bluuebunny/crossref_metadata_2025 huggingface dataset:
Field Decommissioning Obligations in Brazil: The Differences and Impacts of Current Methodologies for Concessions and Sharing Regimes in Light of Investment Attraction
Authors: Gaspar Fabio , Bilda Katiana
Published: October 2017

This paper aims at exploring the different fiscal effects of field decommissioning in the Brazilian regulatory archetype and unveils the comparative law angle and resulting effect in country competitiveness and attractiveness.

Concessions and Sharing regimes (PSC) come with the inherent obligation of infrastructure decommissioning at the end of the contract. To meet such obligations, concessionaires and contractors plan the ways and costs to do so and the Regulator (ANP) approves such plan. The mechanics of how those plans are undertaken are, however, different in each of the mentioned regimes and will result in different tax impacts. These methodologies and its inherent effects will play an important role with regards to how attractive the country is for Upstream investment.

On Concessions, due to accounting rules, a provision is to be made in relation to these estimated costs. Because there are no legal grounds for deducting such a provision for corporate income tax (CIT) purposes, the deduction can only be taken at the effective cash disbursement moment, usually at the end of the field life.

The PSC law and contract provide for a decommissioning fund to be formed by the Contractor in installments. Once cash is put into the fund, the Contractor cannot take it back; even if the actual expenditure later proves to be lower, case in which the remaining funds will be reverted to the Federal Union. In the PSC, rather than a provision a definitive expense (cash into the fund) is made by the Contractor. Therefore, the definitive cash put into the fund is more inclined to generate a tax deduction.

The IMF (International Monetary Fund) has published a paper in 2012, Fiscal Regimes for Extractive Industries: Design and Implementation, where it suggests special fiscal rules for decomissioning tax deductions. Not only special rules will cause projects and countries to be more competitive and attractive, but also society may gain from its positive effects, which range from more jobs and higher income to responsible environment practices. Brazil could benefit from more competitive rules, especially after many other jurisdictions have prepared more welcoming regimes for the current low oil price world.
Short Term Production Optimization Using a Model of the Peregrino Field, Brazil
Authors: Kristoffersen Øystein , Stanko Milan , Hoffmann Arnaud
Published: October 2017

Peregrino is a field offshore Brazil with a FPSO and 2 fixed platforms currently producing close to 100 000 stb/d of oil. Production wells are equipped with electric submersible pumps (ESP) and all produced water is reinjected back into the reservoir using 6 injectors for pressure support. The viscosity of the crude is high (163 cp at reservoir conditions). The present work explores the merits and provides the development details of a model-based production optimization scheme to advice on the best frequency settings of the ESPs in each well. This to ensure the maximum amount possible of oil is produced when water injection capacity is a bottleneck. Furthermore, it studies how the optimal operating conditions change with time.

The optimization formulation considers maximization of total oil production, the maximum allowable water produced given by the available injection capacity and the operational constraints of the ESPs. The optimization was formulated as a Mixed-Integer Linear Problem (MILP). The performance of the wells is represented with piecewise linear tables generated from a commercial simulator.

For the cases tested, the proposed optimization scheme works successfully: It has low running times suitable for real time production optimization, handles successfully multiple operational constraints, and guarantees global optimality. Optimization results are presented for future times.

By using piecewise linear tables to represent the well performances the fidelity of the original model is maintained, while ensuring a robust and fast optimization of the problem. Moreover, it is suitable for frequent model updates without requiring changing the optimization formulation. In summary, this work proposes a method to handle part of the operational complexities of the Peregrino field using a digital twin.
Multi-Scale Ensemble-Based Data Assimilation for Reservoir Characterization and Production Forecast: Application to a Real Field
Authors: de Lima Alexandre , Gentilhomme Theophile , Riffault David , Allo Fabien , Anyzewski Alessandra S. , Emerick Alexandre A. , dos Santos Marcos S.
Published: October 2017

The paper presents the application of multi-scale Levenberg-Marquardt ensemblerandomized maximum likelihood(MS-LM-EnRML) method to an offshore field in Campos Basis. The objective of this method is to update an ensemble of spatial properties and flow parameters using observed productiondata while preserving the prior information already carried by the prior models. The final ensemble provides an estimate of the uncertainties and can then be used for productionforecast andinfill drilling projects. Instead of working directly with the gridblock values of the reservoir, the MS-LM-EnRML method performs a wavelet transform of the spatial properties. Based on this parameterization, a multi-scale approach is followed: different subsets of wavelet coefficients are successively updated with the data using the Levenberg-Marquardt ensemble-based data assimilationmethod. Thanks to the compression property of the wavelets, the field properties are well characterized with a small number of wavelet coefficients. The algorithm starts by optimizing an initial sub-set of large-scale coefficients. The parameterization is then progressively refined, and a new optimization is run on the new subset of coefficients. Because the data mismatch is highly reduced by the initial optimizations at large scales, the perturbation of the fine scale coefficients is minimized resulting in a better preservation of the prior models and a reduced level of noise in the final models.

For comparisons, a second history matching was conducted using the ensemble smoother with multiple data assimilation (ES-MDA) method without the multi-scale parameterization. The quality of the data match, the preservation of the prior models and the ensemble variance are used to compare the two methods. The results showed that although a better data matcheswereobtained with ES-MDA, MS-LM-EnRML preserved better the prior models, the geological consistency and the variability of the ensemble. These results indicate that the multi-scale approach is an attractive option especially when a large number of data has to be assimilated (e.g., long production history and 4D seismic data) or when geological features and seismic information of the initial models need to be preserved.
Development and Evaluation of Ocean Bottom Hybrid Joint Box System for Real-Time Communication and Monitoring in Deep Seabed
Authors: Kimura T. , Araki E. , Yokobiki T. , Kawaguchi K. , Fujiwara N. , Hishiki K. , Yonezaki Y.
Published: October 2017

We have been developing ocean bottom hybrid joint box system for real-time communication and monitoring in deep seabed. The joint box can provide high voltage power and large data transmission used in seabed as a part of seafloor cable network system. We installed first generation joint boxes in the Nankai Trough area, Japan as a part of DONET (Dense Oceanfloor Network System for Earthquake and Tsunamis)project. 12 joint boxes have been deployed in seabed with depth of up to 4000 m from 2010 to 2016. Backbone submarine cables, which provide main power and communication lines from land station to seabed joint boxes, have been deployed before the installation of the joint boxes. Each port of joint box can supply 45 Watts/port and transmit 50 Mbps data for geophysical instruments including broadband seismometer, pressure gauge (tsunami meter), thermometer, etc. 53 seafloor observation systems were connected to the joint boxes for real-time monitoring in the wide area, approximately 200 × 250 km. Observed long-term data confirmed that the joint box has high stability and reliability. There are almost no missing data except for during maintenance. We also applied a data processing method, seismic interferometry method, to long-term seismic data observed by broad-band seismometer. This method can estimate time variation of velocity structure below each seismometer by calculating auto- and cross-correlation. Obtained results confirmed that small change of seismic velocity, which would be generated by earthquake events, is detectable. Since 2014, we have developed modified joint box, which can provide high power and large data transmission, 250 Watts/port and Giga bps rate, respectively. The new joint box can transmit high density information, for example, real-time video image, and operate large seismic observation system with several hundred channels.
Assessment of Cold Water Injection Geomechanical Effects on Brazilian Pre-Salt Reservoirs and on Its Saline Caprocks
Authors: Amaral Ricardo Fernandes do , Seabra Gabriel Serrao , Laquini Joao Paulo
Published: October 2017

Cold water injection creates a cooled rock region around the well that can reduce the horizontal stresses acting on the reservoir and, also, the injection pressure to initiate and propagate a fracture. However, the impact of thermal stresses in saline caprocks, where creeping occurs, is not well understood yet. This study aims at modeling the cooled region created by cold water injection and evaluate the thermally induced stresses in both reservoir and saline caprock.

In order to assess the evolution of the pressure and temperature in the reservoir and in the caprock during 16 years of cold water injection, reservoir simulations considering thermal effects were carried out. Various simulations were performed using different water injection rates and different thermal diffusivities for the reservoir and for the caprock. The model used in these thermal simulations comprehended not only the pre-salt carbonate reservoir, but also the salt rocks. Stress and strain were evaluated using a 3D finite element in a one-way coupling scheme, including the reservoir, overburden (salt and post-salt), sideburden and underburden.

In the worst simulated case, after 16 years of cold water injection, the height of the cooled region in the salt was about 200 m above the top of the reservoir. As expected, horizontal stresses in the reservoir significantly decreased with cooling. On the other hand, horizontal stresses in the saline caprock did not change significantly, even though the thermal expansion coefficient of salt rocks is five times greater than that of carbonates. This result suggests that creeping in the salt relieves thermal stress induced by cooling. Thus, saline caprock integrity is not influenced by cold fluid injection in the reservoir, as long as salt creeping can be considered.

Although cold fluid injection may cool the salt, stress state in the caprock remains unaltered. Thermal stress is relieved by the salt creeping at the expense of plastic deformations. Thus, the saline caprock integrity is not impacted by cold fluid injection.
Design One-Build Many: The Execution Strategy Leading to the Successful Delivery of FPSOs Cidade de Maricá and Cidade de Saquarema, Twin Production Systems Copied from Previously Delivered FPSO Cidade de Ilhabela
Authors: Pinto Guilherme , Torres Rafael , Ribas Paulo
Published: October 2017

Due to diverse oil field characteristics, Carbon-Copy type of projects are rarely used in developing Floating Production Systems (FPS). Known as "Clones" or "Replicas," such projects are starting to become more common in the industry. This paper will demonstrate key success factors of the Carbon-Copy approach in the design and construction of complex FPSOs such as Cidade de Maricá and Cidade de Saquarema based in the original Cidade de Ilhabela. While the economy of scale present cost reduction opportunities, continuous improvement processes applied to the execution strategy may provide additional gains not only in costs but also schedule and quality.

When conditions allow for Carbon-Copy application, it is critical to minimize changes from the original design. Hence, it is essential to implement a global strategy covering different project aspects (engineering/procurement/construction) and phases (FEED/Execution/Installation). The strategy should identify situational scenarios that may represent project gains if different execution approaches and tools are implemented providing solutions to the previous bottlenecks and constraints associated to productivity.

The continuously increasing technical, commercial and regulatory challenges imposed by a more demanding deep water market require Operators and Contractors tight collaboration to renew and improve their processes and execution methods. The advantages and cost savings in reusing proven solutions and designs from one project to the next are intuitive to conceptualize, understand and visualize, but the implementation can be subject to unexpected complexities.

This paper will present, based on the delivery of FPSOs Cidade de Maricá and Saquarema, both carbon copied from previously delivered FPSO Cidade de Ilhabela, some of the key parameters such as suitable project organization, solid lessons-learned process and sound execution strategy focused on anticipated delivery, which enable the right conditions for successful FPS Carbon-Copy projects execution.
Nonlinear Model Predictive Controller Applied to an Offshore Oil and Gas Production Facility
Authors: Neto S. Simoes , Secchi A. R.
Published: October 2017

In this work a nonlinear model predictive controller (NMPC) applied to an offshore petroleum production facility is presented. The facility was simulated using Hysys dynamic simulation, and the used NMPC controller with phenomenological mathematical model was the BRNMPC. Some comparisons were conducted regarding the use of NMPC, linear MPC and traditional PID controllers. The results showed that for level control of the separator vessels, the MPC and NMPC have similar performance, but for pressure vessel control, the NMPC are superior because the system has more nonlinearities and many information were lost in the linearization process.
Near-Miscible Flooding by Production Gas Re-Injection in QHD 29-2 Offshore Oilfield
Authors: Chen Hao , Zhang Xiansong , Yang Jiankun , Tang He , Mei Yuan , Li Bowen , Shen Xiong
Published: October 2017

QHD 29-2 block is a newly discovered offshore oilfield of China with an average water depth of 27.6m, covering approximately 2300 km2. Waterflood is not suitable due to the characteristics of complex lithology, strong heterogeneity, small pores and throats, and low water injectivity. In addition, a wide range of CO2 content (24-90%) in the production gas that presents a difficulty for the mixed gas handling. Thus, near-miscible flooding of the production gas re-injection is proposed for the development of this reservoir. It is concluded that the loss of displacement efficiency can be compensated by the mobility improvement with the pressure decrease. Thus, oil recovery is comparative with that of miscible flooding. Also, the economic and operational costs declined to some extent because smaller gas volumes and lower compression are needed with the reduction of pressure.

Slim tube test, slim tube simulation, and selected empirical formulas are used together to determine the near-miscible pressure interval under the condition of different CO2 contents (40%, 55%, 70%, 85%, 100%). On this basis, a new empirical formula was established to determine the lower and upper boundaries of near-miscible flooding.

Two new points are determined as minimum near-miscible pressure (MNMP) and minimum miscible pressure (MMP), respectively. A higher MMP can be expected by this process which is consistent with the argument that some successful application of CO2 miscible flooding are actually partial miscible flooding or near-miscible flooding. Results showed that the ratio of MNMP to the newly defined MMP is about 0.8 to 0.86. In addition, for the wells QHD 29-2E-4 and QHD 29-2E-5, the lower limit of the CO2 content in the production gas to achieve near-miscible flooding are 34% and 64%, respectively. Moreover, the relative error of the new empirical correlation is less than 10% for the prediction of the pressure interval of near-miscible flooding in the targeted wells.

To the best of our knowledge, this is the first time to study the potential of implementing near-miscible flooding by the production gas re-injection with varying CO2 content in an offshore reservoir of China. The results in the paper can provide a new screening criteria for both enhancing oil recovery and reducing greenhouse gas emissions for similar offshore reservoirs.
Integrated Production Management Solution for Maximized Flow Assurance and Reservoir Recovery
Authors: Bouamra Reda , Vielliard Christophe , Spilling Knut Erik , Nilsen Finn Patrick
Published: October 2017

Over the last decade, a number of subsea solutions have been deployed to unlock the commerciality of deepwater fields and increase the overall recovery factor of the reservoirs. Numerous types of monitoring and measurement technologies have been developed and installed downhole, subsea, and topside, but usually in a fragmented manner. The traditional field surveillance approach often addresses the reservoir challenges separately from issues that may affect flow in the production network or from processing facilities considerations. The value of information obtained using sensing equipment is then not fully taken advantage of, and critical information is lost due to the lack of integration. The objective of this work is to link all data collected along the fluid journey from the reservoir to the process facilties in order to optimize its production and better manage reservoir recovery.

In this work, a novel integrated production management solution (IPMS) is introduced. Dedicated subsea and subsurface metering devices, advanced flow control equipment, production surveillance systems, and production optimization tools are combined to increase the understanding of the reservoir and subsea production network, maximize the value of the subsea hardware and address operational challenges to enable increased predictive flow assurance capabilities and production optimization. Bridging the gap from abstract measurement values to production management decisions, such as inflow control actuation; allow a better reservoir management implementation along of the field life, leading to an increased recovery.

The functionality of the system is designed to address a number of challenges, including the following:reservoir management—recovery increase by combining continuous downhole sensing, seabed data, and IPMSEquipement centric monitoring and predictive maitenancethermal management—increase in system no-touch time and improved system preservationhydrate management—opex savings in regards to hydrate inhibitor injection and regenerationliquid management—avoiding unexpected shutdowns due to liquid surgespigging optimization—potential for reduced production losses during pigging operation and reduced pigging frequencylow temperature management—material integrity and hydrate preventioncorrosion and scale inhibition optimization—completion, subsea production system (SPS), and pipeline integrityerosion monitoring—SPSs and pipeline integrity.

For the first time, integrated production data are used in online pore-to-process integrated models to guide reservoir decisions, optimize opex, and enhance recovery. Specific examples such as detection of reservoir property changes and their impact on recovery, optimized inorganic scale, and hydrates management based on integrated downhole seabed and process data are discussed in detail.
Measured Data Provides Insight for Floating Systems Life Extension
Authors: McNeill Scot , Maniar Dilip , Renzi David , Del Vecchio Cesar
Published: October 2017

The primary goal of floating systems life extension efforts is to project how the system or components will behave in the future beyond the original design life. This predicted behavior can then be used to determine the practicality of the proposed life extension in terms of safety, environmental and economic risk. Often, these predictions are limited to reviewing inspection data (which has a limited ability to predict future response) or analysis (which is dependent on various assumptions). Measured data from in-situ monitoring systems provides accurate system response information which, in conjunction with mathematical modeling and inspection data, can be used to determine past and future behavior. The full potential of measured data for life extension activities has not been realized thus far.

Some uses of measured data in life extension efforts are illustrated through examples in this paper. The first example highlights ongoing fatigue assessment of a mooring line chain jack system using line tension measurements. The second example describes how uncertainty was greatly reduced in a polyester rope fatigue assessment by utilizing measured mooring line tension data. The third example demonstrates use of measured vortex induced motion response of a floating system to reduce the conservative assumptions provided during the design phase. The results of all of these examples show that measured data can provide insight into floating production system (FPS) response that cannot be attained otherwise, allowing for significantly reduced conservatism in life extension engineering assessments. Without the availability and use of this data it would be difficult to demonstrate the fitness for service of these facilities.

The examples of utilizing measured data to enhance life extension efforts provide concrete demonstrations as to how life extension of FPS components can be justified where uncertainty in analytical prediction is high. In such situations, demonstrating fitness for service beyond the design life would prove exceedingly difficult if measured data was not available. Continued service feasibility is most effectively demonstrated by augmenting inspection and analysis efforts with field monitoring data.
Experiences from Automated Hardware-In-The-Loop Testing of BOP Control Systems
Authors: Kårvand O. , Pivano L. , Stenbro R. , Ramos de Carvalho C. , Boff S. , Staudacher L.
Published: October 2017

A BOP relies on a sophisticated redundant control system to achieve desired reliability and safety. The BOP system software must work seamlessly integrating sensors, valves, and diagnostic feedback while being able to hot swap in a fully redundant environment. It is known that software errors may lead to nonproductive time, delays, compromise safety and potentially lead to an environmental disaster. Software failure risks can be mitigated by performing HIL testing which is a well-established test methodology in other industries such as automotive and aerospace, where high performing and robust control systems are essential, and has through the last decade been established also in the maritime and offshore industries. NOV Rig Systems and DNV GL Marine Cybernetics Advisory have together developed a test setup for HIL testing of BOP control systems by combining simulators from both parties.

Basic functionality of the BOP control system is tested through automatic scripts, allowing extensive testing and regression testing (to verify that software previously developed and tested still performs correctly after it has been changed during updates or retrofits based on customer requests). Often new functions are added or existing ones are modified and this could potentially lead to undesired errors. This paper demonstrates how this technology reduces the risk of adding software errors, by using a systematic and automatic testing approach.

This paper introduces HIL as a methodology for BOP control system software testing and shares the experiences from automated testing by using CyberSea Signature on the BOP Control System delivered by NOV Rig Systems.
Surface Plasmon Sensors for Fluid Analysis in Upstream Oil
Authors: Monteiro Othon R. , Suresh Radhika , Chandran Ashwin
Published: October 2017

Sensors are becoming increasingly ubiquitous in the oil and gas industry to enhance efficiency in exploration and production (E&P), as well as to improve safety and minimize the impact of these operations on the environment. In particular, knowledge of the properties of fluids contained in a hydrocarbon reservoir helps to identify the fluid type, estimate reserves, assess hydrocarbon value and optimize production. Although measurement of fluid properties can be done at the rig surface or downhole, the latter is preferred because subjecting these fluids to changes in pressure and temperature compared to the downhole environment may induce irreversible changes. Moreover, in many instances, it is important to monitor the chemical composition of a fluid in real time. Dissolved H2S in reservoir fluids has a harmful impact on cost and safety operations in drilling and production. We have investigated localized surface plasmon resonance (LSPR) methodologies and fabricated sensors for measuring dissolved sulfides in liquids. The impact of the specificity of sensing materials and the design concepts were investigated. The chemical composition and morphology of the nanoparticles affect the response of the sensor, and can be used to mitigate the strong absorption in heavy crudes. The effect of temperature on the sensor response was evaluated. Sensor response was not affected below 150o F. The effect of organo-sulfur compounds on sensor response was also investigated.
Designing Fluid Properties to Minimize Barite Sag and its Impact on Annular Pressure Build Up Mitigation in Producing Offshore Wells
Authors: Calcada Luis Americo , Scheid Claudia Miriam , da Cruz Meleiro Luiz Augusto , Oechsler Bruno Francisco , Fagundes Flávia Marques , Santos Nara Brandão Costa , de Oliveira Arouca Fábio , Damasceno João Jorge Ribeiro , Souza Elessandre , Waldmann Alex Tadeu , Martins Andre Leibsohn
Published: October 2017

After the cementing of an oil well, part of drilling fluid is confined in the annulus between the cement and an isolation tool (pack off). During the production phase of a well, the confined fluid will be exposed to a temperature gradient due to the circulation of reservoir fluid through the production screen. This increase in the temperature causes a pressure evolution that can damage isolation.

Among several possibilities for APB mitigation, the strategy of communicating the annulus with a formation is often considered. In this case, when pressure reaches formation fracture, fluid would be drained from the annulus and thus, the pressure would be released. However, several authors claim that, after a period, barite sag in the drilling fluid will create an impermeable layer, which will prevent communication of annulus with the formation; and APB mitigation strategy would fail. These wells are placed in operation a few years after completion is concluded.

This article presents an extensive experimental task aiming the understanding of the effect of rheology on barite sag for different fluid concepts. The experiments consisted of long time sedimentation tests (monitored by gamma ray techniques) and a rheological characterization of the fluids. Fluids tested include new and aged Synthetic based systems. The role of particle diameter in the permeability of the sedimented bed was also investigated. The experimental results provide valuable guidelines for designing fluids aiming APB mitigation.
Long Tiebacks for Life Extension of Existing Offshore Facilities - A Novel Solution for Flowline Wet Insulation
Authors: Rebello Armando , Alexander Lane
Published: October 2017

Blockage of flowlines due to hydrate or paraffin plugging is an on-going issue for the offshore industry. The problem seems to be exacerbated with the higher pressures and colder ambient temperatures as developments progress into deeper and deeper waters. There are many blockage prevention equipment and techniques available to the system designers, but in spite of this, blockages are still occurring.

This paper presents a novel approach for remediating hydrate or paraffin blockages of wet insulated flowlines with the application of heat directly to the steel OD of the pipe instead of the OD of the wet insulation, which is less efficient.

The herein proposed solution offers two possible configurations for the same base design, one for near-riser cooldown time extension, and one for "as-needed" intervention when hydrate or paraffin plug(s) have formed.

The proposed method establishes a new paradigm, since it utilizes an unbonded layer of external insulation with a gap between the insulation and the flowline steel OD. The gap will be used to circulate hot media, with heat being transferred through the steel wall, while being insulated from the environment through the insulation.
Intelligent Completions as a Key Technology in Brazilian Presalt
Authors: Rodrigues D. N. , Minassa L. B. , Nunes R. S. , Costa L. C. P.
Published: October 2017

This paper discusses the increasing importance of intelligent completion technology in presalt developments. The Brazilian oil and gas service industry was challenged when a major oil company decided to implement large-scale intelligent completion technology for exploratory and development campaigns for two important exploration blocks, due to the limited experience and expertise in this region. The technology is considered important for reservoir risk management because of its flexibility. An intelligent completion provides a means to remotely control inflow as necessary by a reservoir management team. This additional functionality maximizes oil production and reduces unwanted water or gas influx. The technology comprises several important multizone systems, such as remotely operated flow control valves, permanent pressure and temperature monitoring, digital infrastructure, and chemical injection valves.

With limited experience and infrastructure available in the region at the time, considerable planning and interface management was necessary to ensure successful execution. The deep water presalt application imposed several challenges and uncertainties related to long-term reliability and flow assurance, such as calcium carbonate scaling, vibration, erosion, corrosion, etc. Additionally, human resources and local technical expertise along with a strong infrastructure had to be developed. Within approximately five years, the industry effort to reduce the learning curve made it possible to deliver intelligent completion technology with a proven track record into the country.

During these intensive preparation years, several key findings were realized. Standardization became important early during the process, which was crucial for accelerating learning. However, as the understanding of the technology evolved, new applications and well designs were implemented. Intelligent completions are currently being considered during all stages of the field life cycle, from extended well testing to the mature field stage, with different benefits expected for each application. With an increasing need to optimize value from the presalt wells, a holistic approach was necessary that integrated recovered data and active control into a digital platform to allow a more informed and strategic decision making process using the intelligent completion technology capability to maximize the reservoirs’ value. Results achieved to date allow a much wider application range, with increasing importance for upcoming deepwater presalt cluster development.

A milestone of 50 wells installed in several fields using this technology was achieved in the Brazilian deepwater presalt with an accelerated learning curve. Many uncertainties existed initially; however, multiple successful installations have proven this technology implementation to be reliable, with small differences in capital expenditures (CAPEX) compared to conventional wells.
Application of the Delta Transient Method to Multi-Rate Tests: A Method for Calculating Individual Layer Permeability and Skin in a Multilayered Reservoir using Production Logging Data
Authors: Guimaraes Ciro S. , Galvao Mauricio S. C.
Published: October 2017

The method proposed in this work calculates the permeability and wellbore skin factor for each individual layer in a multilayered reservoir, fully addressing the superposition principle for the multi-rate test scenario. The method provides an explicit solution for the inverse problem, where the main inputs are downhole pressure data, production logging data and the surface rate schedule, as well as other commonly known parameters.

The Method has a strong operational drive, which consists of demanding only few hours of rig time to acquire the necessary data. The main contribution of this work is to allow the application of the method to multi-rate schedules, providing more flexibility for the data acquisition scheme. Regarding production logging data, only two flow profiles at distinct times are required for full application of the Method. No stationary data are needed.

The calculations for each layer are performed with a set of algebraic equations, which can be easily modeled in any ordinary spreadsheet software. No graph analyses are required.

The resulting skin distribution has a great impact on acid job designing techniques, enabling the assessment of diversion effectiveness across the wellbore, especially on carbonate reservoirs, where acidizing procedures are largely employed. The individual layer permeabilities provide more accurate data for geological modeling, potentially resulting in more reliable production curves and reserves estimates.

As a final step to the Method, once permeability and skin for each layer are obtained, a reasonableness check is provided. The purpose of this check is to guarantee reliability on the resulting outcomes. A successful case study is presented, where it took 9 hours to acquire all necessary data.
New-Generation, Circumferential Ultrasonic Cement-Evaluation Tool for Thick Casings: Case Study in Ultradeepwater Well
Authors: Acosta J. , Barroso M. , Mandal B. , Soares D. , Milankovic A. , Lima L. , Piedade T.
Published: October 2017

This paper describes the deployment of a new circumferential ultrasonic tool for cement evaluation used in a thick-casing environment. The operation was performed in a deepwater well, where massive loads often require heavier linear-weight casings with thicknesses greater than 1.0 in.

A new-generation, circumferential, ultrasonic cement-evaluation tool was run in combination with a cement bond-log (CBL) tool to evaluate a primary cementing operation and assure zonal isolation in an ultradeepwater well with 10 3/4-in. casing set in the 14 3/4-in. hole section. Casings with thicknesses greater than 1.0 in. are outside the operating range of current circumferential ultrasonic tools. The improvement features, main specifications, and measurement physics comparing the new tool with previous-generation technology are presented.

The operation was performed in a well containing two sizes of 10 3/4-in. casing in the same casing string. Both 85.3 lbm/ft (0.8-in. thick) and 109.0 lbm/ft (1.0-in. thick) casing sections were present and evaluated in the same pass. The sonic/circumferential ultrasonic combination was able to effectively evaluate the quality of the primary cementing operation behind both casing weights, as well as positively detect the top of cement (TOC). The combination of the ultrasonic tool with traditional bond-log technology provides independent and complementary measurements of cement bond quality. This presented the operator with the ability to radially analyze the zonal isolation using an image map and to identify cement quality issues, such as channeling and the presence of microannuli. In addition, the casing integrity was evaluated in the same pass using the ultrasonic tool.

The new ultrasonic tool makes it possible to achieve confirmation of well integrity in complex, deepwater environments, clearly identifying zones ranging from free pipe to fully cemented conditions, including radial mapping. Improvements in the measurement physics enables the analysis of the annulus in cases of heavy, thick-walled tubulars, as well as in the presence of heavier drilling fluids.
Planning and Execution of Pigging Procedure for Gas Pipeline
Authors: Carvalho Matheus Henrique Pestana de , Rotava Eloi
Published: October 2017

Multisize pipelines are widely used in offshore oil and gas production system; however, the inspection and cleaning process for these pipelines usually are more complex. The pigs used in Santos basin, such as porcupine pigs for inspection and varipigs for cleanning, require some restricions, like maximum pig speed to guarantee a good cleaning effectiveness and, mainly, to guarantee the pig structural integrity.

The main purpose of this work is to evaluate the simulation effectiveness to estimate pig total travel time and pig speed profile, therefore assuring the pig integrity during the pigging process in a gas network with many platforms interconnected. The analysys will compare total travel time and structural integrity of pigs after they arrive in final destination, given the lack of a velocity profile information in these procedures.
Riserless Open-Water Abandonment Module: Allowing Open-Water Tubing Pulling in a Safe and Environmentally Contained Manner
Authors: Batista João H. G. , Carr David J.
Published: October 2017

The increasing demand to plug & abandon (P&A) subsea wells has reinforced the need to identify true opportunities to reduce the costs of subsea abandonment.

The existing method in typical P&A programs of switching from a light well intervention vessel (LWIV or dedicated intervention semi-submersible) after lower abandonment, to a drilling rig with subsea BOP and drilling riser to perform upper abandonment activities is uneconomical, due the loss of efficiency and increase of total operational time.

In 2016, a project to develop an 18 ¾" large bore Riserless Open-Water Abandonment Module (ROAM) was launched to enhance well abandonment capacity from a well intervention vessel, by allowing tubing to be pulled in open water in a safe and environmentally contained manner. The ROAM is run in combination with a high pressure Intervention Riser System (IRS)

As ROAM has circulation capability and is self-contained, once the tubing hanger is unseated, residual fluids and debris can be flowed back through circulation hoses and the IRS intervention riser system to the LWIV, guaranteeing minimal leakage to the environment during tubing pulling operations.

ROAM also allows operator to check integrity of the cement bond behind the casing through a logging run after production tubing removal. According to the results, operator can decide to move on with upper cement plug placement and conclude the P&A or safely leave the well and prepare the remedial operation. The full bore access afforded by ROAM opens up multiple options for ‘abandonment in situ’ operations to be performed.

In order to keep the well safe in the event of the vessel losing its position (through drift-off or drive-off), ROAM has dual 10,000 psi rated shear-seal rams, an emergency quick disconnect (EQD) system and a stand-alone intervention work over control System (IWOCS), as well as a 10,000 ram to isolate annulus/circulation side.

ROAM, combined with existing riser-based (IRS) and riser less intervention systems (Subsea Intervention Lubricator or SIL), will extend the capability of well intervention vessels to perform a full P&A without jeopardizing well control and environmental protection.

The paper will give a detailed description of the design, capabilities and operational premises considered in ROAM development and also demonstrate how the system is deployed and operated to guarantee a safe, efficient and cost-effective operation. The paper will also detail all the executed qualifications and performed tests, as well as the update about manufacturing and field-tests.
Evaluation of the Discrete Latin Hypercube with Geostatistical Realizations Sampling for History Matching Under Uncertainties for the Norne Benchmark Case
Authors: Ferreira Carla J. , Davolio Alessandra , Schiozer Denis J.
Published: October 2017

This work describes a methodology that evaluates the Discrete Latin Hypercube with Geostatistical Realizations (DLHG) sample size for complex models in the history matching under uncertainties process with application to the Norne Benchmark Case. The sample size affects the time demanded and results accuracy in a history matching process because a small sample size can yield inaccurate risk quantification and a high sample size can demand excessive time to reach good results. Both factors should be evaluated in order to improve the project's efficiency and to obtain reliable results. Such evaluation gains greater importance in complex reservoir models because the number of tests to determine the reservoir scenarios that match dynamic data can be high due to the level of complexity. The methodology presented in this work is divided in three steps. First, we evaluate the ability of DLHG to produce output cumulative distribution functions (CDF) that replicate a more exhaustive sampling technique (Monte Carlo) using the Kolmogorov-Smirnov test. The output is the misfit between observed and simulated production rates; then, we compare the influence and correlation matrices obtained with DLHG and Monte Carlo samples. The influence matrix shows the impact of the uncertainty variation on the outputs and the correlation matrix measures the strength of the dependence between the uncertainty attributes and outputs. Finally, we perform the stability test. The methodology was applied to the Norne benchmark case; a field located in the Norwegian Sea. The main characteristics of the methodology are: (1) it uses a statistical technique to compare the output CDFs from the reference and DLHG samples and (2) it evaluates the ability of the DLHG sample to identify the reservoir attributes that affect the history match results. We evaluated DLHG sample sizes of 20, 50, 100 and 200, and considered a MC sample size of 5,000 to the Norne benchmark case. The DLHG CDFs for the 100 sample size was able to accurately replicate the corresponding MC CDFs, however it did not replicated the behavior of the influence and correlation matrices. The DLHG sample size of 200 was able to reproduce the CDFs outputs, the influence and correlation matrices and it was considered stable. The study showed that even if the sample size is able to represent the CDFs outputs from a reference solution, the influence and correlation matrices should be evaluated. The methodology presented can be incorporated into usual history match routines.
New Technologies for Enhanced Production in Deepwater and Long Subsea Tiebacks
Authors: Hanssen Birger Velle , Hagland Arill Smaaland
Published: October 2017

New technologies that contribute to enhanced production in ultralong tiebacks have recently been developed. These new developments include higher differential pressure in multiphase pumps and compressors, mechanical designs for high pressures and temperatures, and power systems suited for ultralong tiebacks.

When developing new, cost-efficient boosting technology for long subsea tiebacks and deep water, a system approach is important. This includes power systems, installation methods, maintenance, reliability, and condition monitoring. The new technologies described have been developed based on operational experience and physical theory combined with practical experiments and validation, both scaled and full size. The importance of developing simple and reliable solutions in facilities that enables comprehensive experimenting and testing is also explained. Today’s oil and gas price level also requires cost-efficient solutions, and the paper explains how this can be obtained through standardization and modularization.

The first pump systems that are able to provide a more-than 200-bar differential pressure are already developed, qualified, and put in operation. A game-changing multiphase gas compressor technology that provides differential pressure up to 55 bar has also been built, tested, and verified. In parallel with these developments, subsea power systems have been further developed so that they can be used for step-outs longer than 200 km. Recently, a multiphase pumping station designed for 2,500-m water depth and 15,000-psi design pressure was installed and set in operation in the Gulf of Mexico. All of this contributes to enhanced production and lower field developments costs in subsea environments and provides a platform for further technology developments that can potentially make extremely remote subsea field developments economically attractive.

This paper presents new technology related to multiphase pumping and compression and a system approach that can make production from remote and deepwater subsea fields more capital efficient.
Monitoring Flexible Risers with Optical Sensors – Operational Experience and Future Perspectives
Authors: Santiago B. M. , Morikawa S. R. , Carrara W. , Kravetz A. , Martins J. A.
Published: October 2017

Most of the subsea production systems in Brazil are developed using flexible pipes, including pre-salt fields and their challenging scenarios in ultra deepwater, with CO2 and H2S contaminants, high internal pressure and severe metocean conditions. The integrity management of these flexible pipes plays a major role in maximizing the availability of the production systems while minimizing both safety and environmental risks. One of the key areas for the integrity management is the riser top section, where high tensions and curvatures result in high stresses and may lead to fatigue issues in the tensile armors.

In order to better assess the integrity of the tensile armor at the top section of flexible risers Petrobras has developed a monitoring technique known as MODA (Monitoring based on Optical fiber attached Directly on Armor wires). As the name implies, this technique uses optical sensors — strain gauges based on Fiber Bragg Grating (FBG) technology — attached to each wire of the outer tensile armor. The strain measurements provided by these sensors make it possible to identify broken wires and detect events associated with wire ruptures.

Many components and steps are required to transform the wire strain measurements in integrity data. The main components are the riser end-fitting, adhesives, FBG sensors, submersible optical connectors, optical distribution panels, FBG interrogators and server computers. The main steps are the strain sensor bonding procedure, infrastructure commissioning, equipment installation, data acquisition, data processing and data analysis. The coordination of interfaces between different players involved in each of these steps is crucial for a successful implementation of the MODA.

This paper will discuss Petrobras operational experience with of the MODA and its challenges, lessons learned and future perspectives.