bluuebunny/crossref_metadata_2025 huggingface dataset:
Simplified Model for Control of Severe Slugging in S-Shaped Risers
Authors: Nemoto R. H. , Abrol S. , Becquin G.
Published: October 2015

Offshore petroleum production systems are subject to the occurrence of severe slugging, or terrain induced slugging, an unstable flow regime that causes flow oscillations and may result in production shutdown. In this context, active feedback control may be implemented in order to avoid such flow oscillations and obtain the maximum possible production flow rate. For using model-based control, a simplified dynamic model of the production system is required. This work presents a new simplified model, which may be applied to risers with S-shaped geometry. Results obtained with the new proposed model show a good agreement with a high-fidelity reference model developed in LedaFlow#x2122;.
Optimizing CO2 - EOR Operations by Improved Conditioning of Reservoir Models to Time-Lapse Seismic Data
Authors: Leeuwenburgh O. , Meekes S. , Hofstee C. , Chitu A. G.
Published: October 2015

Dynamic reservoir simulation models have become an essential tool in oil field management. They can be used to explore the impact of alternative development and operating strategies, and can even be used to search for strategies that are optimal in some desired sense. Robust strategies can be obtained by use of an ensemble of models that are all consistent with available data but that adequately represent the uncertainty. In this paper we demonstrate an application of a workflow to obtain multiple models that are all consistent with historic time-lapse seismic data. We show how these models can subsequently be used to obtain optimal recovery strategies, and discuss how this approach can be extended to optimization under uncertainty.

The history matching step is performed using an ensemble-based methodology and an efficient parameterization of the time-lapse seismic data. The optimization step takes the history matched model (or model ensemble to account for all uncertainty) as input. An approximate gradient computation provides improved strategies. The history matching workflow is demonstrated on a representative sector of a field that is developed with both vertical and horizontal wells and is produced with simultaneous injection of water and CO2.

Evaluation of the history matching step indicates a good match with the seismic data, indicating the power of the parameterization method for handling very large numbers of seismic data. It is discussed that production data can be matched simultaneously, given proper characterization of measurement errors. The optimization step is performed assuming an oil recovery scenario based on alternating water and CO2 injection. Appropriate cost models may be employed to arrive at operating scenarios that result in the maximum expected economic value. Results will depend on, amongst other aspects, the chosen economic model, indicating that best operating practices will be region specific.

The combination of advanced yet practical workflows for assisted history matching and recovery optimization is the result of many developments over the past 10 years. We argue that the cumulative result of these efforts provides significant value to field developments by enabling consistency with measurements, reduction of uncertainties and improved optimization of operational strategies.
Offshore Chemical Enhanced Oil Recovery
Authors: Reksidler R. , Vieira R. A. M. , Orlando A. E. , Costa B. R. S. , Pereira L. S.
Published: October 2015

The design of an offshore chemical EOR project involves not just reservoir engineering, logistics and chemical storage issues. Oil/water separation, produced water treatment, incompatibilities with other chemicals, precipitation on surface facilities and high salinity and hardness water source are among the items that must be evaluated.

For polymer flooding, as the main offshore injection water source is seawater or produced water, the salinity and hardness will decrease the viscosifying power of conventional Partially Hydrolyzed Polyacrylamides (PHPA). For small pilots, the chemical consumption of PHPA allows the polymer storage and preparation plant to be whole built on the FPSO deck. Full-field applications may consider independent units for chemical storage and preparation. Proposed full-field alternatives for reducing the polymer consumption are polymers with higher salinity tolerance or reducing the injection water salinity and hardness. Technical and economic analyses are required to compare the alternatives.

Another concern on offshore polymer flooding is the large well spacing, requiring polymers with extended thermal resistance in hard water. At elevated temperatures, even modified polyacrylamides cannot resist long enough. It's also recommended to avoid high shear rate regions during the injection, reducing the need of polymer overdosage to compensate the viscosity loss due to mechanical degradation.

The ASP/SP method has a considerable higher chemical consumption than polymer flooding. Moreover, regular alkalis cannot be used in hard water, requiring hardness insensitive alkalis or water softening. Water desalinization will be necessary to ensure that the salinity gradient required for the ASP/SP method can be attained. Like for polymer flooding, the application of the ASP/SP method may consider an independent unit for chemical storage and water desalinization/softening. Oil/water separation and produced water treatment must be designed in order to be able to treat the back produced fluids containing the EOR chemicals.

Chemical EOR methods are an important strategy to increase the recovery factor of offshore fields, especially where there is no gas available for EOR and thermal methods are not suitable. Important steps are being taken on logistics, chemical and process developments in order to overcome the challenges on making chemical EOR deepwater offshore technically and economically viable.
Benefits of Standardization and Replication in the Bijupira & Salema Redevelopment Project Subsea Tree Design
Authors: Herdocia O. G. , Delescen K. , Rueda L. , Carvalho T. F.
Published: October 2015

In Q4 of 2011, production from the deepwater Bijupira & Salema fields was on rapid decline. The Operator started to study opportunities for tying in additional wells, but the existing subsea infrastructure composed of three 4-slot manifold was nearly fully utilized with the 12 existing wells. As the study matured over the next 15 months to the Final Investment Decision, the BJSA Redevelopment Project became a full blown brownfield flagship project for the operator, which included 3 new gas-lifted infill wells plus 1 appraisal/producer well into a new reservoir, replacement of the entire subsea control system, suspension of 3 wells, and chemical injection upgrades for the FPSO to support all the changes.

12 months after FID, the opportunity came to fruition achieving first oil on February 2nd, 2014. The execution of the project required innovation in engineering and procurement strategy. Together with its main subsea hardware supplier, the operator came up with a strategy to reconfigure hydraulics, chemicals, controls, and well slots to temporarily suspend production from 3 wells whilst still monitoring them, and gain the facilities to hook-up the 4 new wells. The field had an antiquated control system and used legacy subsea tree systems. Thus, the re-development of the field also required a replacement of the complete subsea control system with the latest technology, and adapting the company's standard Enhanced Vertical Deepwater Tree (EVDT) system used on the BC–10 field amongst other places, to work in the existing infrastructure. The innovation in procurement strategy came in to meet an aggressive schedule with an available rig. The base platform for the subsea trees (XTs) was a global standard tor the operator, enabling the use of available XTs in other parts of the world, resulting in the importation of 3 base systems from the Gulf of Mexico, and 1 from Malaysia to industrialize locally. The design engineering for the XT modifications were done completely locally and involved changing 3 of the XTs to direct hydraulic control and gas lift capable amongst other changes, whilst adapting the Bijupira control system to handle a 4th new SCM based gas lifted XT.

The strategy to manage stock of XTs globally and accelerate a critical schedule for an asset in a particular part of the world is seen as a practice worth replicating and a representative success of the global subsea equipment standardization initiative between the two companies. The value of equipment standardization did not stop at accelerated procurement. By using the same EVDT base design as the BC–10 field that was also in construction of its phase 2, the team was able to easily adapt existing procedures for installation and share tools, spares, a dock side test facility, a tree and tubing head spool installation vessel, and the great talent onshore and offshore that make the biggest impact.
Offshore Monoethylene Glycol Recovery Units: The Importance of Choice of MEG State in the Reference Environment for Effective Exergy Analysis
Authors: Teixeira A. M. , Medeiros J. L. , Araújo O. Q. F.
Published: October 2015

Monoethylene glycol (MEG) injection is an approved technology to displace the hydrates equilibrium loci in ultra-deep subsea gas production pipelines. Further, rich MEG has to be processed in MEG Recovery Units (MRU) in order to be recovered as lean MEG to be pumped back. As distillation-based technologies, MRUs are very intensive in terms of heat consumption. In offshore platforms, where space and resources are limited, besides determining energy requirements, it is also of importance to perform a thermodynamic analysis to assess degradation of energy quality, which is done by Exergy Analysis (ExA). The exergy flow of a stream is the maximum amount of power obtainable when the stream is brought into equilibrium with a reference environmental reservoir (RER). In this regard, exergy is a property that depends both on the state of the stream and the definition of the RER. This work investigates how the choice of MEG state in the RER impacts the Exergy Analysis of MRUs. Specifically, two choices of MEG states in the RER are compared by performing ExA for three technologies of MRUs: Traditional, Full-Stream and Slip-Stream. Both approaches led to consistent results with the Traditional MRU having the highest exergy efficiency (if MEG is not supposed to be degraded), while the Full-Stream MRU presented the lowest exergy efficiency, and the Slip-Stream MRU occupied an intermediate position. However, Conception #1 allowed exergy flows to be too high, masking the exergy losses. As a consequence, all MRUs have very similar exergy efficiencies. On the other hand, Conception #2 was able to better discriminate the exergy losses and could differentiate MRUs better. Only with the RER definition via Conception #2 it was possible to obtain more realistic results of exergy efficiencies.
Understanding Complexity and Uncertainty in E&P Mega Projects: The Need for a New Managerial Approach
Authors: Asrilhant B. , Beyda T. T.
Published: October 2015

Mega projects are entities that usually encompass high investment, high participation in the corporate portfolio and high complexity. Complexity is usually underestimated and inevitable in a globalized world based on technological innovation and growing demanding agents, which generally affects projects. Projects grade from simple to complicated and complex. Complex projects consist of multiple, diverse parts that operate in a standardized mode, whose interactions change over time. Because of those mutable interactions associated with possible unwelcome surprises, uncertainty plays a significant role in mega project management.

An important question then arises: how could mega projects could be managed, considering the impacts of complexity and uncertainty. An aggravating circumstance is that a simple project may become complex if immersed in a complex environment. Therefore, the context enhances complexity, notably in mega projects.

This article aims to define mega projects, complexity and uncertainty, and understand the interactions among these three concepts. These concepts and interactions will be applied to E&P mega projects. As a result, the authors propose new knowledge areas that need development and integration with traditional approaches already in use for managing E&P mega projects, which are associated with three dimensions, such as: (1) integration, collaboration and co-accountability; (2) knowledge and technical issues management; and (3) project governance and compliance.
Mass Transfer Parameters in Miscible Flows Across Carbonates Using Computed Tomography
Authors: Vargas J. A. Vidal , Trevisan O. V.
Published: October 2015

The present study presents the development and application of a mathematical model for the 1-D miscible displacement in an intrinsically heterogeneous porous media. The model, referred to as total concentration model (TCM), is developed based on the convection-dispersion equation considering the interaction between the rock and the flowing fluids. The parameters involved in TCM are the dispersion coefficient, the mass transfer coefficient, the effective porosity of the porous medium at the time of the displacement and the amount of solute that is deposited or removed from the porous medium. These parameters are determined in the application of the model through multiparametric matching to the data obtained in the laboratory. In order to evaluate the developed model, two sets of experiments (A and B) were carried out. The tests consisted of displacing two brines across carbonate rock samples. The evolution of salt concentration distribution along the porous medium sample was monitored by X-Ray Computed Tomography (CT).

The great sum of data pertaining to the concentration profiles determined from the CT images in experiment A was analyzed and matched to the TCM model through the simulated annealing metaheuristic method (Simulated Annealing, SA). A dispersion coefficient of 0.01cm2/s for a 1 cm3/min flow rate; and of 0.05 cm2/s for a 5 cm3/min flow rate was determined. The parameters of mass transfer between the fluid and the rock were also evaluated.

Experiment B was carried out in order to double check solute deposition while flowing through the rock sample. Within the TCM model, the phenomenon was quantified by the fr parameter. The concentration profiles were measured at the inlet position, along the rock sample and at the output end. A mass balance calculation was carried out with the obtained data in order to evaluate the fraction of solute deposited (fr) during the experiment. The values determined for fr were 0.2 to 0.4, figures that are consistent with the results obtained with the TCM matching procedure.

The proposed model (TCM) is appropriate for treating data obtained with CT scanners in miscible displacement experiments with relevant interaction between the rock and the fluids. The global matching procedure, considering all curves in the concentration evolution, was used to determine the governing parameters in the model. The amount of data used and the robustness of the method allowed a very good matching of the model to the experimental data.
Using a Unified Controls System for Subsea Production and Pump Controls
Authors: Sommer Burkhard , Völkel Tobias , Dvergsnes Stein
Published: October 2015

The oil and gas industry tends to seek integrated solutions that provide the full range of topside to subsea equipment and facilities down to the reservoir including installation, monitoring and life-of-field services. The subsea control system plays an important role as the binding element between subsea elements like subsea trees, manifolds, boosting and compression pumps in subsea production systems. The seamless integration of the production control system with the pump control system is the key for the success of providing an integrated solution from topside to subsea.

The most efficient way is to incorporate and merge field proven know-how of pump and production control systems based on existing technologies and accommodate it for future needs. The benefits for the customer are reduced CAPEX and significant technical advantages, being only one interface to the distributed control system (DCS), a minimum quantity of installation and workover tools, less topside and subsea equipment for distribution and control and testing equipment, a fully integrated field monitoring system and field proven components consisting of the best technologies the market is able to provide.

Depending on the project requirement a unified or integrated controls can be realized as an integration of the topside control units by adding the pump control to an existing production control system or vice versa. For new projects a full integration can be achieved from topside to subsea from system to board level.

For full integration, common building blocks from the same subsea control module (SCM) product family are being used. Core components from existing technologies have been thoroughly evaluated and selected to form the basis for the new pump control SCM which completes the SCM family.

With the introduction of the single-unit integrated controls SCM into the SCM family, a wide range of SCMs with a unified interface without losing the knowledge and experience made over years of operation can now be offered. The integration also facilitates the usage of online life-of-field services for pump and production controls in an integrated approach.

This paper addresses the key benefits and the functionality of this technology.
Hydrate Formation in Condensate and Mineral Oil Systems
Authors: Straume E. O. , Merino-Garcia D. , Sum A. K. , Morales R. E. M.
Published: October 2015

Hydrate management, as opposed to avoidance, means allowing hydrates to form, but minimizing the risk of blockage formation, such that hydrates are transported with the production fluids. This strategy is starting to be a more viable approach in industry as a means to lower development and operational costs. Safe implementation of various hydrate management strategies requires a throughoutly understanding of how hydrates form and behave in diferent categories of multiphase systems of gas, oil and water. To further obtain insight into the different processes leading to hydrate blockage formation, a number of tests using a visual rocking cell have been performed to measure and observe the various stages for hydrate formation and the changes to the system evolve with continued mixing. This study has considered mineral oil + water + gas and condensate + water + gas systems. Tests were also performed with and without MEG and a model antiagglomerant. The experiments performed have shown that hydrates have a lower tendency to deposit on oil wetted surfaces than surfaces exposed to condensate or the gas phase. However, hydrate deposition was also observed in the oil system. The predominant processes in all experiments included hydrate particle growth, bedding and agglomeration. Hydrate deposits with high porosity formed under high subcooling conditions, resulting in sloughing of the hydrate deposit due to the wetting and weight of the deposit. The addition of antiagglomerant resulted in formation of transportable slurry in the mineral oil system with 30% water cut. The mineral oil and condensate are nonemulsifying, but the pseudo-flow induced in the rocking motion of the cell created shear stabilized emulsion of the liquid phases prior to hydrate formation. Upon hydrate formation onset, the liquid phases appeared to completely phase separate.
Influence of the Gas Protection Composition on Dilution of 4130 80K Material Overlaid with 625 Alloy by Hot Twin Wire GTAW Process
Authors: Filho M. A. Deitos , Maranho O. , Gandelman A. , Santana A. Beltrao
Published: October 2015

Inconel 625 is a nickel-based alloy used in oil and gas equipment due to its outstanding corrosion resistance in seawater, chloride-containing environments, and mainly due to corrosion resistance against the production fluid coming from the reservoirs. However, since Inconel 625 is a high-alloyed material, quite more expensive than low-alloy steels used on most parts of christmas trees and other subsea equipment, their use is desired to be optimized as much as possible. One technique largely employed in the oil and gas industry is the cladding of less noble materials with alloy 625 by Gas tungsten arc welding (GTAW) process. The optimization of the weld dilution of overlays together to the quantity of deposited filler metal is a subjected under study for several researchers around the world, however, not much literature is found about this type of study for Inconel 625 by GTAW hot wire method. This work aims to help academic and oil and gas business community providing information related to alloy 625 overlay welding. Weld beads of Inconel 625 (ERNiCrMo-3) were deposited on AISI 4130 80k by GTAW twin hot wire process, with three shielding gas compositions. The usage of helium on gas mixtures utilized on this work showed two antagonistic behaviors regarding the improvement of the quantity of filler metal used and the weld dilution. The smallest reinforcement was obtained with the highest quantity of helium on shielding gas mixture, while highest amount of helium caused an increase in the weld penetration, and thus in the dilution. Pure argon showed the best dilution results, but bigger reinforcement than helium high amounted shielding gas mixture.
Design Process and Validation of an Autonomous Surface Vehicle for the Offshore Industry
Authors: Coelho R. , Daltry R. , Dobbin V. , Lachaud E. , Miller I.
Published: October 2015

Autonomous systems offer expanding capabilities to provide maritime services in a time where saving costs, creating efficiencies and improved safety are vital. Autonomous vehicles are complex systems and therefore their design and development requires careful and detailed planning. Autonomous Surface Vehicles (ASV) is a rapidly growing company based in the UK with offices in the United States and is a leading manufacturer of Unmanned and Autonomous Marine Systems. Utilising specialist expertise and experience in the design, build and operation of Marine Autonomous Systems, the C-Worker 6 Autonomous Surface Vehicle (ASV) was developed for marine operations support in the Oil & Gas industry.

This paper explores the design and build process from a naval architecture, mechanical, electrical and software engineering point of view, from initial concepts to field operations. The authors also assess the presented method in a meta-design manner. With the initial concept and technology capabilities established, ASV collaborated with Oil and Gas service company Technip to establish industry requirements and define the final configurations accordingly through a dedicated technology qualification process. Technological advancements introduced in this 6 meter long vehicle known as the C-Worker 6, include the integration of multiple offshore payload combinations including USBL, ADCP (current meter), CTD, Multibeam Sonar, Acoustic Telemetry, and Passive Acoustic Sonar (PAM) for marine mammal detection. The robust design incorporating an aluminium, self-righting hull makes the vehicle suitable for harsh ocean environments. C-Worker 6 has a 30 day endurance at an average speed of 4 knots and houses fully redundant power propulsion and communication systems.

As a result of the methodology applied, the product development timeline is presented. The paper also presents data evaluated from real missions. Early qualification of the vehicle has shown its ability to perform in the high sea states of the Gulf of Mexico successfully carrying out subsea positioning in 1300m deep waters with 2.5m waves, as well as having performed Touch Down Point (TDP) monitoring support for S-Lay pipe installation during the technology qualification. The vehicle has since undertaken different mission witch includes a 5 day deployment in the Irish Sea where it held station and extracted data from a subsea platform via an integrated acoustic modem payload, a multibeam survey on a future wind farm installation and Pacific Acoustic Monitoring (PAM) in the Gulf of Mexico.

The interest for using unmanned and autonomous systems to support marine operations in Oil and Gas industry is anticipated to grow with the industry needs and requirements for more efficient, cost effective and safer solutions.
Virtual Core: State-of-the-Art Wireline Technologies To Provide a Viable Substitute for Whole Conventional Coring
Authors: Bize E. , Tisi A. , Laronga R. , Bize-Forest N.
Published: October 2015

With the increase in activity in deep and ultra-deep water exploration, the need for geological information is penalized by its cost. Acquiring full core data in the current economic context is difficult to justify and encourages the development of less costly alternative methodologies to compensate the lack of information when coring is not included in exploration programs. This is particularly true in oil- or synthetic-base muds (OBM) where such alternative technology is still under development as opposed to the water-base mud (WBM) environment where the technology is more mature and the interpretation workflows are better established.

New state-of-the-art electric wireline technologies including large-volume rotary sidewall coring, and photorealistic OBM-adapted formation imaging combined with powerful software tools for visualization and interpretation are demonstrated to provide a viable substitute for whole conventional core for a wide range of applications, especially in clastic environments.
Development of Ultra-deep Water FPSO Mooring Ropes Using High Modulus/ High Tenacity Polyester Yarn
Authors: Bastos M. B. , Haach L. , Fernandes E. B.
Published: October 2015

This paper reports the special product development of Zhejiang Guxiandao Industrial Fibre Co., Ltd in partnership with MBB Enterprises Inc. Guxiandao is localizated in Paojiang, Industrial Zone Shaoxing City in Zhejiang /China and it is the largest industrial polyester manufacturer and supplier in the world (Zhejiang Guxiandao, 2013). This special yarn development uses the latest direct spinning LSP technology(OERLIKON BARMAG, 2013; ZHEJIANG SCI-TECH, 2013) and could be used not only in deep water but also successfully in Ultra Deep FPSO moorings where water depths were between 1500 and 3000 meters, now common on the sub-salt offshore fields. These yarn characteristics are key to produce mooring ropes that are very strong, and with high modulus (stiffer) as compared with current yarn offering, far exceeding the ISO 18692 (2007) mechanical requirements withtype approval from DNV, ABS and B.V. LankhorstEuronete do Brasil (LEB) developed in 2012 theirCABRAL 512 mooring rope using this Guxiandao yarn (G3014HQ) incorporating several rope construction innovations by reducing yarn twisting, strand torsion and increasing subrope braiding pitch as much as possible. Less twist results in lower attrition between fibers which leads to stiffer strands with higher tenacity and more to fatigue resistance. The CABRAL 512yielded breaking strength results that are 510% higher than the designed MBL, even after removing several yarn ends on each sub-rope. The improved yarn allowed Lankhort to further reduce rope'slinear density. Rope elongation was reduced from 11% to 8% meeting the stiffness criteria to reduce the FPSO offset for water depths above 2000 meters. From early 2012 to date, over 6000 tons of this yarn (G3014HQ) has been used on several FPSO projects for Petrobras, SOFEC/MODEC and SBM. All ropers have been approved and passed certification criteria required by ABS and DNV. The next step is to develop the market in Europe to supply ropes to FPSO located in North Sea, Gulf of Mexico and West Africa.
Experimental Evaluation of Pure In-Line Vortex Induced Vibration (VIV-X) in Subsea Jumper Subject to Ocean Current
Authors: Amini M. M. , Fernandes A. C.
Published: October 2015

The jumpers are typically curved pieces used to connect manifold system to wells head. In the area, it is normally exposed to significant currents. So the jumpers are subject to vortex induced vibration (VIV). However, the experimental method for prediction of vortex induced vibration (VIV) of subsea jumpers has so far been limited hence the present work advances with ad hoc experimental tests with jumpers. The experiment investigation was performed for one degree of freedom vortex-induced vibration (VIV) in a set of tests to evaluate VIV response of vertically oriented cylinder in the current channel. The experiments were conducted in the Reduced Velocity corresponding to Reynolds the number range: 10000~30000.
From Nanoscale Wetting Towards Enhanced Oil Recovery
Authors: Giro R. , Bryant P. W. , Del Grande R. R. , Engel M. , Steiner M. B.
Published: October 2015

In oil reservoirs, a significant amount of oil resides in small pores where nanoscale phenomena dominate wettability and drive the mobility of oil. Nanoscale phenomena hence control the quantity of oil to be recovered on the reservoir scale. However, there are significant scientific challenges in both experimental and computational quantification of wetting phenomena on the nanoscale. Experimentally, the challenge is controlling and characterizing extremely small amounts of liquids on sub-micron length scales. New measurement methods need to be developed in order to obtain high-quality data to be compared with simulation results. Computationally, the challenge is in the determination of adequate inter-molecular force fields, and accounting for multi-body effects requires molecular-level simulations including multiple fluids as well as surfaces. Such simulations strain computational resources. Nevertheless, an improved understanding of nanoscale phenomena to unlock trapped oil reserves demands combined experimental and computational investigation across multiple length scales. By investigating sub-micron oil droplets at an amorphous surface both theoretically and experimentally, we quantify local wetting properties at the nanoscale and probe the intrinsic wettability of the surface. The numerical simulations at the molecular level based on Classical Molecular Dynamics and Coarse-Grained Molecular Dynamics are compared with results obtained by means of high resolution microscopy. Our results demonstrate how the interactions between fluids and solids on the nanoscale determine the wetting behavior of the surface. The quantification of surface heterogeneities and chemical contaminants will enable the investigation of the effects of chemical additives such as polymers and nanoparticles on surface wettability. Ultimately, the results will be linked to mesoscale and macroscale enhanced oil recovery models.
Rheological and Thermal Behavior of Water-Waxy Crude Oil Emulsions and Model Oil Systems
Authors: Marinho T. O. , de Souza M. N. , Barbato C. N. , Khalil de Oliveira M. C.
Published: October 2015

The prediction of yield stress for waxy crude oil emulsions and the understanding of oil gelification process play a major role in flow assurance. Oil characterization and its wax content can also provide useful data, specially for engineers engaged in production procedures at offshore drilling plataforms. Since petroleum is a complex mixture of many chemical compounds, a systematic study involving model oil is suitable to account for specific influences on yield stress of systems under gelling conditions. The present work aims to study the behavior of systems at gelation conditions. Therefore, waxy crude oil emulsions and model oil systems were investigated. Rheological and thermal analysis were employed for yield stress measurments and estimations of wax amount precipitated, respectively. Characterizations by DSC, C13RMN, SARA and GC-FID were also carried out. It was verified that cooling was the most import step on yield stress appearance whilst shear rate had the biggest impact on gelification for both systems. The chemical nature of parrafins employed (branched or linear) also played an important role on yield stress values. From the results, it could be shown that aging times larger than 15 minutes did not affect yield stress appreciably.
The Extension of the Fatigue Design Life of Fixed Oil Platforms in Brownfields by Easy Model Refinements
Authors: Fernandes G. C. , Da Silva R. P. , Ribeiro M. V. , Siqueira L. A.
Published: October 2015

The recent decline in oil price directly affects the investment plans of the oil and gas industry. Due to the slowdown in this sector the allocation of resources in brownfields stands out in the current conjuncture. In today's economically challenging environment, the extension of the platform fatigue design life has become critically important from an economic perspective and because in many cases, platform design life has already been exceeded. An evaluation study was developed targeting the extension of platform design life through the refinement of fatigue analyses.

This work focuses in the improvement of environmental data, like increase of number of wave heading and wave spreading with a better representation of the platform boundary conditions by the implementation of super elements to simulate the soil-structure interaction and using the spectral approach for the fatigue evaluation. These issues were treated individually in order to observe the influence of each one in the analysis results of a representative sample of fixed platforms installed in Brazil.

After the analyses were completed, a comparative study between the results of the refinement performed and the original calculation condition was performed. The results show the level of improvement obtained in the increase of the fatigue design life for the items taken under consideration and their relevance, individually and combined.

It could be concluded that readily achievable improvements in fatigue analysis methodology coupled with refined information, which may already be available, can result in a significant increase in the fatigue design life without the need for high cost inspections. Additionally, through the experience developed in structural re-analysis of existing fixed platforms, other issues like the consideration of local joint flexibility, nonlinear analysis approaches and reliability analysis can also be considered in future jobs to further enhance platform life.
Water Alternating CO2 Injection Process - Does Modifying the Salinity of Injected Brine Improve Oil Recovery?
Authors: Ramanathan R. , Shehata A. M. , Nasr-El-Din H. A.
Published: October 2015

In the recent past, IOR/EOR technologies have been modified to include the effects of salinity of injected brine on oil recovery. Water Alternating Gas (WAG) is one such tertiary oil recovery process in the field. It greatly improves the synergy of various individual mechanisms underlining EOR processes, such as ion exchange, wettability alteration, and mobility control. This process has matured over the years, but the alteration of the salinity of injected brine during WAG has not been experimented extensively. This paper investigates the effect of injected brine salinity during water-alternating-CO2 injection and compares its performance with standalone brine injection, using 20 in. length outcrop Grey Berea sandstone cores. The water alternating CO2 process was done under immiscible conditions. It also studies the effect of aging on the oil recovery during waterflooding process.

In the present work, six coreflood experiments were performed: four experiments before aging the cores and two experiments after aging the cores. All of the experiments were done at 149°F. The evaluation of oil recovery and pressure drop were done for each coreflood. The effect of salinity on the rock wettability during waterflooding and water alternating CO2 processes was studied using axisymmetric contact angle measurements.

The effect of salinity on the waterflooding process as well as water alternating CO2 injection process was observed through the coreflood experiments. Low-salinity brine gave the highest recovery during the waterflooding process in aged cores, and seawater brine gave the highest recovery during water alternating CO2 injection process. Wettability alteration towards a more water-wet state was the cause of improved oil recovery by low-salinity brine during the waterflooding process. The lower solubility of CO2 in seawater brine compared to the solubility of CO2 in low-salinity brine was the reason for the higher oil recovery by seawater brine during water alternating CO2 injection process. Fines migration was observed during low-salinity brine alternating CO2 injection process. Aging played an important role in the recovery of oil during the waterflooding process. There was greater oil recovery in aged cores compared to unaged cores. The salinity of brine affected the contact angle measurements of the Grey Berea sandstone rock. The rock was strongly water-wet in the presence of low-salinity brine. Seawater brine made the rock more oil-wet due to the ion binding nature of the divalent ions in seawater brine. The aging of the cores increased the contact angle of the rock, thereby making the rock more oil-wet.
Managing Risk and Cost Using Autonomous Marine Vehicles
Authors: Tichatschke C. , Pai S.
Published: October 2015

Oil companies are turning to new technology to find alternatives to obtain offshore datasets. A remotely piloted, renewably powered, autonomous marine vehicle (AMV), is a prime example of this new and innovative approach to offshore operations. Vital data can now be sent straight to the client's desk using the vehicle and satellite based communications. The vehicle by virtue of its low profile and flexibility on maneuvering around obstructions can be placed as close to an obstruction as possible, reducing the risk typically involved in an operation of this nature. Furthermore, its autonomous nature makes it the ideal vehicle for METOC real-time data acquisition and transmission in the presence of harsh weather and oceanic conditions. In the case of marine seismic acquisitions, the valuable intelligence gained concerning the surface currents behavior significantly helps the party chief and his/her team to ensure they run the operation efficiently and safely (stability of the streamer spread). This paper will describe and provide data on how this vehicle has been used in the mode of data delivery for optimizing marine seismic navigation decisions in South America.

A major operator used the AMV equipped with Acoustic Doppler Current Profilers (ADCPs) to adapt a seismic survey offshore Uruguay to the local METOC conditions. The AMV was deployed to measure current strength, and provided real-time current data via satellite as the survey was underway. This information helped the party chief prioritize areas of acquisition in order to avoid entangling of the streamer and reduce the amount of feathering.

This operation was done in a cost-effective manner, and the vehicle replaced systems usually mounted on chase vessels, which were deployed for other important navigational challenges on the operation. The streamer survey was optimized without compromising results due to the vehicle's ability to hold station in the presence of currents.

By utilizing the AMV the operator was able to accurately estimate the uncertainties of a seismic survey in a remote location where data is not readily available. The AMV's persistence and endurance during the mission demonstrated its overall capabilities, it was able to do work previously done by manned vessels that deployed the moored ocean monitoring buoy, and it provided a significant reduction in capital and operation costs. This two part system is deployed as an integrated system and has the flexibility and adaptability to be deployed in a variety of marine areas to monitor meteorological and oceanographic events on, above or below the surface of the ocean. This is a novel concept for the exploration and production industry particularly as companies go into deeper waters that demand higher operating costs. To date 9 of the 26 successful completed operations for various operators have been in support of seismic surveys.
Wellbore Stability Model for Standalone Liner Completed Wells in Carbonate Reservoirs Subjected to Acidizing Jobs – II. Wellbore Stability Simulator
Authors: Santos E. S. Raggio , Ferreira F. H.
Published: October 2015

Mechanical stability analyses are mandatory to identify suitable candidates for openhole completions. These analyses should comprehend the effects of production drawdown and reservoir depletion state anticipated by the production plan. The understanding and modeling of the physico-chemical interactions between rock and flown fluids and their impacts on the rock mechanical properties have been presented in a companion paper.

This paper introduces the three methodologies intended for the wellbore stability analyses, namely the i) elastic analytical; the ii) empirical solids production and the iii) 2D elastoplastic finite element simulator (FE) and describes the reasons two of them have failed to incorporate the dissolution-induced rock weakening effects on the wellbore stability. The resulting numerical model has been implemented as a standalone specialist 2D FE Simulator. The simulator provides the well design engineers a user-friendly interface upon which they can evaluate the effects of the wellbore and reservoir pressure changes, as well as the aforementioned rock weakening effects from an acidizing job, on the wellbore stability.

The mechanical wellbore response presented by the simulator elucidates how the stress and strain patterns change after an acid well stimulation job. Wellbores under virgin rock conditions tend to fail by localized plastified zones, also referred to as breakouts, whereas wells subjected to acidizing jobs present extensive straining due to rock weakening. The boundaries of the acidized zone encloses a much less rigid rock prone to deform and compact. On one side this compliant zone provides a gradual shear distribution along the well radius inside the formation and mechanical confinement to the surrounding intact rock and therefore helps this rock in supporting the stresses as if the wellbore were much larger. However, on the other side this significant weakened rock volume poses uncertainties about its own stability or solids production risks. The installation of a perforated or slotted liner/casing acting as a bearing element tends to hold this compliant material back and accounts for the material uncertainties and lack of model representativeness in terms of eventual preferential dissolution patterns.

The unprecedented results presented by the developed simulator are assisting the company on the standalone completion decisions and increasing the robustness of well completion designs, therefore assuring the perennity of the CAPEX.
Fluid Conditioning Technology Reduces Days to Target Depth
Authors: Woolums J. , Herrington D. , Coit A. , Sherman J. , Scott E. , Szutiak G.
Published: October 2015

Drilling in hot-hole applications results in additional time and care spent to ensure the integrity of temperature sensitive downhole tools. Rotary steerable systems, monitoring while drilling equipment, mud motors, drilling jars, and electronic sensor packages measuring vibration, loads, temperature, and pressure all have temperature limitations that, when met, require drilling ahead to halt so that the fluid system can be cooled down sufficiently enough to prevent damage to these tools. Conventional approaches such as circulating to cool and evaporative cooling systems are slow and costly. This paper will detail a solution that is capable of extending the running life of these temperature sensitive tools while reducing the overall cost of the well.

An innovative technology is now available to facilitate the rapid cooling of drilling fluids. The design departs from the nonproductive time spent simply circulating to cool and surpasses the economic capabilities of evaporative cooling systems. This closedloop system has been proven on multiple wells with a variety of configurations and operational parameters to confirm the nature of the system's performance abilities. Downhole tool life was monitored and reliability data gathered to show the improved functional life of these components relative to the performance of the fluid conditioning system.

Performance testing proved directly that run life of electronics can be increased by a factor as high as 43%. This extended run life resulted in reduced trips for changing out tools and in turn improved the overall drilling rate. The reduction in drilling fluid temperatures of up to 45 °F (at surface) and 21 °F at bottomhole in a single pass allowed a reduction in nonproductive time spent circulating to cool of more than a full day.

This paper focuses on the mud chiller performance data and for the overall operations on multiple wells drilled as part of a case study in hot-hole applications. Data presented in this paper will show that the system has the ability to shorten time to depth and reduce the overall cost of drilling operations.
All Data Becomes Big When You Fail To Learn From It
Authors: Snøtun H. , Mathisen P.
Published: October 2015

Learning is defined as a permanent change in behavior, but in what way have experiences from previous projects influenced the way we plan and execute drilling operations? There is an abundance of data in the oil and gas industry, but this sharp increase in data has not necessarily translated into greater knowledge and insight. The shear waste of time, cost, effort and talent is astounding, from the engineer meticulously reporting the lessons learned during the lifetime of the project, the man-hours spent looking for the correct file, the effort used to be able to compare data from several sources to create recommendations for projects. This process is repeated across projects, companies, regions and disciplines costing millions, but the result often fails to make an impact in planning of the next project.

We have identified several barriers for efficient use of experiences in planning. One such barrier is that the information is not easily accessible, but it is dispersed on a plethora of formats, files, and physical locations, which means that the engineer spends more time gathering the information than actually analyzing it. Another such issue is the data is not easily comparable across wells, fields, and companies, due to differences in reporting, units of measure or drilling parameters. Due to the time-constraints of a project planning phase one might often end up comparing the accessible wells, rather than the relevant wells. A third barrier is that the context of the experience is often lacking, which means that the engineer knows the what was done, but often lacks the tacit knowledge about why the situation arose, like which drilling parameters were used, which formation was drilled through and what bit was used. The sharp increase of data also means that size of the haystack increases, in some estimates less than one 1% of the data captured is analyzed. This makes it harder to find the correct piece of the puzzle, because the engineer not only have to decide what information to use, but also what to ignore.

We will show, using examples from some of Norway’s leading oil companies, how you can overcome these obstacles by focusing on standardization, visualization and collaboration which makes it possible to compare lessons, wellbores and logs across projects. In the past, in the land of the blind, the one-eyed man was king. The future, however belongs to those who can create knowledge out of data.