bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hydrate Risk Assessment and Restart Procedure Optimization of an Offshore Well Using a Transient Hydrate Prediction Model
Authors: Zerpa Luis Eduardo , Sloan E. Dendy , Koh Carolyn , Sum Amadeu 
Published: October 2011

Abstract
A produced hydrocarbon stream from a wellhead encounters formation of solid gas hydrate deposits, which plug flowlines, and are one of the most challenging problems in deep subsea facilities. This paper describes a gas hydrate model for oil-dominated systems, which can be used for the design and optimization of facilities focusing in the prevention, management and remediation of hydrates in flowlines. Using a typical geometry and fluid properties of an offshore well from the Caratinga Field located in the Campos Basin in Brazil, the gas hydrate model is applied to study the hydrate plugging risk at three different periods of the well life. Additionally, the gas hydrate model is applied to study the performance of the injection of ethanol as thermodynamic hydrate inhibitor in steady-state flow and transient shut-in/restart operations. The application of the transient gas hydrate model proved to be useful in determining the optimal ethanol concentration that minimized the hydrate plugging risk.

Introduction
Offshore explorations in deeper and colder waters impose more challenging scenarios to the flow assurance of the produced streams. High pressures and low temperatures of operation of production facilities with longer subsea tiebacks will promote the formation of natural gas hydrates; crystalline compounds formed by hydrogen-bonded water molecules in a lattice structure that is stabilized by encapsulating a small guest molecule (e.g., methane, ethane) (Sloan and Koh, 2008). Gas hydrates form in the presence of appropriate quantities of gas and water, and are considered one of the most challenging problems in deep subsea facilities, due to its rapid formation compared to other solid deposits (Sloan, 2005).
A transient gas hydrates model, that predicts when and where hydrate plugs will form in flowlines, will have significant utility for the flow assurance engineer in the oil and gas industry. By predicting gas hydrates formation and transportability, the gas hydrate model can be applied to design and optimize oil/gas transport facilities, focusing on prevention, management or remediation of gas hydrates in flowlines. This paper briefly presents a gas hydrate model specially designed for oil-dominated systems, which has been incorporated as a plug-in module in a transient multiphase flow simulator (Turner et al., 2005). The gas hydrate model developed for oil-dominated systems follows the conceptual model presented in Figure 1, where hydrates form at the interface of water droplets entrained in the continuous oil phase. In the oil phase, these hydrate-encrusted water droplets can agglomerate increasing into larger hydrate masses, leading to an increase in the slurry viscosity, which can eventually form a plug (Turner, 2005).
Challenging Horizontal Open Hole Completion in Carbonates: A Case History on Mechanical Isolation and Selective Stimulation in Campos Basin, Brazil
Authors: Villanueva Guillermo Jose , Canas Jesus Alberto , Gigena Daniel , Ferreira Armando , Vidal Jose Oliveira , Pinto Rachel , Landinez Giovanni Alvaro , Jouiti Iwao , Rafainer Gilberto , Cancio Augusto , D&apos;Oliveira Diogo Scarcelli , da silva Wesley 
Published: October 2011

Abstract
This paper describe in details the design and successful operation of an acid diversion completion system, which was used for first time in an exploratory project offshore Brazil.
The most significant discoveries in a recent exploratory campaign in Campos Basin were in carbonate reservoirs. The first vertical well test showed a high heterogeneous and natural fractured carbonate reservoir. Considering the reservoir characteristics, analytical and numerical modeling was performed to assess the productivity of horizontal wells compared to vertical wells.
As part of the Operator strategy of developing this oil field using maximum reservoir contact, a well test evaluation project in the open hole section, mitigating the risk of reducing the production, fractures cementation, etc. was performed. The whole project was developed to address the challenges of carbonate horizontal wells i.e. low permeability sections contributing marginally to the total production.
A multistage horizontal open hole completion was designed and installed to perform a separately and selective stimulation in more than 3,000 ft of horizontal section. Previously, the most advanced technologies for open hole completions with mechanical isolation were reviewed to have the ability to perform multiples stimulations (fracture or matrix) in one continuous and more efficient operation.
Based on final reservoir data obtained during the horizontal open hole navigation and a calibrated Geomechanical model, the acid diversion completion system was selected to perform an acid stimulation instead of a high pressure acid fracture job.
The application was successfully run in this anisotropic carbonate reservoir and eight compartments were stimulated using an acid plant and high pressure pumps mounted on a Supply Boat dynamically positioned. More than 1000 barrels of stimulation fluid; a mixture of hydrochloride acid, and a visco-elastic agent to improve diversion were pumped stage by stage to the reservoir with a real time monitoring at the operator Support Center in Rio de Janeiro.
After all the stimulation jobs and to prevent the high fluid losses, the well was shut in downhole using the reservoir formation isolation valve. A DST string was run. CT and Nitrogen were used to kick off the well and after 6 hours the well started to flow naturally, with first oil at surface within the first 8 hours of flow.
Verification of the Performance of Insulation Materials Used for Deep-Water Offshore Applications
Authors: Edmondson Stephen , Heydrich Stephen , Xu Bo , Moscarello Raphael 
Published: October 2011

Abstract
Insulation is commonly applied to offshore pipelines to ensure the flow of hydrocarbons at elevated temperatures. The thermal properties of the insulation can be readily modeled; however, the performance of the insulation needs to be verified under conditions similar to those encountered in deepwater service. Autoclave testing of individual materials can be conducted but this is not representative of the conditions that the materials see in service. The insulation is typically present in layers, and not every layer is exposed to the same environment. Simulated service testing, where a full size pipe is exposed to a water pressure equivalent to that it will see in deepwater service load, is typically used to verify the performance of the insulation.
This paper presents the unique combination of a process control discipline with the data measurement capability of a new Simulated Service Vessel (SSV) to ensure accurate determination of U value for insulation systems in a deepwater environment.

INTRODUCTION
During the development and qualification of insulation systems for subsea oil and gas pipelines it is important to understand and quantify the behavior of the insulation under service conditions experienced in subsea environments. ShawCor's Simulated Service Vessel (SSV) is a key part of a new state of the art facility built to do just this.
Controlling Hydrate Slurry Transportability by Optimizing Anti-Agglomerant Usage in High Water Cut Systems
Authors: moradpour hossein , Chapoy Antonin , Tohidi Bahman 
Published: October 2011

Abstract
For mature fields with high increasing water cut, gas hydrate is a serious problem because hydrate inhibition with thermodynamic inhibitors, such as methanol and glycols, often become economically and logistically unpractical.
The potential of transporting hydrate particles using anti-agglomerant (AA) in high water cuts systems could be an attractive alternative to the traditional approaches. AAs have long been considered for improving transportability of hydrate slurry flow in pipelines. Although many pilot tests and a few field tests have been conducted, the economics of AA injection have rarely been favourable. Most AA studies focused on the injection of AAs at concentrations higher than 1% to create transportable hydrate slurry. The operational cost of such a process can be only favourable if water cut is very low and oil prices are high.
From the economic point of view, it would be more profitable to decrease as much as possible the AA concentration, in particular in high water cut systems. Low AA concentration restriction is expected to benefit not only the economical viability of the oil and gas production but also minimize the potential environmental impact of the AAs.
In this communication, systematic experiments were conducted to determine the effect of AA on apparent viscosity of water/oil/hydrate mixture at different AA concentrations ranging from 0.15 to 2% (w/w) of aqueous phase. The water cut in the emulsion was varied from 60% to 80%. Hydrate formation was controlled, by injecting gas, until apparent viscosity of hydrate slurry increased sharply at a certain hydrate volume fraction.
The results based on the systems and AA tested show that rheology of hydrate slurry strongly depends on the AA concentration, type of emulsion before hydrate formation and the nature of the liquid hydrocarbon phase. It was also concluded that hydrate transportability depends on the amount of hydrates in the system (not the water cut as generally believed). Therefore, for high water-cut systems where gas is the limiting reactant, it is possible to form transportable hydrate slurries at much lower AA concentrations. This could result in economical application of AA in high water cut systems.

Introduction
Hydrates are ice-like solids that could form whenever water molecules come into contact with a hydrate forming compound (usually present in gas or live oil phases) at suitable combinations of temperature and pressure (Sloan and Koh, 2008). These solids may form in production equipment and/or pipelines and may form a blockage, obstructing the production facilities. Preventing gas hydrate blockage is a major challenge for flow assurance in oil and gas production and transportation.
Maximizing Platform Space Utilization Through the Latest in Multiphase Metering - A North Sea Pilot
Authors: Berge Finn Erik Mohn , Brandt Morten , Fredheim Dag 
Published: October 2011

Abstract
Brazilian operations today are faced with limited deck space on platforms and rigs, the principal reasons being the increased number of wellheads, Xmas trees and piping arrangements that operators must incorporate into complex production systems.
The result is that fitting crucial equipment, such as multiphase meters, is often a difficult challenge. And this at a time when the ability of multiphase meters to accurately measure complex flow regimes, and generate information on water saturation, break through and gas coning, is crucial to production optimization. Petrobras, for example, has indicated that they would like to see a multiphase meter on each of their wells and trees.
This paper will look at how Emerson, in cooperation with FMC Technologies and Statoil, has found a solution which is meeting the requirements of better maximizing space on offshore platforms and the development of a new flow measurement principle to map complex flow regimes.
The new meter design allows the meter to be retrofitted on X-mas trees in a simple intervention without the need to modify the current well head design. The new measurement principal, based on an electrode geometry sensor, provides more detailed knowledge on flow rates and complex flow patterns.
Focusing on the North Sea's Oseberg platform, where the installation of instrumentation such as multiphase meters is very difficult, the paper will look at the development of the new solution by Emerson, FMC and Statoil.
The paper will chart the results of the Oseberg pilot, where the new meter was deployed on the platform with preliminary flow tests indicating that the results are as good as for regular multiphase meters. The paper will also reference a new high pressure/high temperature version of the meter, ideal for the deepwaters offshore Brazil.
The paper will conclude on the benefits of this new solution in flow assurance and the implications for use offshore Brazil, where there is a need for multiphase meters and where many platforms are limited in terms of space.

Introduction - Meeting the Twin Challenges of Multiphase Meters but Limited Deck Space
Many oil & gas operators today are faced with limited deck space on their existing platforms and rigs. There are a number of reasons for this from the growth of small, satellite offshore platforms through to the increased number of wellheads, Xmas trees, piping arrangements and other equipment that operators must incorporate into their production systems.
Supply Vessel Market Trends in Brazil
Authors: Simonsen Eirik 
Published: October 2011

Abstract

Slide 1
Ladies and gentlemen good morning — my thanks to the OTC Brazil's Program Committee for the invitation to be here today to present the ODS??Petrodata view on the supply vessel market.

Slide 2
First a few words about the company I am representing. ODS??Petrodata has this year become a part of the global information company IHS. Our mutual goal is to be the source of critical information and insight within the energy markets.

Slide 3
ODS??Petrodata is an independent market intelligence company, and our only agenda is to present reliable data and relevant information about the oil & gas markets. We are mostly known for our databases tracking all existing and planned offshore fields as well as tracking historic and contracted activity for all offshore rigs & vessels. We also have a significant consultancy business that will be further strengthened by being integrated with IHS.

Slide 4
The focus of this presentation is the outlook for the Brazilian supply vessel market. As the global supply vessel market will significantly impact the Brazilian market, I would like to first present our view on the global market.

Global supply vessel market
We include Platform Supply Vessels (PSV) and Anchor Handling Tug Supply (AHTS) vessels in this market segment. Today, we have about 2,500 supply vessels in operation and about 350 vessels under construction. About 60% of the fleet is AHTS and 40% is PSV. Analyzing the supply vessel market, we normally split the market in a Harsh & Deepwater segment (H&D) and a Shallow & Benign segment. We include AHTS with more than 10,000 horsepower capacity (BHP) and PSV with more than 2,000 deadweight tons (dwt) in the H&D segment and smaller capacity supply vessels in the S&B segment. H&D includes all water depths in the North Atlantic and the rest of the world in water depths above 100 meter while S&B includes rest of the world in water depths less than 100 meter. Nearly 45% of the supply vessel fleet is included in the H&D category.
Recovery of Retrograde Condensed Liquid in Mature Reservoirs of Gas Condensate in Latin America
Authors: Vega Riveros Gina Luz , Yehya Emad , Saputelli Luigi Alfonso 
Published: October 2011

Abstract
The clear increase of the gas and gas condensate reserves at the Eastern part of Venezuela during the last decades can be considered as the best evidence of the current huge efforts to develop those gas potential. More than 65% of the remaining gas reserves are concentrated in the Eastern part of the country, most of which show an initial reservoir pressure equals to or greater than the dew-point pressure, the reservoir temperature is between the critical and the cricondentherm temperatures, and the hydrocarbon mixture originally exists as a single-phase dew-point gas. As a result this would suggest " in-situ?? liquid drop-out between 2 to 12 percent which then after would hinder the natural gas production.
This paper shows the obtained results from studied cases of some routine or cyclic dry gas injection in wells of carbonate reservoirs. It has been concluded from the course of study that it is possible to re-evaporate the condensate liquid, especially around the wellbore through changing the composition of the in-situ liquid drop-out. This micro-compositional effect upon the liquid drop-out in the porous media within the vicinity of the well-bore would increase the chance to prolong the multi-wells gas reservoir production life. Previous experiences of dry gas injection were obtained in the mature gas condensate reservoir belonging to the Rapid River and Cold Spring Fields (located in Canada) via injecting pressurized dry gas which leads to an increase of the surface liquid production from 5 to 15 STB/MMSCF. A similar test was made on 12 reservoirs belonging to Cold Spring Field which also leads to an increase of the surface liquid production from 8 to 10 STB/MMSCF, meaning an increase of surface liquid production of almost 25%.
Venezuelan reservoir fluids under this study have shown concentrations of 2% to 4% of H2S and 10% to 25% of CO2. Initial Production tests combined with PVT data have shown a progressive degradation in hydrocarbon fluid properties with depth and have also shown a sharp decrease of hydrocarbon gravity from 50° to 32° API. The fluid profile showed a noticeable variation from the shallowest reservoirs, with mainly gas condensate fluids, to the deepest ones with mainly volatile types of fluids. The producing GOR of the gas condensate reservoirs ranges from 5000 to 16000 Scf/STB, whereas those for volatile oils range from 2000 to 5000 Scf/STB. Some gas condensate reservoirs have C7+ mole percentages of less than 12.5.
The lab swelling experiments using commercial simulator and field experiences in Latin America have permitted to prove that the injection of dry gas will yield a modification of the reservoir fluid composition as well as its phase envelope, which would increase at the same time the cumulative production, the recovery factor and the production life of the reservoirs.
Swivel Connection Development
Authors: Da Silveira Helvecio Carlos K. , Cardoso Leonardo , Candiani Ivan , Dias Rodrigo 
Published: October 2011

The information contained herein is the confidential property of GE Oil & Gas and its affiliates, is to be used only for the benefit of GE Oil & Gas and shall not be reproduced or used for any other purpose without written consent of GE Oil & Gas.

Abstract
The required adaptability of the production systems to field evolution presents the flexible flowlines as a suitable solution, with advantages to rigid pipelines. The usage of flexible flowlines associated to the challenges of deep and ultra-deep water explorations and increment of Working Pressure promotes the metal-to-metal swivel connections to required components for subsea equipment, leading installation reliability and assuring operational confidence.
In order to reduce operational risks during pipelines and in-lines installations, different designs of Swivel connections had been used on the last 10 years. All designs had the same concept of a Metal-to-Metal Seal with an energizing system that add some risk to the system and requires ROV operations.
The present work shows a new Swivel concept for 2500 meter of water depth and 10,000psi of working pressure, that uses a Metal-to-Metal Seal on seat and not require a ROV intervention. On this concept, the Metal-to-Metal Seal run during the installation on energized position and allow relative movement between the inlet and outlet Swivel connection. Also, this kind of concept permit to work with one Metal-to-Metal Seal design for different Swivel sizes, which means that the deliverable time for the Swivel could be reduced and make easier the maintainability of the Swivel connection.
ESP Assisted Production Allocation in Peregrino Field
Authors: Olsen Helge , Sheth Ketan , Pessoa Rui Francisco , Okita Risa , Crossley Alexander , Martinez Ignacio 
Published: October 2011

Abstract
The Peregrino field is located in Campos Basin approximately 85 km offshore from Cabo Frio in Brazil. The oil in Peregrino is heavy with a gravity of 14° API. First phase of field development will be accomplished by two drilling capable wellhead platforms tied back to a central FPSO. A Total of 30 producer and 7 water injector wells are planned for this phase.
One of the most critical factors in offshore operations is physical space. Flow allocation devices like test separators can be bulky due to the large capacities required to operate with heavy oil. These and the gear required for their control and efficient operation like heaters can be among the most space consuming equipment onboard. Multiphase flow meters are also available for flow allocation purposes; however its accuracy is highly impacted by heavy oils. The slow gas flashing out of heavy oils affects the representativeness of necessary pressure-volume-temperature (PVT) characterization.
Downhole Venturi meters were other alternative considered when deciding about the flow allocation method for Peregrino. These were initially left behind basically due to two factors; the economical impact related with a single unit required per well and the limited data available regarding its uncertainty with viscous oil. The changing oil/water conditions in Peregrino can be a challenge from a viscosity modeling point of view. Therefore a decision was made in favor of the flow allocation based in Electric Submersible Pumps (ESPs) performance. This technique has been used with success in wells with very high water cuts but it's a novel approach in viscous oil.
Improving the accuracy of this approach required multiple tests with the submersible pump models selected for Peregrino field. The tests were performed in a high viscosity flow loop in Claremore and covered a wide range of viscosities and speeds. This paper outlines the test results and presents the principles of flow allocation in Peregrino.

Introduction
Statoil is currently developing the Peregrino field in offshore Brazil (see Figure 1). The Peregrino project is the company's largest internationally operated field and biggest project outside of Norway to date. This is a large scale project with an estimated 2.5 billion barrels of oil. First Oil production started in March 2011. The field is located in Campos Basin approximately 85 km offshore from Cabo Frio in Brazil at 100 m water depth. It consists of two wellhead platforms tied back to a central FPSO (see Figure 2). Thirty horizontal oil producing wells are planned to be drilled from the platforms during the first development phase.