bluuebunny/crossref_metadata_2025 huggingface dataset:
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'Oliveira Diogo Scarcelli , da silva Wesley
Published: October 2011

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

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

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

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

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

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.

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

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.
Workover/Well Intervention and Regulatory Challenges
Authors: Solli Tomas Elander
Published: October 2011

Historically classification of ships was introduced for the maritime industry. This was back in the 18th. Century when all ships had very similar tasks. The diversity today is something completely different and workover units are one of the latest add-ons to the wide variety of ships and offshore units. So how do the shelf states, flag states and classification societies address this situation?

The term workover is used to refer to any kind of oil well intervention involving invasive techniques, such as wireline, coiled tubing or snubbing. What are the accident scenarios following workover/well intervention? Many shelf state authorities consider any unit that connects to a live hydrocarbon well to be an offshore unit. Are the vessels involved in workover suited for the task? The current situation is very complex due to the fact that the different types of workover techniques and operations have a very different risk profile. Today there are very few international requirements associated with the vessels or equipment used during well intervention. With the Macondo disaster fresh in mind it is also prudent to ask if the systems and safeguards in use during well intervention and workover are sufficient. Also in this growing industry new operators are rapidly entering into this market; with or without relevant experience. Practically any offshore supply vessel can swiftly be converted into a well intervention unit without any assessment or approval of the modification of the vessel.

At the same time the number of subsea wells used in the offshore industry is rapidly increasing. Any subsea well in any deepwater development will need well intervention sooner or later to varying extent. And the vessels used can undertake heavy or light well intervention with minor modifications to the vessels.

To a big extent the well intervention industry is self regulating. In this paper DNV will present their view on the regulatory challenges in this booming industry and the risks involved in these activities.

Introduction

Before discussing the subject of this paper further I will need to clarify the subject. What is workover? And what is Well Intervention? There are different understandings amongst different parties in the oil industry what these terms really mean. There is no reason to argue whether one view is more correct than the other, but for the sake of this paper it is important to clarify what is being addressed In the Schlumberger Oilfield glossary Well Workover and Intervention is defined as follows:

" The process of performing major maintenance or remedial treatments on an oil or gas well. In many cases, workover implies the removal and replacement of the production tubing string after the well has been killed and a workover rig has been placed on location. Through-tubing workover operations, using coiled tubing, snubbing or slickline equipment, are routinely conducted to complete treatments or well service activities that avoid a full workover where the tubing is removed. This operation saves considerable time and expense.??
Unique Salt Drilling Steerability Test: Advanced RSS Proved Outstanding Build-up Rate Capability in Brazil Mobile Salt Formations
Authors: Thomson Ian James , Krasuk Raul M. , Freesz Marcos Paulo
Published: October 2011

Salt drilling in offshore projects has become more frequent over the last 10 years in many parts of the world. In Brazil, important oil discoveries were made in carbonates reservoirs that lay below thick salt bodies. Drilling through salt can be challenging, especially where severe salt mobility is common. Salt mobility or creep rate is mainly a function of downhole temperature, geomechanical stresses around the salt body and salt mineralogy.

Today, many deepwater wells targeting hydrocarbons below the salt in Brazil are still considered exploratory or appraisal, and are drilled vertically through salt, with only a few projects in the development phase. Due to the gradual transition of deepwater projects into the development phase, the requirement for directional drilling through salt is rapidly increasing.

To achieve a better understanding of the salt drillability, in terms of steerability capabilities and directional assembly stability, a pioneer directional drilling test was conducted in a mobile onshore Brazil salt formation, using an advanced rotary steerable system (RSS) and a specialized downhole drilling optimization measurement-while-drilling (MWD) tool. This paper will show, in detail, the results and lessons learned from this unique salt drilling steerability test, along with the result of deepwater sections drilled directionally through salt formations offshore Brazil.

Introduction

Directional drilling through salt has been perceived by the drilling community to be a challenge due to the plastic nature of the evaporates and due to wellbore stability problems commonly experienced in the past. The ability to consistently perform directionally in salt and achieve the planned buildup rates (BURs) had been an issue in salt throughout the years. In general many aspects rule the BUR capability in salt: The evaporate rock being drilled, salt creep rate, and bottomhole assembly (BHA) and bit design, among others. The directional drilling technologies evolution over the last years, along with the experience gathered in salt drilling worldwide, had given more confidence for operators and service companies to venture in directionally drilling through salt intervals.
LNG Tandem Offloading - A Qualified Technology Now Ready for FLNG Project
Authors: Lavagna Damien , Le Touze Laurent , Fournier Jean Robert
Published: October 2011

LNG offloading operations are critical for the FLNG deployment on fields subject to medium or harsh environmental conditions. In the oil industry, tandem offloading operations are routinely performed using flexible marine hoses in various project specific configurations. The challenge of offshore LNG transfer lies in the combination of constraints from both the cryogenic operational requirements and the aggressive marine environment.

From 2006 onwards SBM Offshore has developed an EN1474-2 compliant flexible cryogenic marine hose for offshore transfer of LNG. In 2010, the hose design and fabrication received a Type Approval certification from both ABS and DNV. SBM then completed the qualification of both the cryogenic coupling and the LNG tandem transfer system.

The LNG transfer system is located on the stern of the FLNG and is connected to a dedicated bow manifold on the LNG carrier. The line configuration is suitable to handle the boil-off gas and transfers the vapour back to the FLNG boil-off gas management system. For the safety of operations and to increase the operability weather window, this system is designed to be operated without support vessels or tugboats. The line deployment and retrieval operations are carried out in a similar fashion to oil transfer systems and benefit from years of field expertise.

This paper describes the system and outlines the main operating procedures. It summarizes the qualification roadmap including concept review, design assessment and associated testing program. It also presents the design analyses that were carried out, concludes on the generic system performances and operations limitations, and highlights key integration issues.
Considerations for the Use of Carbon Dioxide Removal Membranes in an Offshore Environment
Authors: Tierling Shane , Jindal Sanjeev , Abascal Ricardo
Published: October 2011

Interest has been piqued in the use of membranes for the removal of bulk carbon dioxide from natural gas in an offshore environment because of the advantages that membranes present in weight, space efficiency and tolerance of motion. A number of practical considerations have to be considered when using membranes for CO2 removal offshore and these will be discussed in the context of recent KBR work.

Membranes have strengths and weaknesses compared to other carbon dioxide removal technologies in an offshore environment. These strengths and weakness lead to specific concerns and opportunities that should be addressed in the design stage and can have impacts on the full life cycle of the offshore facility if not fully addressed. We will discuss how to approach these issues to lead to successful construction, operation and maintenance of the carbon dioxide removal membrane system in an offshore environment.

Introduction

Gas is becoming an increasingly important part of the global energy equation constituting 18.5% of the energy mix in 1977 which further increased to 23.5% of the mix in 2005 per Wood (2007) [Fig. 1].
A Case Study: A High Throughput Mud-Gas Separator for Underbalanced Drilling
Authors: LeBlanc Chris Mark , Amorim Marco , Piacentini Roberto
Published: October 2011

Underbalanced drilling (UBD) is a drilling technique in which hydrodynamic pressure, exerted by the drilling mud and circulating fluids in the well bore, is below the pressure of the well formation. In UBD applications the surface pressure is lower than the well pressure, resulting in the flow of hydrocarbons to the surface at a controlled rate. This drilling technique requires specialized surface equipment for continuous separation of the drilling mud and hydrocarbon components for recirculation, sampling, storage, flaring, and disposal. Underbalanced Drilling technology provides significant technical and economical value and reduces damage to the well formation. This paper highlights how custom-off-the-shelf technology provided a cost-effective solution where Petrobras was able to reduce the time required to reach full production and eliminate or reduce, the fracturing required after a well is completed.
Global Offshore Operations Performance: Assessing Uptime Reliability
Authors: Kilchrist Joseph , Alba Juan Carlos
Published: October 2011

During the past dozen years, Ziff Energy has studied the Operating Costs and Uptime Reliability of Offshore Operations in the North Sea, Gulf of Mexico, West Africa, Asia Pacific and South America (i.e. Brazil). In all, Ziff Energy has detailed operations data for more than 900 offshore assets in 20 countries. These include Shelf and Deepwater assets, including older platforms, high productivity ‘LNG Feed' offshore gas fields, and all types of production systems (from fixed structures to subsea wells, spars, TLP's and FPSO's). Ziff Energy Group's Operating Efficiency/Reliability methodology provides a unique opportunity for offshore operators to compare their operations performance with other operators' similar operations. This presentation will include an overview of the metrics calculated and the lessons learned in measuring the uptime reliability performance of offshore operations, drawing on examples from our extensive experience. We will compare Offshore operations from around the world (e.g. by production system).

Application

The presentation will highlight uptime/production reliability performance issues associated with production losses in offshore operations. The presentation will present a sample of case studies (key findings) and will outline the role of performance assessment in guiding the continuous improvement of operations efficiency and reliability.

Results, Observations, and Conclusions

The presentation will provide production efficiency assessments from Ziff Energy's Offshore studies of oil and gas operations. Challenges in completing an assessment of Offshore Production Efficiency will be addressed, including differences between operators in their definitions of planned and unplanned losses. The presentation will include a look at the benefits of peer assessment of Offshore Operations.

Significance of Subject Matter

The presentation provides new performance management tools (metrics) by production systems:Uptime ReliabilityKey Performance Indicators - Metrics

These tools are useful for managing the operations performance of offshore fields, which help operations management extend the economic life of their fields.
Tools and Techniques for the Selection and Design of Safe Deepwater Riser Systems for Mobile Offshore Drilling Units
Authors: Whooley Alan , Deegan Jonathan , Goldsmith Riley G. , Botto Adriana
Published: October 2011

The deepwater drilling industry has been rocked by the tragic Deepwater Horizon event in the Gulf of Mexico. The incident identified a number of possible failings by operator, service contractors and the regulator which combined to lead to the ultimate results which were evident in mid 2010. This paper will assess the options available to the deepwater drilling industry in assessing the risk of various riser and BOP configurations for drilling and completing deepwater wells in moderate metocean environments. The paper will address two different systems:A classic subsea BOP stack configuration,A surface BOP stack with a subsea isolation device (SID).

Both of these configurations have merits depending upon a number of factors which include rig availability and schedule, project economics, riser integrity, BOP configuration, geological issues and, most importantly, the hazard and risks associated with each concept.

This paper will identify the various technical analyses and risk analysis techniques that must be undertaken to assure the operator of the system is comfortable with each system. These include riser analysis, rig mooring and station keeping analyses, system HAZIDs and HAZOPs, and more.

The idea of the paper is to provide the operator and drilling contractor with a ‘road map’ which will allow them to navigate their way through the various issues to be addressed. This road map will start with the concept stage (rig contracting early well planning) where issues such as project economics, rig availability and risk tolerance will provide input into the overall decision making process. The paper will next address the preliminary and detailed design stages where issues surrounding metocean criteria, rig characteristics and rig configuration and geological conditions will play a part in the overall input. The paper will describe how a project team would approach the issues. Finally as the project moves to the implementation stage the paper will describe the techniques for final assurance that the concept can be managed in the implementation stage.
Capturing the True Non-Linear Load-Elongation Properties (Including Permanent Elongation) of Polyester Rope in Mooring Analyses
Authors: Pasternak Jason , Garrity Robert , Leite Sergio
Published: October 2011

Polyester is the most widely used synthetic fiber in modern mooring systems. Though its use is widespread, very simplistic models of its nonlinear load-elongation behaviors are typically utilized in mooring analyses for predicting maximum line tensions and facility offsets. This oversimplified approach can lead to under/over conservative results affecting both mooring system and riser design. A more accurate approach is to separate the permanent elongation of the rope from its non-linear rope stiffness properties. Handling these variables (stiffness and permanent elongation) independently is key in accurately representing the mooring system's response. Different mooring scenarios (e.g. MODUs, FPSOs, SPARs) are affected in different ways by the use of an oversimplified load-elongation model of polyester behavior. This study will address these affects for both a Semi-submersible and an FPSO under metocean conditions typical of the Brazilian basins.

Through a detailed rope testing plan, rope non-linearities and length effects as a function of mean load and frequency of loading oscillations can be fully captured for use in mooring analyses, better predicting actual mooring system responses. One such rope testing plan will be discussed and shown how the data is analyzed and prepared for use in the mooring analysis.

By modeling the true non-linear stiffness and being able to capture the permanent non-recoverable elongation of fiber mooring ropes in a mooring analysis, the designer can more accurately assess the vessel motions during a storm event and more effectively plan component lengths such that re-tensioning operations will not significantly impact the facility's ability to operate. Such accurate vessel motions and offsets from this analysis method also aid greatly in the riser and other system designs that are integral parts of permanently moored facilities.

Hydrodynamic Model Overview

For the semi-submersible examined in this case study, a generic Mobile Offshore Drilling Unit (MODU) model was created with symmetry along each horizontal axis. This symmetry, in conjunction with an assumed flat seafloor, allowed for metocean conditions to be applied only on one quadrant of the model to determine the controlling environment direction. The chosen base model was a modified Aker H-3 Series semi-submersible. The approximate vessel dimensions are ~74m×63m with a operating draft displacement of ~28,000 mt. The following figure shows the hydrodynamic model of the semi-submersible that was created in AQWA and used to generate the RAOs and wave drift forces.
Dynamic Positioning Capability and Enhanced Reliability
Authors: Reilly George T. , Hensley Michael
Published: October 2011

The dynamic positioning (DP) classification notations (DPS-1 to DPS-3) reflect the equivalent International Maritime Organization (IMO) equipment classes which represent increasing levels of redundancy. The criteria given and the use of Failure Modes and Effects Analyses (FMEA) have formed the industry's basis for evaluating DP. However, other important measures, such as position keeping capability and reliability of the designs, are not reflected in these current notations.

This paper investigates the use of another well established risk tool - the fault tree which allows for the interaction of various components and their failures to be mapped from the vessel's design. The technique provides for the use of the tree design and failure data to be combined so as to give numerical values to the probabilities of (time between) failures of system components.

The values that come from the fault tree approach can then be used in the development of an Enhanced Reliability (ER) notation (e.g. DPS-2, ER-60, 40kn - indicating 60 days between failures that result in loss of redundancy in a 40 knot ‘environment’). This enhancement to DP criteria is expected to be the most significant since the IMO Guidance was originally published.

Application

The progression of offshore operations into deeper waters was inevitably accompanied by the increased adoption of DP systems as traditional mooring systems became less viable for small units or for short periods of operation.

Entities interested in using vessels with DP capabilities need a mechanism for comparing different units against their specific operational requirements. In addition, DP system vessel owners want their assets to be easily identified for the capabilities (and investments) they have to offer.

Results, Observations, and Conclusions

Procedures on the development and the requirements of the Enhanced Reliability for DP systems will be presented.

Significance of Subject Matter

Compliance with the Enhanced Reliability requirements would provide a means for owners and operators to have a consistent and quantitative measure of the capability relative to the reliability of the DP system.
Correlation of the Petroleum System from Santos and Namibian Offshore Basins
Authors: Mello Marcio Rocha , Bender Andre A. , Filho Nilo Chagas Azambuja , Barbanti Silvana , Franke Milton R. , Jesus C.L.C.
Published: October 2011

The sedimentary basins of the South Atlantic have developed into one of the most active regions for petroleum exploration in the whole world. The increase of interest in the oil industry has resulted from the numerous recent giant to supergiant oil and gas discoveries along both the eastern and western continental margins of the South Atlantic in deep and ultradeep waters. The use of the petroleum system concept in the South Atlantic marginal basins provides an effective means of classifying and characterizing the diversity of the oil and gas systems, as well as, a means to aid in the selection of appropriate exploration analogs. The South Atlantic marginal basins also provide some of the best examples of how petroleum systems evolved through time with respect to both their levels of certainty and their areal and stratigraphic limits. An examination of the Orange and Santos basins, in Namibia and Brazil, respectively, provides examples of almost perfect analogs in terms of petroleum system. For example, lacustrine and marine source rocks, similar oil type, almost identical reservoir deposition environments, traps associated with basement highs and vertical migration pathways dominate in each of the basins, with normal faults networks providing the effective carrier. However, there are clear differences when Aptian salt layers are present in the Santos basin and absent in the Namibian basins. Also, differences are observed when thermal evolution is considered. Although no Aptian salt section is present in Namibian basins, and thermal maturity appears to be much higher in the Namibian coast, both basins share almost identical elements and processes of the petroleum system concept. In summary, the aim of this paper is to show how the petroleum system modeling, supported by geochemistry, allows a correlation between counterpart basins across the South Atlantic realm.

DISCUSSION

The evolution of the South Atlantic sedimentary basins provided the general conditions for the establishment of various petroleum systems. The formation of source rocks, reservoirs and traps are directly related and connected to the phases of the evolution of the passive continental margins (Figure 1): pre-rift, syn-rift, transitional and thermal sag (drift) sequences (Mello, 1988, Mello et al, 1991 and Katz and Mello, 2000).
Pre-Stack Full Waveform Inversion for Velocity Model Building
Authors: Kapoor S. Jerry , Vigh Denes , Bunting Timothy John
Published: October 2011

An accurate earth model is key to any successful depth imaging effort. Full waveform inversion is an advanced velocity model building process which uses the full two way wave equation. Existing methods use a ray tracing approach to distribute velocity errors within the model. In this presentation, we will show examples of seismic data processed with the latest technology, including earth model building with full waveform inversion.

Introduction

The industry has moved to using two-way wave equation migrations(commonly known as reverse time migration), especially in areas of complex geology such as the salt bodies in the Gulf of Mexico and offshore Brazil. The velocity model, including velocity anisotropy, is key to any depth migration effort. The natural next step is to use the two-way wave equation for velocity model building. One of the most advanced tools for velocity model building using the two-way wave equation is Full Waveform Inversion(FWI). Full-waveform inversion uses computer intensive forward modeling of the seismic measurement combined with residual wavefield back propagation to iterate to a final velocity model, which can provide greater detail than tomographic ray tracing approaches. Velocity inversion using full waveform inversion has been used on a number of projects around the world including the GOM, Brazil and the North Sea.
Seismic Ocean Botttom Nodes: A Versatile Field Development Tool
Authors: Ronen Shuki , LeCerf Didier , Rokkan Arne , De Sousa Joao Tadeu Vidal , Gelot Jean-louis
Published: October 2011

In deepwater such as Santos basin pre-salt environment enhanced imaging can be achieved using wide azimuth acquisition geometry (WAZ). There are two options available for seismic imaging: towed streamers and seabed receivers. During field development, surveys usually have a limited size (<300km2). WATS (wide azimuth towed streamers) have operational restrictions due to surface obstructions such as FPSOs, offloading buoys and drilling rigs. Undershooting with multiple vessels is a solution with significant data quality limitation, especially in the context of seismic monitoring (4D). Ocean Bottom Cables (OBC) also have operational issues due to water depth and due to seabed obstructions such as pipelines, and anchor chains. Ocean Bottom Nodes (OBN) provide excellent Full-Azimuth (FAZ) Multi-component (4C) seismic data. OBN can be safely used in areas with both surface and seabed obstructions. Deployed by Remotely Operated Vehicle (ROVs) the nodes provide high repeatability for 4D seismic monitoring. Some OBNs can be mobilized on a vessel of opportunity and can be deployed by a dynamically positioned vessel already working in the field, thus increasing the safety and reducing the cost of the node survey. The technology is ready for commercial applications and spectacular results have been already achieved. The industry is now developing specific business models and operational models for combining nodes with surface towed streamers and with permanent reservoir monitoring OBC.

Ocean Bottom Nodes are emerging as a new acquisition method

Unlike surface towed streamers and Ocean Bottom Cables (OBC) the Ocean Bottom Nodes (OBN) are autonomous recording systems (Fig 1) and Remotely Operated Vehicles (ROV) (Fig 2) can deploy them safely on the seabed. Each node has seismic sensors, an analog to digital convertor, a clock, memory and battery, they are able to provide continuous records for weeks and month. They also record their tilt, voltage, temperature, and humidity. Because each node has its own clock and keeps its time, Clock drift and synchronization should be handled carefully and may causes delays in data processing but has never caused loss of data. The seismic sensors are a hydrophone and three geophones for four components (4C). The seismic sensors record both primary P waves and secondary Shear waves. The combination of the hydrophones and the geophones enables separation of the P waves to up-going and down-going wavefields. This separation is important for imaging with both primaries and multiples.

Ocean bottom nodes are not a new idea. Oceanographers have used them for decades, but recent computing- battery- and ROV- technologies are making them more and more practical and affordable. In addition to the technology push, there is an increasing market pull for nodes for exploration of hard to find oil and for reservoir development and production monitoring.
Ixodid ticks, fleas and lice infesting dogs and cats in Hawassa, southern Ethiopia
Authors: Kumsa Bersissa E. , Mekonnen Shewit
Published: October 2011

This study investigated the prevalence, risk factors and species composition of ticks, fleas and lice infesting dogs and cats in and around Hawassa in southern Ethiopia. In total, 200 dogs and 100 cats were examined from November 2008 to April 2009. Of the dogs and cats examined, 99.5% and 91.5%, respectively, were infested with one or more species of ticks, fleas or lice. The overall prevalence was higher in dogs than in cats. A total of six different species of ectoparasites were collected and identified from dogs, but only three species from cats. Ctenocephalides felis was the predominant species amongst the animals, with a prevalence of 82.9% on dogs and 67% on cats. Other prevalent species on dogs included Ctenocephalides canis (73.8%), Heterodoxus spiniger (4%), nymphs of Amblyomma spp. (3.5%), Pulex irritans (2.5%) and Haemaphysalis leachi (0.5%). C. canis (18%) and P. irritans (6%) were also found on cats. More female than male fleas and lice were observed. The study revealed that the prevalence of fleas, ticks and lice on dogs was not significantly different between male and female animals or between young and adult dogs. However, the prevalence of these ectoparasites was significantly higher in female than in male and in adult than in young cats. The study showed that the prevalence of ectoparasites on both dogs and cats was significantly higher on animals with flea allergy dermatitis (FAD) than those without FAD, and on animals with lesions on their skin compared with those without lesions.