Doris Engineering (France)

Abstract In the current energy shortage and transition context, gas represents an alternative to provide an affordable, reliable and less GHG emissions issuing energy than other available fossil energies. Flow Assurance studies have been launched for a series of gas fields to identify optimal subsea processing functional requirements for a subsea to shore export. The objective is to confirm the robustness of subsea processing architectures identified in previous studies and to evaluate their sensibility towards water depth, step-out, fluid composition and bathymetry. First, real gas fields were selected, the portfolio was completed with notional cases constructed on analogs to reach a good mapping in depth and distance to shore. For each case, bathymetries and PVT models were established. Ledaflow® was used to construct flow models and define the necessary pipeline size based on early and late life flowrates (based upon Erosion Velocity Ratio, Turn down and hydrate risk). When the multiphase export required several pipelines in parallel, an alternative architecture was studied consisting of multiphase pipeline at early life and then gas/liquid separation plus single phases export (separated gas pipeline and liquid pipeline) for late life. Compression and boosting requirement were evaluated. More than one configuration is technically possible. The solution of "multiple multiphase export pipelines" is usually in competition with a "single multiphase pipeline at early life coupled with a subsea separation at late life". The first configuration favors operational flexibility, while the second one favors reduced installation time and cost and allows decreasing the well head back pressure to increase reserves. However, this last solution still requires the installation of a liquid line at late life. Regarding boosting requirements, each configuration has compression needs at late life. The first architecture allows to optimize the compression requirements and increase the process efficiency, while the second one present the drawback of high boosting requirements for the liquid line for great depth and longer step out. For the multiphase export, and a field with very low CGR, the governing parameter for the pressure loss and the compression requirements is the step-out, not the water depth, while, for the subsea separation scheme, the water depth becomes detrimental for the boosting requirements of the liquid line for the great water depths. This large study confirms the feasibility of subsea to shore architectures for gas fields and allows identifying the limitations of the existing technologies and anticipating future technological developments.

Coral reefs are among the most diverse ecosystems on the planet [...]

Hereditary hemorrhagic telangiectasia (HHT) is a systemic disease characterized by mucocutaneous telangiectasias, epistaxis, and arteriovenous malformations (AVMs). Intracranial hemorrhage (ICH) rates in this population are not well described. We report ICH rates and characteristics in HHT patients with brain AVMs (HHT-BAVMs). We studied the first 153 HHT-BAVM patients with follow-up data enrolled in the Brain Vascular Malformation Consortium HHT Project. We estimated ICH rates after BAVM diagnosis. The majority of patients were women (58%) and white (98%). The mean age at BAVM diagnosis was 31±19 years (range, 0-70), with 61% of cases diagnosed on asymptomatic screening. Overall, 14% presented with ICH; among symptomatic cases, 37% presented ruptured. During 493 patient-years of follow-up, 5 ICH events occurred yielding a rate of 1.02% per year (95% confidence interval, 0.42-2.44%). ICH-free survival differed significantly by ICH presentation (P=0.003); ruptured cases had a higher ICH rate (10.07%; 95% confidence interval, 3.25-31.21%) than unruptured cases (0.43%; 95% confidence interval, 0.11-1.73%). Patients with HHT-BAVM who present with hemorrhage are at a higher risk for rehemorrhage compared with patients with BAVM detected presymptomatically.

The understanding of the morphology and the shallow geo-hazards of the seafloor is a major focus for both academic and private industry research. On November and December 2009 a geophysical pipeline survey was carried out by Fugro Oceansismica S.p.A. (FOSPA) and FUGRO France (FFSA) for DORIS Engineering on behalf of GRTgaz (Engineering centre, Transmission Pipe Department; www.grtgaz.com) which are currently investigating the possibility of laying a pipeline between Sardinia and Corsica as a spur line from the planned GALSI Project. The Project, “Alimentation de la Corse en gaz naturel”, consists of a corridor 100 km long and 1.0 km wide along the Corsica-Sardinia shelf. The integration of the multibeam, sidescan sonar and sparker data provided a high resolution seafloor mapping for geo-hazard assessment. In this article the data acquired along a break of slope section (approximately 20 km × 1.5 km), in the eastern sector of the Strait of Bonifacio are described. The area was abandoned during the survey, because of its unsuitability. Indeed, in this area the continental shelf, approximately 100 m deep and deepening gently eastward, is characterized by an uneven morphology, with different seabed features such as Beach-rocks mainly NNW-SSE oriented. Also, the continuity of the continental margin, identified around −110/−115 m, is interrupted by four canyon heads which incise the slope and are associated with glide deposits.

Azurite field is located in the Mer Profonde Sud (MPS) block offshore Republic of Congo in 1400 meters water depth. The field development employs the world's first Floating, Drilling, Production, Storage and Offloading (FDPSO) vessel to produce the Azurite reserves. Six subsea production wells and three water injection wells will deliver a peak production of 40,000 barrels of oil per day (bopd).Azurite production will ramp up over a period of one year. During this time, issues of low temperature caused by low flow, and commingling of well completion and production fluids will present flow assurance challenges. Operationally, among all of the Azurite flow assurance and operability issues, those of artificial lift, wax precipitation and deposition, hydrate formation and unbalanced reservoir pressures are the most critical.This paper highlights the beneficial effects on flow assurance by selecting the FDPSO concept, and presents the flow assurance and system operability challenges and solutions for the Azurite field during startup and development, normal production, and transient periods. Included in the paper is a discussion of artificial lift techniques considered, and the evaluation process that led to selection of seabed multiphase pumps. While Azurite has a relatively short operating history to date, a comparison of predicted versus actual behavior is also presented in this paper.Introduction. Azurite field is located in the Mer Profonde Sud (MPS) block offshore Republic of Congo in 1400m water depth. The field development employs the world's first FDPSO to drill and produce the Azurite reserves. Six subsea production wells and three water injection wells will deliver a peak production of 40,000 bopd.The Azurite reservoir contains black oil with a gravity of 25o API, a gas to oil ratio (GOR) of 460 standard cubic feet per barrel (SCF/bbl) and a high wax appearance temperature (WAT) of 129oF. The predicted water cut (WC) ranges from 0% at initial production to 91% as production declines.Production from Azurite will ramp up over a period of one year. During this time, issues of low temperature caused by low flow, and commingling of well completion and production fluids present flow assurance challenges. Among all of the flow assurance and operability issues for Azurite, artificial lift, wax precipitation and deposition, hydrate formation and unbalanced reservoir pressures are the most critical ones.To ensure system operating flexibility and the ability to displace live fluids, a looped flowline/riser system was selected. To maximize recovery and provide a means of artificial lift, a multiphase pump (MPP) was designed for the subsea production system (SPS).The SPS employs passive thermal insulation and looped flowlines with hot dead oil circulation as the primary means to prevent hydrate formation. To mitigate the risk of wax deposition, an operational strategy of regular pigging and the use of inhibitors were selected.This paper presents the advantages afforded to flow assurance by the FDPSO concept, flow assurance and system operability challenges faced, and solutions developed during the course of design development for field startup, normal production and transient periods for the Azurite field development.

Abstract The « GIFT » concept concerns the development of an offshore floating LNG (Liquefied Natural Gas) storage terminal moored to the seabed by means of a turret mooring system that allows the terminal to weather-vane freely in accordance with the prevailing weather conditions, thus minimizing the loads acting on the terminal and its mooring system in extremely bad weather conditions (typically hurricane in Gulf of Mexico). When the significant wave height is higher than 1.25m (operating limit of the tugs) and lower than 2.5m (unloading operation limit of GIFT), stern transverse thrusters rotate the hull oblique to the direction of the prevailing seas, so that the hull acts like a breakwater and creates a calmer area in its lee side for the tugs, in which they can maneuver the LNG carriers for berthing and mooring. During an LNG carrier unloading and when an LNG carrier is not alongside, the terminal weather-vanes freely again. The terminal will receive LNG from conventional LNG carriers that berth alongside the terminal. The LNG will be regasified onboard the terminal and exported to shore, as gas, via two 16" flexible risers and a subsea pipeline. The objective is to prove feasibility and to increase knowledge of this specific innovative design of floating LNG terminal. The following marine aspects are addressed:Behavior of the terminal alone in survival seas (including mooring and sloshing analyses)LNG carrier approach and berthing including fender DesignBehavior of LNG carrier during unloading at terminal (mooring analysis) A further objective is to investigate the effectiveness, in open water, of equipping the hull with horizontal skirts, to further dampen the terminal motions and the seas in the lee of the terminal. Introduction The concept 'GIFT' is presently developed on the following characteristics:Dimensions : 410 m length × 55m beam × 43m depthReceiving LNG carriers with 75,000m3 to 250,000m3 storage capacitiesTerminal storage capacity of 350,000m3 (6 tanks of 60,000m3 with membrane type containment)Unloading LNG Carrier up to 18,000m3/hour (2 × 5 rigid 16" loading arms)Gas send out capacity of 8 billions cu.m per year (regasification of 45,000m3 of LNG per day)Water depth: 75m in Gulf of Mexico Therefore, the challenge and the technological objectives are to design a terminal, which:Can berth LNG carriers side-by-side in an extended range of weather conditions up to 2.5m significant wave height.Reduce relative movements of the terminal and the LNGcarrier so that the unloading operations are close to those traditionally used in sheltered coastal (inshore) terminals, using existing designs of cryogenic loading arms.Is located at some distance off the coast in order to achieve safe, environmentally friendly, fast and efficient unloading operations, and to avoid traffic congestion and effectively to respond to safety concerns presently raised by onshore regasification plants and approach of LNGcarriers.Is cost effective, constructed and delivered in shorter time than onshore terminals and offshore LNG-GBS's (Gravity Base Structures).

Methanol Losses to the Hydrocarbon Phases in Offshore Pipelines and its Effect on Economics D.F.M. Bruinsma; D.F.M. Bruinsma Colorado School of Mines Search for other works by this author on: This Site Google Scholar P.K. Notz; P.K. Notz Doris, Inc. Search for other works by this author on: This Site Google Scholar J.T. Desens; J.T. Desens Colorado School of Mines Search for other works by this author on: This Site Google Scholar E.D. Sloan E.D. Sloan Colorado School of Mines Search for other works by this author on: This Site Google Scholar Paper presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, October 2003. Paper Number: SPE-84040-MS https://doi.org/10.2118/84040-MS Published: October 05 2003 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation Bruinsma, D.F.M., Notz, P.K., Desens, J.T., and E.D. Sloan. "Methanol Losses to the Hydrocarbon Phases in Offshore Pipelines and its Effect on Economics." Paper presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, October 2003. doi: https://doi.org/10.2118/84040-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE Annual Technical Conference and Exhibition Search Advanced Search AbstractMethanol is the most commonly used hydrate inhibitor in offshore pipelines. The amount of methanol that is lost to the hydrocarbon phases and the implications that this has on the flow assurance strategy and the economics of offshore developments are presented. Methanol losses to the hydrocarbon phases are greatest in pipelines with small amounts of water. For cases of high methanol losses, non-volatile or thermal inhibition methods may be more economical. The importance of accurate predictions of methanol losses is discussed along with the need for experimental data. An experimental technique for measuring methanol partitioning between aqueous and hydrocarbon phases is discussed. Comparisons between predictions and data are made for methanol partitioning between aqueous and hydrocarbon phases of live fluids.IntroductionMethanol is the most widely used gas hydrate inhibitor in offshore pipelines because of its low cost and high thermodynamic effectiveness, on a weight basis. The actual world-wide offshore flowline usage of methanol is impossible to accurately determine at this time. This is because delivered offshore methanol is also used for other purposes and because offshore regulatory agencies do not compile flowline usage data. Based on inhibition needs for existing developments and sales estimates, it is apparent that the annual world-wide offshore methanol usage is in excess of 200 million pounds.One of the least precise areas concerning hydrate inhibition in offshore pipelines is methanol partitioning between the aqueous phase and the hydrocarbon gas and liquid phases. Since methanol is only effective as an inhibitor in the free water phase, any partitioning into the hydrocarbon phases is considered a loss and must be compensated with additional methanol injection.Sample CasesIn order to quantitatively compare methanol usage and the effects on economics, four cases of methanol partitioning are considered. An example gas condensate flowline and an example black oil flowline are considered at both high and low pressures.Gas Condensate Flowline: 200 MMscfd gas, 300 BPD condensate liquid at 40–50 °API with a MW of 100 and 40 BPD water. The moles of hydrocarbons per mole of water is 680.Black Oil Flowline: 10,000 BOPD, 35 °API, MW of 200, GOR of 2000 scf/STB and a water cut of 5% (6.86 moles live oil per mole water).Further properties of the two flowlines are presented in Tables 1 and 2, which were constructed using realistic values for these fluids. Keywords: multiflash 3, fraction meoh, pvt measurement, economics, methanol, prediction, inhibitor, aqueous phase, flowline, concentration Subjects: Pipelines, Flowlines and Risers, Fluid Characterization, Offshore pipelines, Phase behavior and PVT measurements This content is only available via PDF. 2003. Society of Petroleum Engineers You can access this article if you purchase or spend a download.

Abstract As hydrocarbon production is now contemplated for larger and larger water depths, the technical issues related to the import of the fluid stream onboard the floating production facility have to be well resolved. The hybrid riser concept, as developed today, brings a technically and commercially viable solution to this problem. The purpose of the present paper is to describe the latest developments achieved on the hybrid riser technology. The concept presented here is different than that developed for the Girassol field located offshore Angola as it incorporates improvements which have been made after the detailed design of the Girassol unit was completed. The paper gives details on overall geometry and governing criteria for the sizing of the system. Overall fabrication and installation procedures are also presented as well as the main results of the dynamic behaviour of the system when installed on its final location. Introduction When developing hydrocarbons in deep waters or ultra deep waters, that is to say from 1000 m to 3000 m, one of the biggest technological challenges that has to be overcome by the developers comes from the riser system. Indeed, raising the production stream from the sea bottom to the surface is the only feature, together with the mooring system, if not using a dynamic positioning system, which really depends on the actual water depth. The size of the floating unit supporting the production equipment does not vary with the water depth but mainly with the production throughput level and the amount of required storage. Likewise, the sub-sea equipment suitable for 1000 m is very similar to that suitable for 2500 m or even 3000 m, and the water temperature is the same at all these depths. At these depths the water temperature is closed to 4° C. This is rather cold when compared to the hydrate formation temperature, generally around 20° C, or to the wax appearance temperature that could be close to 30 or 40° C. When considering also that most of the reservoirs located in deep waters offshore the West coast of Africa lie in relatively shallow soil depth and are therefore relatively cold, the importance of the thermal properties of the riser system becomes quite obvious. This is why the riser system described in the present paper has been developed for particular applications in deep waters located offshore the coasts of West Africa. Description Of The Tower The tower described here-below has been designed for an application located in the Gulf of Guinea and in 1500 m of water. It is designed to allow the production of 150,000 bpd from 24 wells to be brough to the surface. This layout involves 12 flowlines arranged in 6 piggable loops, plus 2 water injection lines and 1 gas injection line. All these lines are gathered in 2 towers, each one incorporating 6 producing lines, 1 water injection line and 1 gas injection line.

Abstract The paper identities the advantages, features and applicability of a concrete hull for an FPSO and the issues related to project execution. For those considering the options for other fielddevelopments, the paper identifies the conclusions and the work on which these were based. The content of the paper is based on extended studies on the advantages, design features and feasibility of fabrication of thisnew design of FPSO hull. This work formed part of BPs review of options for the development of their Schiehallion field in 375 mctres water depth West of Shetland, the Atlantic Frontier. The conceptual design of vessel hull was carried out with the objective of providing the best solution for a concrete FPSO for BPs application. This included consideration of capital cost, system availability, operating costs, HSE aspects. Decommissioning and disposal, The flexibility of the concept e.g. for addition and modification during service were also examined. The design process was taken to the stage where these matters had been examined and the design has approval in principal for certification. During the design process the mathematical modelling of vessel motions and mooring forces were confirmed in tank tests. BP participated in the proof of concept, retaining the concept on their final short list of two options for the field development. It was concluded by all parties that this new concept had been full examined and proven technically. Introduction This paper has been produced by the Shetland Deepwater Alliance (SDA) with the cooperation and assistance of the BP Atlantic Frontier Programme (AFP) evaluation team. It draws together their shared views and conclusions on the use of concrete as a material for the hull of an FPSO, The following companies formed the alliance SDA for the BP AFP Stage 2 project; DORIS Engineering, Sir Robert McAlpine, Blue water, John Brown and Trafalgar House. During 1994 BP carried out a detailed evaluation process, in full compliance with the European Union regulations, to select a contractor to develop the concept of a concrete FPSO. Among the responding companies, SDA were placed ‘first in class’ for this work and, during the early part of 1995, were invited to tender this concept for Stage 2 of the Atlantic Frontier Programme in competition with other steel and concrete concepts. During the tendering process SDA was coached by BP. This allowed the teams working on the development to exchange views with the objective of achieving the optimum solution for this concept. Another of the benefits of this process was that both parties became familiar with the objectives opportunities and constraints in the design, construction, flexibility and service aspects of the concept A considerable amount of work was carried out by SDA in the development of a concrete hulled FPSO suitable for service West of Shetland. The concept was examined to optimise Capex, Opex, build schedule and flexibility to change during design/constnretion and when in service.