bluuebunny/crossref_metadata_2025 huggingface dataset:
Challenges of Drilling Operations in Extreme Deepwater
Authors: Capeto Jorge , Stahl Matt , Bhalla Kenneth , Kluk Daniel
Published: October 2017

This paper highlights the challenges to drilling risers and running equipment for offshore drilling operations from dynamically positioned mobile offshore drilling units (MODUs) in extreme water depths. Whereas nearly all exploratory drilling has occurred in water depths shallower than 3,000-m, Total recently set the water depth record with its Raya-1 well (3,400-m water depth, offshore Uruguay) using the Maersk Valiant drillship. Petrobras has also set a new Brazilian record for exploratory drilling by reaching a water depth of nearly 3,000-m. The 3-BRSA-1296-SES well was drilled to a water depth of 2,988-m the Moita Bonita area, located in the Sergipe Alagoas basin off northeastern Brazil. Several operators have leases that extend into significantly deeper water depths. This paper discusses approaches and criteria to evaluate the suitability these systems for operations in such depths.

As drilling water depths increase, candidate MODUs may require additional and/or upgraded subsea and running equipment to perform drilling operations. Some of the main concerns faced at these sites by the existing riser systems include but are not limited to: riser deployment and retrieval○challenges to handling and lift capacity caused by running weight and axial dynamic response,○diverter housing contactrerating / requalification of subsea BOP equipment (particularly control components);utilization of the riser system's rated capacity,riser recoil following planned or emergency riser disconnect,connected operability,collapse pressure rating,storm hangoff of the riser and LMRP,fatigue due to vortex-induced-vibration or wave loads.

In such depths, longer and heavier riser equipment, rig motions, submerged weight to mass ratio, hydrostatic pressure, mud flow, stiffness, drag, waves, and current all play important roles on riser system integrity, from the wellhead to rig equipment. In addition, many of these wells are located in remote frontiers and are typically characterized by difficult logistics and harsh environment. These factors exacerbate the complexity and potential risk of already challenging operations.

This paper provides general guidelines to evaluate and understand the performance and limitations of existing drilling riser systems on MODUs in moderate and harsh conditions in extreme water depths. The paper will discuss evaluation methods, typical findings and potential mitigations for these issues.
Application of TMCP Material for Large Diameter Pipelines under Sour Service Conditions
Authors: Schruff C. , Kalwa C. , Hillenbrand H. G.
Published: October 2017

Due to the progressive exploitation of natural gas fields pipeline designers facing more and more challenging demands to ensure durable and safe operation conditions for their products. Besides a reliable application in arctic areas, in the deep sea or in seismically active regions the HIC resistance for H2S containing fluids is a key requirement which has to be fulfilled. Here, sophisticated pipe material and tailormade solutions for specific projects have to be developed.

Over the last decades EUROPIPE is looking back on a successful history in the delivery of sour service material based on TMCP plates. This paper gives an overview about EUROPIPE´s development activities and the contribution in actual pipeline projects to fortify the confidence in the use of TMCP material:

In the beginning adequate steel making practices for sour service material are presented. Afterwards the requirements for sour service steels and the benefits of TM rolling with accelerated cooling are introduced. Furthermore it is explained how the design concerning material grades and corrosion testing has developed in the past. An outlook on further developments will be given as well.

During a controlled TM rolling process the precipitation stages, grain refinement and microstructure of line pipe material can be adjusted to meet requirements which are needed for later operation. Accelerated cooling ensures a homogeneous material and restricts carbon redistribution and banded microstructures. These effects lead to a reduction of HIC and SSC initiation sites due to inhomogeneity. Nevertheless recent operator experience has questioned the general suitability of TMCP rolled products for sour service. From the pipe manufacturers position lean alloy designs below material grade X60 are considered unsuitable due to the resulting heavy wall thicknesses and the higher deformation rates in processing plates to pipe. On the other hand the developments towards even higher grades are influenced by discussions concerning an increased carbon content and local hard spots. The presented information will show that the use of grade X65 is technically justified and the recent research activities towards the implementation of higher grades shall be further considered and developed.

Due to given results pipeline operators and manufacturers are encouraged to maintain their fruitful cooperation in the development of high quality-products even for application under severe sour service conditions.
Liquefaction Technology Considerations for Floating LNG
Authors: Tierling Shane , Attaway Doug
Published: October 2017

Floating LNG (FLNG) technologies are being deployed to monetize mid-sized offshore gas reservoirs, avoiding constructing a sub-sea gas pipeline to a land based LNG facility and export jetty. A previous OTC-Brasil paper (OTC-26158 Gas Pretreatment Considerations for Floating LNG) has discussed marinization and pre-treatment options available for FLNG, and an OTC paper (OTC-27940 Liquefaction Technologies and Mechanical Drive Considerations for Floating LNG) has discussed space, weight, and safety consideration in liquefaction technology selection. This paper is a continuation, focusing on the thermodynamic and efficiency considerations of the liquefaction technology options. For those not familiar with the previous work, there is some discussion of the marinization and safety drivers within the focus topic.

Offshore liquefaction technologies are often novel and many lack offshore references. The available offshore liquefaction technologies will be presented by Licensor and Technology name. Because of the diversity of liquefaction technologies, and to remain Licensor agnostic, the technologies are grouped by refrigeration method, with Nitrogen expander and SMR (Single Mixed Refrigerant) groupings of technologies examined with an emphasis on overall liquefaction efficiency, efficiency focus areas and design flexibility. DMR (Dual Mixed Refrigerant) is compared with the other two technology groupings.

The paper provides an overview of the FLNG state of the art in liquefaction.
Low-Cost, Rigless, Nonintervention Well Testing
Authors: Engel Diogo , Margotto Romulo , Azevedo Vinicios
Published: October 2017

Well testing is a proven method for reservoir characterization, which is important for well-completion design, future development strategies, stimulation needs, and determining the commercial feasibility of the reservoir. This paper presents a surface data-acquisition system and its applications for rigless well-testing operations.

Drill-stem testing (DST), which is classified as a temporary completion of a well, typically involves a large and complex operation. A key activity during DSTs is collecting downhole pressure and temperature data using gauges at the bottom of the well that monitor pressure changes throughout the operation. Particularly crucial are the shut-in and initial build up, which provide insight into major reservoir properties. While shutting in the well at the bottom reduces the effects of wellbore storage, providing the most accurate downhole measurements, it also requires a rig and numerous personnel to prepare the well and run in hole (RIH) the test string. A rigless DST operation using a surface closure and surface data-acquisition system has been used in several wells to optimize data acquisition recovery as a non-invasive alternative to running downhole pressure gauges for pressure-transient well testing.

The effectiveness of the data-acquisition system provides advantages and accountability by avoiding the cost and risk of running equipment downhole and monitoring tests in real-time at surface.

The surface gauges acquire high-resolution pressure data at the wellhead during flowing and shut-in, which are then converted to bottomhole conditions using proprietary models. Because this technique is nonintrusive, it can be used to test wells in which downhole gauges are impractical or cost prohibitive, such as highly deviated, horizontal wells with tubing restrictions, sour-gas, high-pressure wells with high bottomhole temperatures, and low-cost evaluations. For mediumto high-permeability formations, a three-day test is typically sufficient to calculate basic near-bore and reservoir properties, including skin, permeability, and initial pressure. Longer tests that track pressure changes to reservoir boundaries can also be used to calculate the reservoir size.

The data-acquisition system has proven its efficacy after enabling a low-noise response and low-pressure changes resulting from temperature effects. Based on data provided by the data-acquisition system, the operator designed a well-testing campaign and achieved results typical of those expected using a conventional approach.
Direct Pore-Level Examination of Hydraulic Electric Analogy in Porous Media
Authors: Goudarzi Banafsheh , Mohammadmoradi Peyman , Kantzas Apostolos
Published: October 2017

Taking advantage of the analogy between hydraulic and electrical flows to facilitate the prediction of porous media characteristics is a longstanding practice in petroleum engineering. The relationship between hydraulic and electrical properties is widely used in well-logs interpretation and characterization of transport properties of porous media relying on the strong correlation between electric and hydraulic flow conductance. However, due to the lack of direct investigations, the similarity among their pathways/tortuosities is still unclear. It is a challenging and almost impractical task to identify the streamlines experimentally. Here a series of direct finite element numerical simulations are conducted within pore-level microstructures to extract and compare the streamlines of both electric and fluid flow currents and examine the accuracy of the analogy by predicting the petrophysical characteristics of the case studies. The fluid flow and electric transports are simulated through pore-level digital rocks of synthetic unconsolidated sand packs representing the Athabasca oil sands deposit as the second largest oil reserve in the world. The formation factor, porosity, and absolute permeability of the media under consideration are predicted, and consequently, the streamlines of both electric and hydraulic currents are extracted and compared in terms of length, shape, and pathways. According to the results, the fluid flow pathways pose differently and are longer than the homogeneous electric current streamlines. The ratio between the hydraulic and electric tortuosities follows a polynomial trendline, and a local extremum occurs at the porosity of eighteen percent. Pedotransfer functions for tortuosities, dimensionless permeability, and formation factor are proposed underpinning the rigorous relationships between transport processes in rocks.
New Technologies for Cost Effective Offshore Compression Stations
Authors: Falomi S. , Iurisci G. , Matina D. , Bigi M. , Bisio V.
Published: October 2017

The need to minimize the total cost of ownership for offshore plants requires the development of technologies focused on both reducing equipment footprint and weight (capital expenses) and increasing performance, reliability and availability (operational expenses).

The OEM has been working on those features through the development of different products: ▪Maximize reliability/availability by removing most critical items (such as mechanical dry gas seals) with an integrated motocompressor design;▪Minimize the overall equipment (reduced footprint combined with improved reliability) through:High head and high-speed stages (High Pressure Ratio Compressor);Liquid tolerant compressor;Integrated auxiliaries.

The reduction of installed equipment is first obtained through combination of newly developed high head and high-speed compressor stages, which allow to increase the pressure ratio that can be performed in a single compressor casing, minimizing the total number of compressor casings required for a certain duty.

Secondly, these stages can also be combined with a compressor design which is liquid tolerant, thus allowing higher resistance to the liquid carry over from upstream scrubbers and eventually decreasing the scrubber size (or in some instances its removal). It should be noted that this technology is not only limited to flange to flange centrifugal compressor, but the overall auxiliary system (including dry gas seals’ system).

Finally, the OEM has been working on the integration of auxiliary systems: the possibility to reduce number of compressor casings, leading to possibility to handle most of services in a single body, and the reduction of required lubrication oil, allows integration of lube oil console within the compressor baseplate. This design has been proved for reinjection services up to 50 MW and for floating LNG compressors up to 70 MW.

The present paper will thus describe the design and validation strategy of the proposed technologies, showing how they can positively impact the total cost of ownership of compressor stations.
First Openhole Intelligent Well Completion in Brazilian Pre-Salt
Authors: Schnitzler E. , Gonçalez L. F. , Ascaneo W. M. , Gonçalves F. F. , Almeida R. S. , Marques M.
Published: October 2017

This paper describes a new Intelligent Well Completion (IWC) configuration used in Brazilian pre-salt fields. It also presents the first application of this new design and the future benefits expected. The conventional IWC design used in Brazilian pre-salt areas comprises cased hole wells. The casing perforation is performed before installing the completion, which does not provide a separation between upper and lower completion. The production string is installed in a single run from its lower part to the tubing hanger and does not include a disconnection element to allow the upper completion retrieval. The new design adds a separated lower completion that can temporarily isolate the formation during the upper completion installation and heavy workover operations.

In the development of the new openhole IWC design some features have been considered critical: maximum flow area, minimum complexity, CAPEX reduction, improved well safety, flexibility with single zone completion configuration and compatibility with workover. The introduction of a lower completion system added some complexity to the wells, at the same time as it provides reservoir isolation during upper completion installation. Other benefits observed are the decrease of the wellbore size required to drill into the reservoir as an openhole completion is to be installed instead of a case hole. In instance, the use of one of the casings is not required anymore. The proposed alternative was initially applied in one well for qualification and was capable of delivering a dual zone completion where initially an openhole single zone completion was planned. The use IWC in this well was an important feature for reservoir management due to the significant difference between the injectivity of the zones completed. The new design proved to be a success in this initial application.

The new solution developed has set a new completion philosophy for pre-sal wells. Other benefits of using a lower completion in IWC is the ability of quickly isolating the reservoir, what is especially important when major fluid losses are expected during drilling and completion phases. One of the major benefits of this approach is the possibility of installing the lower completion using Managed Pressure Drilling (MPD) techniques.
Cost, Efficiency, and Environmental Considerations of Medium Voltage Electric Heating Technology
Authors: Molnar Christopher
Published: October 2017

Offshore production facilities utilize a variety of process heating equipment to start production and operate efficiently. Applications include glycol reboiling, oil and gas conditioning, knock-out drum heating, molecular sieve regeneration, sea or potable water, and fuel/lube oil maintenance. Fuel-fired solutions for these applications present many challenges in regards to start-up time, operating efficiency, safety, and environmental impacts. A new technology regarding medium voltage (MV) electric heating elements and MV thyristor control technology exists as a solution for high powered process heating applications in the oil & gas and petrochemical industry.

Medium voltage electric heating technology is capable of controlling process streams to +/-1°C for very large power output and can operate on voltages up to 7,200 Volts. Medium voltage electric heating technology opens the door for new solutions to eliminate local emissions, improve on operational efficiency, and allow for greater process flexibility through the use of clean, efficient, emissions-free electric heating.

The purpose of this paper is two-fold. First, the paper provides a summary to industry experts regarding the latest design methods and test results regarding second-generation MV heating systems. It will be important to gather questions and recommendations for additional research and development of such systems from the conference and apply them to future work.

Second, this paper also highlights several case studies regarding the reduction in installation and operational costs, as well as the positive impact on footprint, weight, and safety for an offshore facility. Lab data, original analysis, and third party testing results will be presented as a means of educating the audience and to provide a model for industry standards regarding this new technology.

Finally, medium voltage electric heating technology opens the door for completely new solutions in downhole, subsea and offshore heating, especially with regard to hydrate prevention and flow assurance.
Advanced Control for Gas-Lift Well Optimization
Authors: Campos Mario C M M , Lima Marcelo L , Teixeira Alex F , Moreira Cristiano A. , Stender Alberto S , Von Meien Oscar F. , Quaresma Bernardo
Published: October 2017

The search for improvements in the production efficiency is one of the main challenges for the production engineers responsible for an asset, mainly at moments of low prices and very strict regulations for safety, environment and quality of products. Another point is that offshore plants are becoming more complex, so advanced control systems can support the operators and play an important role to improve stability and profitability.

This paper will present an advanced control algorithm for gas-lift optimization of offshore wells that aims to increase oil production. It will also show and discuss some results of the implementations of this real time advanced control system in two offshore platforms, emphasizing the economic gains and critical points to maintain this controller running with a good performance.
Soil Modelling Calibration Using Measured Data
Authors: Venero Germain , Muniz Leandro , Diezel Alexandre , Gomes Victor , Fachini Rafael
Published: October 2017

This paper presents the procedure for the calibration of a soil model represented by P-Y curves in the global finite element model of a drilling riser system using onboard measured data.

In the case of lack of real data or data uncertainty regarding the soil properties of one specific well location, the soil model can be calibrated using measured data during the drilling campaign.

The calibration procedure improves the accuracy on the prediction of the wellhead bending moment and stresses along the conductor pipe based on global riser analyses performed during the operation to assure the integrity of the well structure and thus, safe operations.
Planned Shutdown Time Optimization Using Lean Six Sigma
Authors: Matos F. L. , Pereira T. D. , Bonini C. H. K. , Carocha D. M.
Published: October 2017

Reducing planned shutdown duration (turnaround time) has been one of the biggest challenges in the offshore business. Ensuring operation efficiency while also considering safety, environment and quality issues is a complex activity that involves planning and strategies to mitigate risks and wastes. The main objective of this paper is to demonstrate how Lean Six Sigma (L6S) tools allied to good practices can guide the management of these activities, minimizing downtime and reducing Lost Production Opportunity (LPO). After the scope of work is defined, a Kaizen event was held to walk through the current process (organized in a Gantt Chart) in order to find improvement opportunities. Some Lean Six Sigma methods used were: simultaneous activities matrix, to find clashes between projects; Critical Path Analysis; 5S tagging and positioning the materials near the job location; applying the 8 wastes and Single Minute Exchange of Die (SMED) analysis to separate internal to external activities and converting possible internal to external activities; streamlining/rationalizing internal activities; Failure Mode Effect Analysis (FMEA) to provide the contingency plan on the critical path; and daily progress report using an S-curve. All these methods helped to ensure maximum efficiency of the operation, mitigating risks and wastes on the planned shutdowns. Using the proposed methodology, three successful planned shutdowns were accomplished between 2015 and 2016. The first one was the largest in complexity and duration, embracing 50 projects among vessel internal inspections, software upgrades and multiple piping replacements; the shutdown duration was reduced from 26 to 24 days, with a return of 70k bbls. The duration of the second one was reduced from 5 to 4 days, saving around 50k bbls. The last one was a partial shutdown, with more restrictions to resources on board due the live plant. The shutdown duration was reduced from 14 to 4 days, returning around 60k bbls to the company. The proposed methodology shows how the L6S tools allied with good management practices can systematically optimize all planned shutdown processes, eliminating wastes and delivering results.
Epoxy Resin Helps Restore Well Integrity in Offshore Well: Case History
Authors: Vicente Perez Miguel , Melo Jardyson , Blanc Romulo , Roncete Andre , Jones Paul
Published: October 2017

While developing an offshore well in Brazil, the integrity of a well under construction became compromised resulting from channel communication after cementing the production liner. Leaks in producing wells can cause formation damage, loss of production, and increase tubular corrosion. This paper discusses the application of a new resin for a casing-leakage problem caused by a channel after the primary cementing operation.

Conventional cements and slurries are commonly used to repair this challenge; however, these solutions are limited, at best. Depending on the channel size, well integrity can be restored with cement, but only if the channel is large enough to allow a sufficient volume of slurry to enter. The new epoxy resin exhibits exceptional resistance to contamination, including oil-based and water-based fluids, tailored mechanical properties, very-low yield point, as well availability of solids-free designs, making the resin an ideal candidate for a wide range of remedial operations throughout the life of the well.

When the challenge is outside the capabilities of either conventional solution (Portland cement/microfine cement), another method is necessary to squeeze off the leak. Recent developments have shown that resins are an excellent alternative for these types of challenges. A new resin design has overcome this limitation and is helping ensure wellbore integrity, thereby contributing to environmental sustainability and social responsibility, while acting as an annular barricade against water and gas leaks. The liner-hanger leak was repaired in one attempt using the new epoxy resin and squeeze techniques. Well integrity was restored, and the operator was able to perform the completion operation without any signs of leakage.

The new epoxy resin has become the primary solution and offers three primary benefits for restoring wellbore-integrity applications, including solids-free liquid with high-penetration capabilities and tailored mechanical properties to withstand a variety of wellbore challenges and enable customization and optimization for specific pumping operations.
Evaluation of Hybrid EOR as Polymer-Assisted Carbonated Waterflood in Calcite Cemented Sandstone Reservoir
Authors: Lee Ji Ho , Kim Guan Woo , Lee Kun Sang
Published: October 2017

Hybrid enhanced oil recovery (EOR) as polymer-assisted carbonated waterflood (PCWF) improves mobilities of both aqueous and oleic phases. The process introduces synergetic effect modifying reservoir wettability and fluids’ viscosity. These effects are the results of polymer rheology, geochemical reactions, and interphase transport of CO2 in crude oil/brine/mineral system. In this study, its performance is compared to waterflood, polymer flood, and carbonated waterflood. Firstly, polymer injection of PCWF raises the viscosity of aqueous solution over 4 cp despite of chemical and mechanical degradations. Secondly, PCWF contributes to considerable calcite dissolution increasing molality of Ca2+ by 400%. It triples equivalent fraction of Ca2+ and the reservoir is modified toward more water-wet condition. Lastly, PCWF allows CO2 to be transferred from aqueous solution to oleic phase. This transport reduces oil viscosity with 8% while pressurized system by polymer injection viscofies oil. As a result, PCWF recovers additional oil with 14.5%, 9.5%, and 2% over waterflood, polymer flood, and carbonated waterflood after 1.5 pore volume injection. Despite of the synergetic effects, PCWF requires operating cost to consume polymer and CO2. To improve oil production and economic efficiency of PCWF, robust optimization with multiple heterogeneous permeable fields is performed. Optimum injection designs of PCWF increases net present value with 36% over waterflood.
First 03 Zone Intelligent Completion in the Brazilian Pre-Salt: Design Considerations, Challenges, and Lessons Learned
Authors: Del Vecchio Filipe , Maciel Potiani , Salom Francisco , Chagas José , Ortiz Antonio
Published: October 2017

Since the first Intelligent Completion installed 20 years ago, the systems have become more and more complex in order to enable the results in terms of productivity and optimization, allowing real time monitoring and management of each zone in the well in an independent way. Accompanying the search for higher efficiency of the system is reliability assurance, one of the most important themes for the oil industry. Producers and injectors wells have been completed with the ultimate technology to achieve the best performance for each zone, allowing management optimization of the reservoirs, improving the reliability of the systems, reducing costs with workovers, therefore improving the return on investment over the life of the field. Currently, Intelligent Completion can be found widely in production areas around the world, from mature land to ultra-deepwater wells like those in the Brazilian Pre-Salt. Each scenario has its challenges, for example the Carbonates of the Pre-Salt.

Presented in this paper are the complexities and the challenges to plan and install the first Intelligent Completion in a subsea well with three producing zones in the Brazilian Pre-Salt, performed in 2015. A selective completion in three zones, comprised of feed-through packers, permanent downhole gauges in all zones, chemical injection mandrels, inflow control valves with adjustable choke, mechanical sliding sleeves and Flat Packs with hydraulic and electric lines. In addition, a downhole safety valve, Tubing Hanger (TH) with eight hydraulic penetrations and one electric, in a water depth of 2200 m. Planning and detailing were the main drivers of this big project
Cost Reduction Method for the Replacement of a Riser Bellmouth
Authors: Yoshioka R. , Thorne D. , Kovacs A. , Maier D. , Mineiro F.
Published: October 2017

Offshore constructions costs can be very high when the operation requires the use of additional vessels and support tugs. This was the case in 2016, when some of the riser bellmouths needed to be replaced on one FPSO located offshore Brazil. The initial bellmouth change-out plan included an installation vessel plus support tugs to hold the turret moored FPSO in position. As a result of the current cost constraints in the offshore industry, it was necessary to challenge the conventional way of working and to re-evaluate the construction methodology. This paper presents the methodology used on the FPSO bellmouth change-out, where all operations were conducted from the FPSO, without the need for the installation vessel or support tugs.

The FPSO for this case study is located in the Campos Basin deepwater, in 1485m water depth, and approximately 70 kilometers east of Victoria, Brazil. The FPSO started production at its current location in May 2010. The unit has a maximum oil production capacity of 100,000 bopd, and a gas processing capacity of 70 mmscfd. Oil is stored onboard and offloaded through a tandem moored shuttle tanker. The gas is compressed and exported from the FPSO via a flexible riser, which connects into the Petrobras gas export system. The bellmouth change-out operations consisted of replacing the bellmouths of each of the 8 production risers. The paper will focus on engineering design and offshore operation phases to implement the bellmouth change-out in a safe, cost effective manner.
MPC Successful Application in Deepwater Exploration: Case Study
Authors: De la Cruz Sasso Alejandro , da Silva Thiago Pinheiro , Brand Patrick
Published: October 2017

Adverse conditions are often encountered during managed pressure drilling (MPD). These conditions can include wellbore instability, kicks, and losses that create challenging scenarios for cementing operations, such as a narrow operational window (below 0.1 lbm/gal) between the pore and fracture pressure, which can compromise the necessary barrier and require unconventional solutions in deep water. We will review a successful managed pressure cementing (MPC) operation and presents findings and lessons learned. MPD allows the operator to control wellbore pressure as the hole is being drilled. By performing dynamic formation integrity test (DFIT) and flow testing, wellbore conditions are revealed, providing precise data, such as the necessary equivalent mud weight (EMW) to help prevent losses and surface back pressure (SBP) to overcome kicks. In the case discussed, information was generated during the drilling stage to provide parameters and input to proceed with cementing operation modeling, which was analyzed using state-of-the-art software to identify the crucial steps necessary for a successful operation. MPC modeling should be performed using the most reliable data to help select the best approach and tool to achieve expected cementing results. This allows densities to be defined as well as slurry and spacer volumes, displacement rates, and the recommended minimum SBP necessary for safe execution, thus helping minimize losses and avoid kicks. For the case discussed, casing was run on drillpipe using an inner string. Once landed, the cementing models were calibrated before beginning the operation using obtained DFITdata. The cementing operation was executed in accordance with the defined schedule, including surface rates, events, stages expected, and SBP. Using this method, displacement was completed, lifting pressure was observed, and then SBP was controlled in such a manner that wellbore control was maintained. Losses occurred; however, according to the final pressure recorded compared to the model, the expected top of cement (TOC) was achieved. After waiting on cement (WOC) and drill out, the leakoff test (LOT) confirmed good cement in place. Key aspects, such as communication between personnel involved during execution and the SBP control as per the design, were important to the success of this operation.
Oil-Water Pipe Flow Dispersions - From Traditional Flow Loops to Real Industrial Transport Conditions
Authors: Shmueli Andrea , Schümann Heiner , Unander Tor Erling
Published: October 2017

This paper is focused on studying oil-water pipe flow dispersions. There are two main objectives of this work: First is to gain more knowledge on the behaviour of oil-water dispersions in pipe flow. Second is to provide validation of a new methodology to characterize dispersion properties at realistic industrial conditions. The characteristics of oil-water flows such as the development of the phase fraction profiles, droplet chord lengths and pressure gradient were studied in a 0.069 m diameter and 50 m long horizontal pipe at the Multiphase flow laboratory of SINTEF in Norway. The fluid system consisted of a model oil (Exxsol D80) with and without surfactants, and tap water. A comparison of the experiments with and without a mixing valve was performed. The experiments were conducted at different superficial liquid velocities and five different watercut values (The water cut is defined as the ratio between the superficial water velocity to the liquid superficial velocity).

In addition, experiments on a wheel-shaped flow loop were conducted at selected conditions. The wheel mimics realistic pipe flow conditions for the oil-water dispersions. This methodology allows identifying flow developing time scales and long-term behaviour, which are not possible to study in a shorter test sections. Furthermore, it is possible to have an indication of the viscosity increment when dispersions form.

The results from the pipe flow experiments show that: The effective viscosity of the mixture increases by the dispersion formation promoted by the valve. As a result, the pressure gradient increases dramatically in comparison to the same conditions without premixing. For the studied cases, the surfactant concentration did not have any significant effect on pressure drop in the pipe. However, differences in the phase fraction profiles were observed especially with respect to flow development along the pipe. A possible explanation is that the effective viscosity of the created dispersion is not high enough to produce an increase the pressure drop. Flow development along the pipeline (oil-water separation) is observed just for selected cases without surfactant. For the rest of the experiments, especially with surfactant, the length of the test section was not long enough to observe flow development. With the wheel, it is simple and fast to study both formation, and stability of dispersions with real fluids at realistic conditions. There are indications that the energy dissipation rate could be used as scaling parameter between pipe flow experiments and the wheel experiments. Wheel experiments can be used to cost-efficient investigate dispersion characteristics and long-term flow development, which cannot be observed in traditional pipe flow loops due to their restrictions.
Effects of Calibrated Water into Carbonate Dissolution
Authors: Nuñez R. B. , Koroishi E. T. , Trevisan O. V. , Gadelha de Freitas Filho R. D.
Published: October 2017

Brine with designed ionic composition has been shown by many authors as a technique that improves oil recovery, allowing an increase of up to 20% of the total oil saturation of carbonates rocks samples during laboratory experiments. The main objective of this research is the development of an experimental methodology to assess the impact of the dissolution of carbonate rocks due to brine with designed ionic composition in high pressure environments, such as the ones found in Brazilian pre-salt reservoirs. This work reports the temporal effects of dissolution of outcrop carbonate rocks while in contact with water of different total salinities (38 kppm, 16 kppm, 8 kppm and 2 kppm) at 10,000 psi and 110° C, in terms of changes in mass, porosity and permeability. The experimental setup was composed of: positive displacement pump (DBR System), fluid injection cylinder, sample carrier cell, transducer pressure and oven to maintain the temperature of the system. The aforementioned samples were cleaned and dried in order to proceed with basic petrophysical characterization (porosity, permeability and weight). Outcrop rocks were placed inside pressure vessels containing water at the specified salinity and held under pressure for determined periods of time (168 hrs). At time intervals, the rock specimens were taken for evaluation of mass, porosity and permeability. Five cycles were repeated for different water total salinities. Changes on porosity and permeability were evaluated by gas porosimeter and gas permeabilimeter, respectively. Mass of the outcrop rocks were determined using analytical scale. Experiments showed that modifying water salinity can induce the carbonate dissolution which may be related with an ionic exchange between the ions present on the rock surface and the ions in the brine. A non-thermodynamic equilibrium state is created which results in chemical interactions in the aqueous phases as well as interactions between water and rock in terms of precipitation/dissolution of rock minerals and/or changing the rock surface charge resulting in loss of mass and changes on porosity and permeability of the samples. The research innovative approach consisted in the development of an experimental methodology to evaluate the effect of brine with designed ionic composition on the dissolution of outcrop carbonate rocks at high pressure and temperature in static conditions.
Application of a Methodology to Incorporate Probabilistic Data from Two Technologies: Reservoir Simulation Models and 4D Seismic
Authors: Assunção Germano S. C. , Davolio Alessandra , Schozer Denis J.
Published: October 2017

There are several methodologies that use 4D seismic (4DS) information as deterministic dynamic observed data to improve the accuracy of reservoir simulation models. However, 4DS data also have uncertainties due to errors caused by resolution, acquisition, processing and interpretation. Deterministic 4DS information does not consider these uncertainties properly. Thus, the objective of this work is to evaluate the application of a methodology that incorporates 4DS and simulation data probabilistically, considering uncertainties from both data sets.

Through the combination of uncertain reservoir parameters, multiple simulation models are generated/simulated, providing multiple pressure change (ΔpSIM) maps. In this study, the available 4DS data are multiple pressure change (Δp4DS) maps yielded from a probabilistic seismic inversion. We first transfer the Δp4DS maps to the simulation scale and then, for each reservoir position, we build two probabilistic density functions: (1) PDFSIM using ΔpSIM maps and (2) PDF4DS from Δp4DS maps. We then compare PDFSIM and PDF4DS, establishing which one is the most precise in each reservoir position, and use this information to select the most precise ΔpSIM and ΔpSEIS maps.

We used a synthetic reservoir with moderate complexity, eight predominant uncertainties (such as permeability and porosity), 11 producers and eight water injectors. Two sets of ΔpSIM were studied: (a) 500 ΔpSIM maps generated from 500 simulation models at the beginning of a probabilistic history-matching procedure using wells and (b) 97 ΔpSIM maps from history-matched models using well production data. Two sets of 4DS data were considered: (c) 125 Δp4DS maps yielded from a probabilistic inversion considering reservoir uncertainties and noiseless synthetic seismic data (d) 500 Δp4DS maps from a probabilistic inversion considering reservoir uncertainties and noisy synthetic seismic, representing a more realistic 4DS data. Using as input data (a) and (c), we identified positions where Δp4DS maps were more precise. We then selected the ΔpSIM maps using Δp4DS values at these positions. As result, selected ΔpSIM maps presented more precise estimates of pressure than the initial ΔpSIM maps. Applying (a) and (d), more precise estimates of ΔpSIM were also obtained. Using (b) and (c+d), we identified, through our methodology, reservoir positions where simulation data are more precise than 4DS data. The selected Δp4DS maps using ΔpSIM values presented more accurate and precise estimates then the initial Δp4DS maps.

The main contribution of the work was to apply a methodology incorporating simulation and 4DS data, considering uncertainties from both. Applying the studied methodology, we can use seismic information to update simulation models, as well as simulation data to reinterpret 4DS data (employment of engineering data to constrain 4DS).
Effect of Microstructure on Hydrogen Diffusivity, Trapping and HIC Resistance in Two API X65 Steels
Authors: Pereira Viviam Serra Marques , Hincapie-Ladino Duberney , Nishikawa Lucas Pintol , Goldenstein Helio
Published: October 2017

The paper compares Hydrogen Induced Cracking (HIC) resistance and Hydrogen Permeation (HP) results for two API X65 microalloyed steels, with different contents of Mn and Nb: one containing low Mn and high Nb (L-Mn) and the other, high Mn and low Nb (H-Mn). The main objective is to correlate the microstructural differences between these steels with hydrogen diffusion and trapping behavior and hydrogen-induced cracking resistance.

Both steel plates were characterized with optical and scanning electron microscopy in their transverse sections, in relation to the rolling direction. HIC resistance tests were made in accordance with the NACE TM0284-11 standard; samples obtained from the transverse section were also submitted to Hydrogen Permeation tests, based on the ASTM G148-97 standard. NACE solution A saturated with H2S was used in the two procedures. Besides, Thermal Desorption Spectroscopy measurements were made, in order to show which steel trapped more hydrogen atoms, and carbides/carbonitrides volume fractions were estimated with ThermoCalc software. The L-Mn steel presents a homogeneous microstructure through the plate thickness, composed of refined ferrite and small pearlite islands. The H-Mn steel has a heterogeneous microstructure through the plate thickness, composed of ferrite and pearlite bands, and presents centerline segregation. Hydrogen permeation tests showed that, despite all the microstructural differences, the hydrogen effective diffusion coefficient (Deff) was almost the same for both steels – the Deff obtained for the L-Mn steel is slightly higher than for the H-Mn steel. Contrary to expectations, the L-Mn steel presented higher hydrogen subsurface concentration (C0) and number of trapping sites per unit volume (Nt) values. Thermal Desorption Spectroscopy analysis confirmed that the L-Mn steel traps more H atoms than the H-Mn one. These results, along with the similar Deff values, can be explained by the presence of nanoprecipitates of microalloying elements, which, according to ThermoCalc simulations, appear in higher volume fraction in the L-Mn steel. Finally, the HIC tests results showed that the L-Mn steel has a better performance in sour environments; this behaviour is related with its special microstructural features.
Investigation of Electroless Nickel-Phosphorus Coating as an Alternative to Corrosion/Fouling Resistant Alloys in Downhole Service
Authors: Zhu Da , Uzcategui Alberto , Gong Lu , Qiu Xiaoyong , Huang Jun , Sun Chong , Luo Jing-Li , Zeng Hongbo
Published: October 2017

Harsh physical and chemical environments found in downhole operations have traditionally required the use of exotic corrosion-resistant materials, which are expensive, difficult to source and challenging to machine. This paper evaluates high-phosphorous electroless nickel (EN) coating as an alternative to these materials. The performance of this coating on carbon steel is compared to the performance of corrosion resistant alloys for fouling and surface characterization, and adhesion of inorganic and organic materials in a series of laboratory and field tests. In this paper, we first describe the complex and hostile thermal-chemical environment that exists for well completions commonly used in oil and gas production. The chemistry, physics and engineering governing principles of corrosion and fouling are reviewed. The set-up of the laboratory facilities and test procedures for fouling are described in detail. The performance of EN coated carbon steel is compared to several corrosion resistant alloys commonly used in downhole operations: 13Cr-L80, 28Cr-L80, 316L stainless steel, and Inconel 625. Examination of these specimens indicates the extent of corrosion and accumulation of fouling substances on EN coated and uncoated carbon steel at each time point.
Chokes in Series Provide Safe Testing Operations in Wells with Abrasive Solids
Authors: Margotto Romulo , Cunha Jeferson , Miranda Reginaldo , Ribeiro Daniel da Cunha , Benedito Ully Misse Moreno , Meneguelo Ana Paula
Published: October 2017

Solids production has been an issue in the oil and gas industry for years. Several materials and configurations have been tested under different conditions to determine how to produce fluids more efficiently when abrasive solids are present. This paper discusses well-testing operations involving formations with the potential for solids production. The discussion focuses on the choke manifold, which is a crucial piece of equipment used during testing operations.

The choke manifold facilitates dual-flow paths that control the well flow at surface from the upstream control equipment to the downstream process equipment and allows the operator to perform choke changes without interference to operations or test objectives. It is responsible for controlling the flow rate, upstream choke pressure, downstream choke pressure, and for maintaining critical flow. These tasks are easily achieved using a single choke when no solids are produced. However, when solids are present during the flow through the choke manifold, erosion can occur in the choke body and beans. When these parts are damaged, the well should be shut-in and all operations suspended to repair the damaged equipment.

Previous experience shows that the use of chokes in series combined with a high-resistance material (tungsten carbide) improved the choke manifold capacity to work with abrasive solids with less erosion issues. Such capability relies on the lower velocity and pressure changes provided by chokes in series. The choke configuration was tested in the field with a high abrasive flow (gas with solids) and resisted, as expected.

Computational fluid dynamics (CFD) simulations were used to analyze the flow-velocity profiles in the flow path of the choke manifold. This study presents a comparison of these results with actual field data (pressure upstream and downstream of the choke manifold during different flows) to demonstrate how the three-choke system can provide safer operations with abrasive flows.