to control and regulate the oil well production of deepwater production systems, but it has great installation costs and risk. For complex underwater environment, it is necessary to find a best way to install the Christmas tree securely and rapidly. ROV (Remotely Operated Vehicle) is wildly used in the field of offshore oil, especially in deep water for its large working depth, safe, efficient and other characteristics, and it has become an indispensable tool for development of deep-sea oil and gas. In one Christmas tree installation at Liwan3-1 deepwater oilfield, the ROV succeeded in assisting the installation of Christmas tree. The solutions for winding and wrong operation risk in installation process are given in the end.

High-Value Engineering Center: Implementing a Major Capital Project - Gorgon

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 145708, ’Use of a High- Value Engineering Center in Execution of a Major Capital Project, Gorgon,’ by Siva Malladi, SPE, Parag Shah, and David Cruikshank, Chevron, prepared for the 2011 SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 20-22 September. The paper has not been peer reviewed. The Chevron-operated Gorgon Project is off the northwest coast of Western Australia and encompasses several megaprojects, including an all-subsea upstream development of the Greater Gorgon gas fields. Because of its sheer size, scale, and complexity, in addition to several unique characteristics, the Gorgon Project required an extraordinary level of project management. A key project-management strategy was appointment of a high-value engineering center (HVEC) in Jakarta. Introduction This project is one of the world’s largest natural-gas projects and the largest single-resource project in Australia’s history. The development program includes several megaproject components. Gorgon Upstream—comprising subsea production facilities, pipeline facilities, and domestic gas-export facilities. Gorgon Downstream—comprising a 15×106 t/a liquefied-natural-gas (LNG) plant on Barrow Island, gas-receiving and processing facilities (e.g., slug catchers, heaters/coolers, acid-gas-removal plants, gas-dehydration plants for pretreatment of feed gas to the LNG plant), condensate-stabilization facilities, monoethylene glycol regeneration, LNG/condensate storage and offloading, power-generation and -distribution facilities, and other utilities to support the LNG plant. A domestic gas plant with the capacity to provide 300 TJ/d to supply gas to Western Australia. Carbon dioxide (CO2) injection. LNG-export terminal. Infrastructure facilities—camp, buildings, logistics, telecommunications, and other facilities to support the construction and operation of the LNG-plant facilities on Barrow Island. The full-length paper details the scope associated with the HVEC work for the Gorgon-Downstream project, the evaluation undertaken of the Jakarta HVEC, and the challenges encountered and remedial tac-tics used during the execution of the HVEC work. The engineering and procurement portions of the downstream project were completed at the main execution centers (ECs) in London (two offices), Singapore (one office), and Jakarta (one office). Part of the execution strategy was the use of an HVEC in Jakarta to support the main ECs in the UK, operating as a remote design resource. The project-execution plan for performing this work was the following. The main EC would perform the detailed engineering, begin the 3D-modeling work, bring the model up to between 40 and 60% maturity for various disciplines, and transfer the design-work scope to the HVEC. The workscope transition would occur in a staggered sequence for various work areas—modules, preassembled racks (PARs), preassembled units (PAUs), and stick-built areas—in accordance with the EC execution sequence and in line with the overall project schedule. The HVEC would pick up the 3D model from that point and develop it to final completion to generate the required deliverables, as described in the following section.

Technology Focus: Offshore Facilities (February 2010)

Technology Focus In the relentless quest for reserves replacement, global upstream oil and gas operators continue their migration into deeper waters. The latest generation of subsea production facilities is widely applicable with confidence when specified correctly. However, selecting the optimum associated surface-processing facilities, and how best to link them to the subsea system, generally requires a more location-specific deliberation. While field developments in established deepwater provinces such as the Gulf of Mexico, Brazil, and west Africa continue to expand, new deepwater regions such as in Southeast Asia and the Bay of Bengal off the east coast of India are being opened. However, even the well-established structural-design standards evolved by the industry for the Gulf of Mexico were recently shown by hurricanes Katrina and Rita to need a further overhaul in the way they are applied. An unprecedented scarcity of equipment and resources suitable for deepwater drilling and construction also has driven up the unit costs and project durations sharply for deepwater developments in recent times. All these factors have, collectively, encouraged the industry to seek and qualify an expanded and more flexible range of modular and integrated field-development solutions that can be optimized and applied more quickly in a reliable and cost-effective manner for the wider spectrum of deepwater challenges ahead. Among the most notable is the industry’s first floating-drilling, -production, -storage, and -offloading-based system that went into operation in deep water offshore west Africa during the past year. These innovative floating and subsea deepwater solutions, when demonstrated by analyses and tests to be truly fit for purpose, are, however, only of meaningful value if upstream operators respond proactively with practical ways to apply them in the field quickly and confidently. Offshore Facilities additional reading available at OnePetro: www.onepetro.org OTC 19929 • “The Greater-Plutonio Riser Tower” by Daniel de la Cruz, BP, et al. OTC 19857 • “Tahiti Spar as a Wet-Tree Concept” by P. Griffin, Chevron, et al. SPE 124158 • “Northwest Hutton: Decommissioning the UK North Sea’s First Large Platform With a Fixed Steel Jacket: Topside Removal” by Chris R. Farrow, BP, et al.

THE DEVELOPMENT OF GORGON AREA GAS

Australia will increasingly need to turn to natural gas to offset declining oil production and meet an expanding global need for clean energy. The Gorgon Development Joint Venture Participants, (ChevronTexaco/Exxon- Mobil/Shell), are poised to develop the significant Gorgon gas reserves located 130 km offshore the North West Australian coast to help fulfil this need.The Gorgon Development has access to extensive proved reserves of 13.8 Tcf and a development plan that can supply gas to a Barrow Island landfall at world competitive prices. Several concepts are being considered for development of the Gorgon reserves.Technology will play a key role, with the extensive use of subsea production facilities and innovative LNG design concepts being considered.The focus is on a design that would have a low unit cost and also provide new benchmarks in safety and environmental performance. The development of the Gorgon reserves could also facilitate the establishment of other gas-based industries in Western Australia and offers the opportunity for new gas-to-liquid (GTL) plants to lead Australia’s transition to a gas-based economy.The Gorgon Development is expected to attract nearly A$4 billion investment for an LNG development and a further A$2 billion for a major industrial gas consumer. Total export income could reach A$2,500 million per year for 30 years.

A Consistent Thermodynamic Model for Predicting Combined Wax‐Hydrate in Petroleum Reservoir Fluids

Abstract: Low oil prices and the competitive nature of the oil industry world‐wide demand more cost‐effective techniques in the development and operation of offshore reservoirs. Extended‐reach gathering networks and transportation of unprocessed well streams by subsea pipelines are two attractive options that could have significant impact in the development of marginal oil/gas fields. These subsea pipelines are prone to wax and/or hydrate formation that can potentially block the pipelines and lead to serious safety and operational problems. Wax and hydrate formation are both examples of solid deposition. They are modelled conventionally and are studied independently. In this work we describe a wax model that has been developed based on regular solution theory. The wax model was successfully coupled with an existing hydrate model. The integrated wax‐hydrate model is capable of predicting five phase equilibria (i.e., water, liquid hydrocarbon, vapor, wax, and hydrate) as well as predicting the effect of wax formation on the hydrate phase boundary and vice versa. The results show that a reliable wax‐hydrate model can minimize the risks involved in the transportation of fluids prone to wax and hydrate formation. The model can be used as a powerful tool in the design and operation of subsea and arctic pipelines and production facilities.

THE PERSISTENCE AND EFFECTS OF NON-WATER-BASED DRILLING FLUIDS ON AUSTRALIA'S NORTH WEST SHELF: PROGRESS FINDINGS FROM THREE SEABED SURVEYS

The effects and persistence of non-water-based drilling fluids discharged into the marine environment were investigated at three locations on Western Australia's North West Shelf (NWS), namely the North Rankin 4A' (NRA) drilling platform, the Wanaea–6 production well and the Lynx–la exploration well. For the multiple-well drilling operation at NRA, acute biological effects at the completion of drilling were restricted to within 400 m in the direction of the prevailing current. High total petroleum hydrocarbon (TPH) concentrations within the NRA cuttings pile persisted between 1991 and 1993. Away from the cuttings pile itself, a consistent downward trend in TPH concentrations was evident, indicating an approximate half-life of one year for surface sediments. Three years after the completion of drilling at Wanaea–6, biological effects appeared to be limited to within 100 m of the cuttings discharge point, with background concentrations of TPH and trace metals occurring near 1,200 m in the direction of the prevailing current. Sediment hydrocarbon concentrations greater than 1 mg/kg were found to be restricted to within 200 m of the cuttings discharge point. Dramatic reductions in TPH and barium concentrations occurred in the 12-month period between the completion of drilling and the follow- up survey at Lynx–la. The reductions are attributed to sediment dispersal mechanisms which appear to play a major role in reducing sediment TPH and trace metal concentrations in mid-shelf water depths (70–80 m) on the NWS. The installation and presence of subsea production facilities may result in sediment redistribution and changed dispersal mechanisms, complicating the interpretation of the presence of contaminants within sediments.

The Highlander Field - One Year's Operating Experience

Summary In 1985 the Highlander field was brought on stream from one of the first generation of advanced remote-controlled subsea production facilities in the North Sea only 15 months after the U. K. Dept. of Energy approved development. The successful development of the Highlander field was made possible by a combination of innovative ideas and the advancement of existing technology. This paper describes the problems and successes during 1 year of operating experience. Introduction The Highlander field is located in Block 14/20, 8 miles [12.9 km] northwest of the Tartan platform in 420 ft [128 m] of water (Fig. 1). Because "stand-alone"-type developments were seen as uneconomical, the decision was made to develop the field with a remote-controlled subsea production and water-injection facility would be controlled by and produced to the Tartan platform. The development was completed in two phases, a procedure that substantially reduced the time from project approval to first oil being produced. Phase 1 consisted of running well completions in predrilled, offtemplate wells and connecting these wells to the Tartan platform through two 8-in. [200-mm] service lines. During Phase 2, the template and slug catchers were installed; the wells were reconnected to the template; and the template, test and bulk production pipelines, slug catchers, and risers were commissioned. These two phases are described more fully by Smith and Batcheler. This paper deals with the operating experience of Phase 2. The development originally consisted of four wells-Wells HS12, HS13, HS14, and HS15-previously drilled and suspended between 1980 and 1983. In 1985, these wells were completed and tied into a subsea template that has 12 additional slots for future wells. Since then, three wells (Wells H1, H2, and H3) have been drilled successfully through the template. All wells and services are interconnected by manifolds on the template. Production to the Tartan platform is through 12-in. [300-mm] bulk and 8-in. [200-mm] test multiphase pipelines. The pipelines are connected into two subsea slug catchers at the base of the Tartan platform. These slug catchers are designed to eliminate slugging before oil is pumped up to the platform through two 7-in. [180-mm] casing strings. Gas is separated out of the crude at the slug catchers and routed to the platform through the 18 5/8x7-in. [470X180-mm] riser annuli. The template is also connected to the Tartan platform by 8-in. [200-mm] waterinjection, 8-in. [200-mm] gas-lift, and 4-in. [100-mm] utility flowlines. Umbilicals provide hydraulic and electrical power and chemical injection to the template. Maintenance is by diver intervention during well servicing, and workovers require a diving support vessel or semisubmersible drilling rig. A new subsea wireline technique, successfully tested on Well HS14 in Nov. 1987, allows routine well work to be carried out from either a diving support vessel or a semisubmersible drilling rig simultaneously with the drilling of new wells. This will substantially reduce well-servicing costs.