bluuebunny/crossref_metadata_2025 huggingface dataset:
How is Multiple-Point Geostatistics of Lithofacies Modeling Assisting for Fast History Matching? A Case Study from a Sand-Rich Fluvial Depositional Environment of Zubair Formation in South Rumaila Oil Field
Authors: Al-Mudhafar Watheq J.
Published: April 2018

Modeling accurate lithofacies and petrophysical properties is a crucial step in the reservoir characterization as it affects reservoir heterogeneity, fluid flow modeling, and history matching, especially in complex geological structures. In this paper, the multiple-point facies geostatistics (MPFG) and sequential gaussian simulation were integrated as an efficient workflow for lithofacies and petrophysical property modeling of a fluvial sand-rich depositional environment of Zubair formation in South Rumaila oil field, Southern Iraq. The lithofacies features of the upper sandstone member has three main lithotypes derived from the core data analysis of 20 wells: sand, shaly sand, and shale.

In the MPFG, the surface map of the fluvial depositional system of the upper sandstone reservoir in Zubair formation was created through a 2D user-defined training image. The training image body and channels were pointed to the three aforementioned lithofacies as an alternative to the variogram to create the 3D facies system. Then, the surface map was sampled and trained by neural networks to create the discrete template of 3D facies distribution pattern into the 3D grid construction. The resulted pattern represents a numerical geomodel that captures all the features of the fluvial depositional environment of the reservoir, which then was adopted for 3D lithofacies modeling.

The resulting MPFG-lithofacies model reflected a more reasonable facies architecture than the sequential indicator simulation by preserving the fluvial features of the geosystem. Many realizations were generated and cross-validated to determine the most appropriate lithofacies model, which was considered later for the permeability and porosity modeling by the sequential gaussian simulation. To attain history matching, the resulting MPFG and petrophysical model was upscaled and incorporated into the compositional reservoir flow simulation for history matching. A near-perfect and fast history matching with the least mismatch was obtained with respect to observed and calculated cumulative and rates of oil production and water injection for the entire field in addition to all producers and injectors within the whole production history. The results reflect how is efficient considering multiple-point statistics to reconstruct the complex geological features to capture reservoir heterogeneity and achieve fast history matching.
API RP-2MET Metocean 2nd Edition; Updates to the Gulf of Mexico Regional Annex
Authors: Santala Markku J.
Published: April 2018

This paper describes the changes embodied in the upcoming 2nd Edition of API RP-2MET (Metocean). Gulf of Mexico metocean criteria updated in this edition include revised hurricane hazard curves (including a recommended method to address the so-called "crest conundrum"), the addition of an extreme wind squall criteria case and an update to the marine growth profile. Additionally, the wind section of the informative annex is updated to now include tropical cyclone-specific wind gust profiles and spectra and squall-specific wind gust profiles. The goal of highlighting the areas where RP-2MET has been updated is to ensure metocean practitioners are aware of the recent changes and apply them as they develop input to the design of offshore facilities and to offshore operations in the Gulf of Mexico.
Redefining Capital Investment: A Steady Hand in an Unsteady Time
Authors: Abughazaleh Waleed
Published: April 2018

Over 57% of Oil & Gas mega-projects exceed original budget and delivery timeline and this figure grows to over 80% for mega-projects internationally. This is detrimental to capital investment returns, especially when posed against a backdrop of weak oil prices. Integrated Oil Companies (IOCs), National Oil Companies (NOCs), and investors looking to maintain or gain a strong position in the oil and gas market are silently struggling to properly assess and secure viable strategies for capital investments. Even in a world where oil price fluctuations can be mitigated, returns are relative to each company's evaluation of capital projects and execution strategies. Unfortunately, current capital project selection methodologies are unfit to account for such wide discrepancies in performance outcome.

At the corporate level, each entity develops a framework for appraising and assessing the economic viability of its capital investment opportunities. Business cases and investment analyses employ variations of Net Present Value analysis (NPV) and Internal Rate of Return (IRR), modified to create company specific metrics that are meaningful for selection of capital projects. Yet, the prevalent overruns, in budgets and delivery timelines, translate directly into significant reduction of capital investment capability, and erode returns. These negative results are often not realized until the capital is irreversibly committed.

Past sprints of high oil prices provided a forgivingly large margin of return that made profitability certain. Moreover, the long-term nature of oil projects obscures the impact of cost overruns. However, extended low oil price environments, such as the current state, expose critical gaps in existing capital management methodologies within project driven entities. A more rigorous investment study is required for future capital allocations to ensure profitability, and in some cases, solvency.

In this paper, I present a conceptual framework for capital allocation management. This new framework, Advanced Risk and Capital Allocation Management (ARCAM), aims to synchronize risk, strategy, and capital decision modeling to ultimately give better visibility of future performance of capital investment opportunities. For the purpose of this paper, the investment decision makers are the IOCs, NOCs and oil service companies.

I will begin by referencing challenges highlighted by executive management in earning calls of top oil corporations and jointly looking at performance data of mega-projects in recent years. After taking into account the impact of low oil price environment, we will explore how applications of ARCAM framework can be leveraged to better assess the financial viability of capital investments within the oil and gas sector.
The Impact of Digitalization on Offshore Operations
Authors: Sylthe Olav , Brewer Thornton
Published: April 2018

Most of today's digital initiatives in oil and gas are incremental rather than disruptive. Some companies are taking a step forward to make improvements in technical or operational capabilities, but many are not fully embracing the power digitalization can provide. Numerous benefits such as increased cost savings and significant improvements in collaboration, productivity, maintenance and revenue have been realized through digitalization…if only more offshore operators would take the technological plunge.

Online collaboration technologies provide offshore engineers the ability to digitize workflow and planning processes, optimize decisions between experts, disciplines and companies involved in the life of field perspective, and visually identify operational activities and maintenance events once projects are online. Through digitalization, all offshore field projects – assets and activities – are: easily understandable through online 2D/3D visualizations; rapidly created or replicated using existing field layouts with a 3D asset library; immediately monitored and reporting to real-time operating levels; and getting an instant view of the cost consequences due to a required action or change to a field. Offshore operations would dramatically change upon oil and gas companies embracing and upgrading their digital capabilities, thus improving the way they collaborate with and connect new data insights to their operating models.

The novelty for offshore engineers is that digital collaboration tools are easy to integrate and train the next generation of employees to, and capable of accelerating project timelines by up to 80%, especially during the early concept and FEED phases. These time savings can drive cost savings as high as 70% across a project's lifecycle. The benefits are undeniable when this technology is implemented across the oil and gas industry…regardless of current oil prices.
CFD Analysis of Entrapped Water Response of FPSO/FLNG Turret
Authors: Yu Kai , Hsieh Yvonne , Ge Zhongfu , Yu Qing
Published: April 2018

In recent years, large diameter internal turret systems are increasingly becoming a viable solution for large FPSOs and FLNGs in harsh environmental conditions, because of higher vertical load capacity and flexibility in the riser number. The large volume of water in the moonpool introduces unique design challenges in extreme operating conditions, due to complex interactions between the water and the turret structure. The water trapped inside the moonpool exerts considerable dynamic loads on the turret and moonpool structures. These loads are combined with other environmental loadings and need to be considered in the design of the system.

In the present work, computational fluid dynamics (CFD) models were created for simulating complex entrapped water dynamics in a generic large turret design. The CFD model in this study used fully 3-D Reynolds-Averaged Navier-Stokes (RANS) equations and the k-ω SST turbulence model. Additionally, a multiphase flow model, using the volume of fluid (VOF) method, captured the free-surface. The analysis matrix included cases with forced free surface motions, vessel forced motions and vessel responses to regular and irregular waves.

The CFD simulation started with grid and time step sensitivity studies for an open moonpool. The CFD model was further validated with free decay cases by comparing the results with empirical estimates. After that, a chain table and a turret system were added into the model to perform free decay cases and forced motion cases. That CFD model was also assessed with the vessel motions in regular and irregular waves. Simulation results revealed sloshing and piston modes and natural decay rates in the moonpool, as well as temporal and frequency characteristics of water motion in response to wave forcing.

The CFD simulations clearly captured the effects of the moonpool, the chain table and the turret structures on the dynamics of entrapped water. The simulation results offered valuable insights into the flow patterns of entrapped water in the moonpool as well as the resultant dynamic loads, which are crucial to the moonpool and turret design.
Exploring New Concepts in Subsea Field Architecture
Authors: Diaz Mariana J. C. , Stanko Milan , Sangesland Sigbjørn
Published: April 2018

The present paper will explore an alternative subsea system configuration where it is possible to install dedicated equipment for each well (or group of wells) depending on its particular needs (e.g. boosting, separation, metering). This could allow achieving efficient and optimal management of the integrated system over the entire life of the field. Additionally, it opens for opportunities to optimize the operation of equipment and the utilization of resources. To test the concept, a field life study was performed on a conventional subsea oil field using a commercial software for modeling of production systems. The reservoirs were represented using a material balance model, and well rates are calculated considering the pressure drop and pressure increase (boosting) along the production system. Three cases were simulated and compared in terms of their cumulative oil production and power consumption when subsea processing is required. Case 1) standard configuration of pipeline-riser system without subsea processing unit, case 2) including a single subsea booster in the original network system, and case 3) including a modular assembly with boosting capabilities to individual wells. From all the evaluated cases, Case 3 showed the highest cumulative oil production at the end of field life. Two production strategies were tested for case 3: System demand (boosting units starting up at different times according to wells requirement) and simultaneous running mode (all boosting units starting up simultaneously). The different production strategies influence the potential for system improvement in terms of the process efficiency, production rate, and power demand.
Flow Assurance Engineering in Deepwater Offshore - Past, Present, and Future
Authors: Bomba John , Chin Doreen , Kak Ashutosh , Meng Weihong
Published: April 2018

The objective of this paper is to provide a review of the evolution of the flow assurance discipline over the years as it applies to the design of gathering and export pipeline systems. In the early days, pipeline design was essentially a job for one engineer when pipelines were on land or in shallow water, not in a new geological province, flowing temperatures / pressures were not abnormal, and had no multi-phase flow or contaminants.

This paper will identify events or circumstances that affected how "~Pipeline Hydraulics" were designed. Flow Assurance Engineering has evolved from two fundamental pillars – thermo-hydraulic analysis of fluid flow in production systems, and production chemistry.

Today, flow assurance engineers in a project not only provide predictions, but also prevention strategies, and remediation methods for: Fluid characteristicsFlow hydraulics and thermal behaviorsPerformance of the production systemGuidance of operation strategiesIdentification and management of solid deposition issues: hydratesparaffins (waxes)asphaltenesscales, etc.

They interface with multiple disciplines involved with the project, including subsurface, pipeline and risers, subsea hardware, topsides process facilities, chemical vendors, the fluid laboratory, etc.

Beginning in the late 1940s, pipelines began transporting hydrocarbons over long distances onshore (conversion of the Big Inch Crude and Little Inch product pipelines to natural gas service for example) when unforeseen flow problems began to occur. Exploration gradually moved to nearshore drilling, and finally, to shallow water. Additional flow problems increased in complexity and magnitude.

To track how these increasingly complex flow problems affected pipeline design, this paper presents: The evolution of Flow Assurance from simple hydraulics calculations to a well-defined engineering disciplineThe critical responsibilities in current deepwater development - Greenfield and Brownfield projectsThe re-shaping of Flow Assurance Engineering by digital revolution and big data technologiesThe evolution of the discipline applying new technologies to unlock new reserves with longer, deeper tiebacks
ISO Standards to Enable Reliable, Safe and Cost-Effective Technology Development, Project Execution and Operational Excellence
Authors: Østebø R. , Selvik J. T. , Naegeli G. , Ciliberti T.
Published: April 2018

This paper addresses the current oil & gas industry need for awareness and how to accelerate use of international standardization efforts, with focus on multi-disciplinary ISO standards and business governance. Qualified compliant use of ISO standards can unlock necessary business value and is a means to achieve cost-efficiency, HSE objectives, and minimize climate impact. The user domain encompasses regulatory bodies, oil and gas companies, drilling companies, engineering companies, equipment manufacturers, research & consultancies.

The ISO/TC67 Working Group "Reliability engineering and technology" has responsibility for reliability and cost related ISO standards within the Petroleum, petrochemical and natural gas industries. The portfolio of the multi-disciplinary ISO standards is internationally acknowledged and has recently been updated by many new standards that the global user domain can benefit from to achieve cost reducing technologies. Reliability and cost is part of the equation in innovative technology development processes to enforce quality and minimize risk, and enable new technology meets overall business performance objectives.

This paper will give highlights of the following ISO standards and a roadmap for their application:

ISO 14224 - Collection and exchange of reliability and maintenance data for equipment

ISO 20815 - Production assurance and reliability management

ISO 19008 - Standard cost coding system to gas production and processing facilities

Company applications are presented to show examples in technology development, project development, and oil & gas field operations. Standards relation to digitalization of oil and gas industry will also be addressed, e g. how "reliability communication" between oil company and supplier can benefit from use of the latest ISO standard 14224. Contractual framing of reliability and Key Performance Indicators will also be presented.

This ISO standardization work is based on international expert team efforts by many countries, and in collaboration with IOGP. The work supports the ISO/TC67 Mission: "To create value-added standards for the oil and gas industry", and the ISO/TC67 Vision: "International standards used locally worldwide."
Campos Basin Technologies Yard: 40 Years of Lessons Learned
Authors: Roberto M. , Coutinho A. B. , Santos A. R. Dos
Published: April 2018

Campos Basin, during the last 40 years, has been the stage where the technology development has played its main game in terms of pushing the offshore oil and gas production to overcome its challenges to go deeper and deeper in WDs never experienced before.

Incremental, innovative, enabler or even disruptive technologies, supported by a strong commitment to success and the capability and drive for field test new ideas have made such a difference.

Structured actions based on technology programs specific created for reaching defined targets, such as Petrobras Deep and Ultra Deep Water Technology Program named PROCAP, in its four sequential "versions" for over 28 years, resulted in two OTC Awards, in 92 and 2001, and helped Petrobras to achieve an important position worldwide in offshore production.

A focused projection of the future in terms of the next generation under development to overcame challenges related to revitalization of Campos Basin mature fields, such as life extension methodologies, heavy oil processing, oil and gas contaminants treatment, subsea boosting and separation systems, power distribution and transmission, that are part of Petrobras technologies "gold list" are being developed and they will be available in the next couple of years. Additionally, an internal program, named Subsea Operational Technologies, has been developed to promote a full integration among suppliers, R&D and operation teams to reduce OPEX and enhance oil and gas production in Campos Basin. Also, associated to that, a strong and efficient integrated operation control has promoted the required offshore field management drive and safety.

This paper will present a retrospective of the most significant Subsea system, Well Drilling and Completion, as well as Topsides technologies developed and deployed in the Campos Basin for more than 80 production systems in more than 30 oil and gas fields development.
Utilizing the High-Pressure Rheometer for Comparison of LDHI Effectiveness
Authors: Spratt Tony , Conrad Pete , Asheim Colton , McCarthy Ryan , Golczynski Tommy
Published: April 2018

A series of comparative tests have been performed between the autoclave and high-pressure rheometer to assess the capability of the high-pressure rheometer to replicate the results of the autoclave while utilizing smaller valumes and having increased sensitivity. A total of ten oils were used in the evaluation with an excellent correlation between the autoclave and rheometer. An overview of the results, the testing methodologies and equipment is contained within the paper to ensure the community can replicate the results.
Downscaling Global Wave Ensemble Forecasts With Machine Learning Techniques in Application to Billia Croo Test Site
Authors: Darbinyan David , Wang Michael , Buck Elaine
Published: April 2018

Accurate marine weather forecasts are essential for operational planning which could lead to significant cost savings on vessel, personnel, and equipment stand-by. There are many global forecasting products available on the market, providing free wind and wave forecasts on a global scale. However, the spatial resolutions are too coarse to fully resolve local effects. Several methods are available for forecast downscaling to represent local conditions: physical downscaling with high resolution mesoscale models, with global model providing the boundary conditions; bias correction of the global model forecast by an experienced forecaster with knowledge of local conditions; and statistical downscaling such as simple regressions or more sophisticated machine learning algorithms. The statistical downscaling approach allows fast, computationally inexpensive downscaling (as opposed to high resolution local model runs) without the need for continuous, operational support of a forecaster. Another advantage of this method is the possibility of constant improvement through continuous training as more data becomes available.

The European Marine Energy Centre's (EMEC) Billia Croo test site for wave energy converters (WEC) is situated at a location dominated by high seas. This makes the operations and maintenance planning for WECs a challenge, which accurate forecasts could help to partially resolve. Datawell Waverider buoys provide in-situ wave measurements in real-time, with data also being collected and stored. This dataset allows the implementation of machine learning algorithms to downscale the global marine forecast products. In this study, an attempt is made to downscale operational ocean wave ensemble forecasts from NOAA/NWS/NCEP model runs, with forecast lead times of +12, +24, +36, +48, +72, +96 and +120 hours. After preliminary machine learning model training, an on-line training algorithm is put in place to assess its efficiency and capacity to continuously improve the accuracy.

The utilisation of the wave ensemble forecasts as features in the machine learning model allows for consideration of the uncertainty of initial conditions of the forecast model run. A timeseries of in-situ observations in past hours are used as additional features, representing the preceding wave conditions.
Upgrade of Unbonded Flexible Pipe Design Capabilities in Pressure and Temperature
Authors: Bernard Gary , Bouche Pierre-Yves , Caicedo Juan , Chirat Mathieu , Deheeger Antoine
Published: April 2018

For decades, TechnipFMC has been providing unbonded flexible pipe technology with demonstrated capabilities up to 15,000 psi & 130°C (266°F). Lately, the need for high pressure high temperature production solutions has increased especially in the Gulf of Mexico. As limits are pushed further, new developments were initiated, continuously increasing the range of qualified products. This paper presents recent achievements extending the capabilities of flexible pipes technology up to 17,500 psi and 150°C (302°F).

While the test conditions of products are becoming more severe when targeting higher pressures and temperatures, the qualification process described in API RP 17B remain the main reference for qualification tests of unbonded flexible pipes.

The qualification tests presented were conducted in compliance with latest standard requirements. The test parameters were chosen by manufacturer based on experience and knowledge in the high pressure high temperature domain acquired through past projects.

Analysis of results was completed with laboratory examination to allow assessment of tested samples condition, ensuring both flexible pipe body and end fittings are reaching expected performance.

This paper will present the tests performed on a 6" inner diameter 17,500 psi and 150°C rated product, manufactured to demonstrate industrial capabilities and allowing as well to perform tests in realistic project conditions. This qualification work is covering both static and dynamic applications, combining high pressure high temperature conditions with ultra-deep water environmental loads.

Many qualification tests are described, including burst tests, pressure cycling tests and bending fatigue test with angle and tension variations representative of conditions encountered in Gulf of Mexico. In addition, results of material small scale and mid-scale test, also performed, highlight ability of the materials to sustain high pressure and high temperature.

Achievements of flexible pipe qualification conducted are presented to the industry, demonstrating the ability of the unbonded technology to reach design pressure of 17,500 psi and design temperature of 150°C for static and dynamic applications.
An Integrated Workflow of IOR/EOR Assessment in Oil Reservoirs
Authors: Chen Peila , Balasubramanian Sriram , Bose Sushanta , Alzahabi Ahmed , Thakur Ganesh
Published: April 2018

This paper presents a comprehensive workflow to screen, rank and evaluate improved and enhanced oil recovery (IOR/EOR) opportunities for given reservoirs. This multidisciplinary workflow was applied to multiple oil reservoirs, aiming to improve volumetric sweep and recover bypassed oil.

This comprehensive screening workflow integrates the static and dynamic reservoir conditions, and fully couples with geological and geophysical characterization. Firstly, a parametric screening and ranking for various IOR/EOR techniques for the target reservoirs are performed. Secondly, an advanced EOR screening process incorporating the evaluation of geological framework, facies distribution, flow barrier, reservoir production performance and other key reservoir rock and fluid characteristics is applied. The impacts of critical parameters to production performance are rigorously investigated, including various diagnostic plots of waterflood.

The oil reservoirs were pre-screened by oil initially in place (STOIIP) and current production rate to screen out the less attractive reservoirs for EOR. Five top-ranked reservoirs were evaluated by integrating geological characteristics (static) and dynamic reservoir indicators. Diagnostic plots such as water oil ratio (WOR), oil rate, number of active oil producers, GOR, reservoir pressure, water injection and production profiles were analyzed to investigate the reservoir performance. Through this workflow, additional opportunities were identified to increase production and/or extend the reservoir life. The reservoir screening for IOR/EOR assessment revealed a high side opportunity of adding over 5.2 MMBOE of recovery through effective reservoir management. A portfolio of most attractive EOR targets was generated for decision making by higher management.

The integrated IOR/EOR screening workflow, evolved from practical field experience, is beneficial for revitalizing mature waterfloods, effective reservoir management, recovering bypassed oil, and more importantly the design and implementation of suitable EOR pilots.
Application of Real-time Video Streaming and Analytics to Breakdown Rig Connection Process
Authors: Hegde Chiranth , Awan Omar , Wiemers Tim
Published: April 2018

Invisible lost time (ILT) has been estimated to contribute significantly to well construction costs. Reduction of drilling connection time can lead to significant savings, especially in offshore drilling projects. The overall time of a drilling connection can easily be measured using conventional sensors on the rig. However, to gain further insight into the source of operational inefficiencies it is beneficial to breakdown the overall drilling connection process into smaller sub-processes and quantify the time spent doing each. Current sensor technology does not allow us to easily measure these sub-processes on the rig. In this paper, we outline a deep learning-based computer vision method to analyze and measure such sub-processes within the overall drilling connection process using a real-time video feed.

Video of the drilling connections is streamed in real-time using a novel IT framework. In a proof of concept exercise, we applied image recognition techniques to enable us to breakdown and classify the sub-processes during the drilling connections. Convolutional neural networks (CNNs) - a deep learning algorithm - are used to analyze these video images frame by frame to identify rig activities.

The workflow includes an analytics pipeline to capture video on the rig, transfer of data to the office, video recognition analysis, tabulation of results, and delivery of this result to a graphical interface for cognitive analytics. We performed experiments wherein CNNs were used on the video images to diagnose rig activities with good accuracy. Incorporating the temporal information using a recurrent network has been shown to further improve analysis accuracy.

The described workflow is a suggested method for automating the detection of inefficiencies on drilling rigs using rig floor video and machine learning. For the demonstration case, we successfully analyzed video captured on an offshore rig and derived high value useful information using machine learning. This video analysis information can be further combined with conventional drilling sensor data to boost accuracy to identify and confirm rig activities and to quantify invisible lost time during each connection. The presented techniques demonstrate the potential of video analytics as a reliable, low-cost means to effectively "micro-analyze" various rig operations with the aim to identify and replicate best composite performance.
A Practical Approach to Evaluate Acoustic and Flow Induced Fatigue of Piping Systems
Authors: Chen Quan , Vinayan Vimal , Vrijland Ronald
Published: April 2018

Piping systems having flow discontinuities like bends, tees, reducers and valves can experience acoustic induced vibration (AIV) or flow induced vibration (FIV) due to internal pressure fluctuations (acoustic or turbulent flow sources of excitation). The excitation may range from 20 Hz to 5000 Hz depending on the pipe geometry and flow characteristics. At such frequencies, excessive vibration can cause fatigue-induced failure of the piping system if not designed properly. In some extreme cases, failure may occur in a matter of days or even hours. This paper proposes a practical frequency domain based finite element analysis (FEA) approach/design-tool to calculate the fatigue damage of piping systems due to FIV or AIV.

For a FIV analysis, the two key steps that can be identified in this approach are: (1) the development of a transfer function, and (2) the generation of a pressure fluctuation spectrum over the frequency range of interest. The transfer function defines the relationship between the stress range (∆σ) and a unit pressure fluctuation (∆p) that is used to calculate the fatigue damage. It is assumed that the stress range reaches a maximum when the internal acoustic pressure spatial distribution completely coincides with the natural mode shape of the pipe system. Harmonic analysis is performed to obtain the maximum stress range at each natural frequency of the piping system. From the transfer function and pressure fluctuation spectrum, a stress range spectrum can be calculated. Assuming a Gaussian fluctuating pressure distribution, a Rayleigh distribution is expected for the stress range. The fatigue damage can be calculated using a closed-form solution with an associated S-N curve. A typical tee-joint in a pipe spool will be examined to illustrate the procedure. The proposed procedure can be modified for an AIV analysis specifically, which is not presented here.
Use of Magnetorheological Fluids for Pressure Drop Generation
Authors: Estrada John , Akbari Babak , Nielsen Garrett
Published: April 2018

The magnetorheological fluids (MRF), or magnetic field responsive fluids, are a combination of magnetically polarizable particles in a carrier fluid. This type of fluid has the ability to modify their rheological properties under the influence of a magnetic field. The generation of a tunable pressure drop could have the potential to controlling fluid losses while drilling and cementing in narrow operating windows and to provide a tunable fluid barrier that could work as a packer. Using the reduced form of the Navier-Stokes equation and a model to estimate the yield stress of the fluid based on the magnetic field strength, it is possible to determine the pressure drop caused by the fluid behavior.
Effects of Nanoclay on the Rheological Properties and Resistivity of Synthetic Based Drilling Fluids under High Temperature
Authors: Pan Dongmei , Vipulanandan C. , Amani Niousha , Reddy Sai Anudeep , Chockalingam Chella Ganapathy
Published: April 2018

In this study, synthetic based drilling fluids (SBF) were developed for high temperature applications and modified using nanoclay to improve the sensing properties for monitoring. The major constituents of drilling fluids were fatty acid methyl esters, surfactant and water. The ratios of synthetic based fluid to water (S/W) ratios of the SBF were 50/50 and 70/30. The temperature was varied from 25°C to 85°C. The nanoclay concentration was varied up to 1% by the weight of the SBF to modify the rheological properties and the sensing electrical resistivity of the SBF. The effect nanoclay on the rheological properties and electrical resistivity of the SBF was investigated. PV of SBF (50/50) was increased 100% and 286% at 25°C and 85°C respectively and additional of NC reduced the effect of temperature on the PV of SBF. Hyperbolic model has been suggested for modeling the rheological behavior of the SBF to predict the ultimate shear stress. Adding 1% of NC affected the rheological properties by increasing yield point and ultimate shear stress of the SBF with S/W ratios of 50/50 and 70/30. The electrical resistivity of the drilling fluid with and without nanoclay decreased with the increase in the temperature. The results also showed that even 1% nanoclay decreased the electrical resistivity of the drilling fluid 30.2%. This clear indication of the sensitivity of electrical resistivity to the nanoclay contents and the electrical resistivity is a good tool for quality control for the SBF.
Case Study of an Offshore Operation Conducted with a Fit-for-Purpose Abandonment System
Authors: Canny Steven A , Olstad Delaney Michael
Published: April 2018

Traditional late-stage abandonment operations can utilize equipment originally designed for drilling a well. However, innovative new technologies have been developed which far better meet the unique needs of intervention and abandonment work. The effective application of these systems in the oil and gas industry has resulted in both significant cost savings and an increased standard of safety. Additionally, Operators have realized that an integrated project solution from a single source is integral to completing the job scope in a competent and effective manner. This paper examines the successes of a fit-for-purpose system currently working in the Gulf of Mexico which is specifically designed to both conduct late-stage intervention and abandonment project, and focus on safety while reducing overall operational expenditures.

To effectively address the market, a new method for completing workovers and abandonment operations was needed. Subsequently, a system was designed which incorporates capabilities associated with costly Jack Up rigs along with the quick mobilization and set up of a crane assisted rigless unit. This solution has been utilized in offshore campaigns that include all phases of abandonment operations including well diagnostics, reservoir isolation, tubular retrieval, fishing, section milling, and conductor recovery

The case study will highlight the versatility and adaptability of the system which provides an integrated solution package to the client. The system which includes a pulling and jacking unit also includes all ancillary equipment necessary to efficiently intervene and permanently abandon offshore wells. The case study will discuss the project parameters, examine the operations, and review the lessons learned from a multiple well project on an offshore platform in the Gulf of Mexico.
Safety Distances of Packers for Deep-Water Tubing-Conveyed Perforating
Authors: Deng Qiao , Zhang Hui , Li Jun , Dong Jian , Wang Hao , Hou Xuejun
Published: April 2018

The technologies of high density and high charge perforator are widely used in the perforation jobs of deep-water wells, resulting in a large increase of impact loads in the wellbore. Determining the safety distances between the packers and the perforating gun is a critical step for developing completion designs of deep-water. This paper examines the processes of pressure wave generation, attenuation and reflection propagating through the completion fluid during wellbore perforation and develops a calculation model to formulate safety distances of the packers to protect the non-perforated wellbore. A calculating model containing an unknown function is established, which is used to solve the safety distances of packers and a mathematical model based on numerical simulation results is proposed to predict the peak pressure on the perforating gun, which can evaluate the sensitivity of peak pressure to changes under different conditions of perforation. The complete calculating model for determining the safety distances of packers is finally created. The results of case study show that the predicted peak pressure by the model is accurate, within 10% of measured values by a pressure sensor installed at the bottom of the perforating gun during a well completion job within the South China Sea. This calculating model indicates that the attenuation law of the pressure wave propagation in the completion fluid basically accords with the exponential attenuation mode, which is verified by the data of underwater explosion experiment. The number of perforating bullet, charge per hole, tubing length, formation pressure and wellbore pressure are important factors of the safety distances. According to the numerical simulation results of the field example, the shock absorber has the optimal installation position, which the ratio R0/R=0.6 being the best shock absorption effect can be achieved. This study proposes a novel method for the safety distances design of packers and the location of the absorber is optimized, which has important significance to provide guidance for the design of deep-water perforating operations and to improve security.
Modeling Subsea Gas Release to Atmospheric Gas Dispersion Cloud
Authors: White Charles , Pétrié François , Rousse Benjamin
Published: April 2018

A new methodology has been developed and tested by the authors to model gas dispersion efficiently from a subsea pipeline gas release. The methodology was applied to two practical cases: a 1′ diameter hole and a full pipe rupture in 100m water depth. The objective of the study was to develop a calculation methodology to simulate gas cloud propagation above the sea surface from a subsea gas release. The simulation includes modeling the gas concentration in air to determine if the concentration reaches critical levels.

The methodology utilizes three steps:

Calculation of gas discharge rate;

Calculation of subsea gas jet and plume utilizing an analytical model;

Calculation of gas dispersion in air with specialized CFD software.

This paper presents a case study performed for each calculation step with the objective of increasing the calculation efficiency compared to a typical full CFD methodology.

This methodology has shown promise in providing a simple, quick, and cost-effective solution for these safety analyses. The main efficiency is realized modeling the subsea jet and plume using fundamental equations. The subsea model and analysis determine the gas content repartition at sea surface as an input for the gas dispersion analysis. An analytical model was utilized, with some simplifying assumptions, leading to a significant reduction in calculation time. The analytical model used has been validated with underwater gas plume experiments. The reduction in calculation time can allow for an increased number of simulation and sensitivities of the study, leading to a better understanding of the main sizing parameters involved.

As a conclusion, the limit of the present approach and its validity domain are discussed based on the models used and the assumptions performed during the calculations. Further developments can be anticipated (e.g., larger water depth application or validation of high gas discharge rates based on experiments to evaluate the limitation of the assumptions).
An Example in the Use of Performance-Based Engineering for Offshore Shallow Foundations Overlying Liquefiable Sand
Authors: Sancio Rodolfo B.
Published: April 2018

Geohazards affecting offshore facilities are typically mitigated through avoidance. However, as stated by Cauquil (2014), exploration and production activities are moving to more complex and deeper geo-environmental contexts, and recent projects have shown that it may not be possible to avoid the geohazard and its impact area. Therefore, facilities in these fields must be developed using a design that can overcome the effects of the hazard.

If present, seismically induced geohazards (e.g., seabed settling due to liquefaction) can be mitigated by placing facilities on deep foundations that penetrate through liquefiable layers. Alternatively, facilities can be placed on shallow foundations that are designed to tolerate permanent ground displacements. These ground displacements depend on various factors such as the density and thickness of the liquefiable layer, the depth to the liquefiable layer, and characteristics of the ground motion (e.g., intensity, magnitude, and duration). The magnitude of settlement that needs to be incorporated in design must be based on either a deterministically developed design earthquake scenario or a probabilistically developed annual probability of exceedance (or return period).

This paper describes how hazard curves can be calculated to estimate liquefaction-induced settlement under shallow foundations overlying liquefiable soils. These hazard curves were developed using the PEER performance-based earthquake engineering (PBEE) framework (Deierlein et al., 2003). The PBEE framework incorporates the probability of seismically induced ground motions developed from a probabilistic seismic hazard analysis (PSHA), the probability of liquefaction conditioned to the occurrence of a ground motion, and the probability of settlement conditioned to the occurrence of liquefaction. The results of the analyses are discussed, and recommendations are made for incorporation in evaluation of geohazard and designs considering their occurrence.
Application of System-Theoretic Process Analysis to the Isolation of Subsea Wells: Opportunities and Challenges of Applying STPA to Subsea Operations
Authors: Kim H. , Lundteigen M. A. , Hafver A. , Pedersen F. B. , Skofteland G.
Published: April 2018

Systems-Theoretic Process Analysis (STPA) is a recently developed hazard identification technique that is based on control and systems theory. Previous studies on STPA emphasize two major strengths of the method: (1) STPA provides a systematic top-down approach that enables early identification of system flaws, and (2) STPA covers a wider scope of hazards compared to traditional methods. Despite these advantages, there are only a limited number of studies that have applied the method to subsea systems. It is therefore of interest to investigate how STPA can be used to formulate new or verify existing requirements to safety-critical systems for subsea facilities. One example is the isolation of subsea wells initiated by the platform emergency shutdown (ESD) system. The purpose of this paper is to apply STPA to this function, and to discuss opportunities, challenges and possible implications of the results obtained from the analysis.

The paper starts with a thorough literature study and includes an analysis of the insights and recommendations made from other industry sectors and application areas. This review is followed by the STPA analysis of the proposed system, with focus on the identification of the unsafe control actions and safety constraints for subsea well isolation. It is investigated how STPA is able to address specific design philosophies and subsea operating conditions, like fail-safe function of subsea ESD valves, long distance between top-side control system and subsea valves, and dynamic behavior of the control structure. The paper concludes with discussions and suggestions on how the STPA procedure may be improved for application to subsea systems.
A Low-Viscosity Retarded Acid System for Stimulation of High-Temperature Deep Wells
Authors: Sayed Mohammed , Cairns Amy J. , Aldakkan Bashayer S. , Gomaa Ahmed M. , Alnoaimi Khalid R.
Published: April 2018

To enhance the efficiency of acid stimulation treatments in high-temperature carbonate reservoirs, the industry requires a superior retarded acid system that inherently displays high thermal stability, controlled reaction rate, and acceptable corrosion losses. One of the earliest means of acid retardation was through the addition of polymer gelling agents; however, these sytems commonly lead to formation damage. Alternatively, a commonly used approach to slow down the acid/rock reaction rate is through the use of acid-in-oil emulsions (i.e., emulsified acids). The viscous nature of these fluids, however, leads to unfavorably high friction pressures during the pumping process. Additionally, the thermal stability of emulsified acids is questionable at temperatures exceeding 300°F. Herein, we introduce a novel engineered acid system for stimulation of high-temperature carbonate reservoirs. The proposed technology reduces the free water in the system and consequently prevents full dissociation of the acid. Reducing the free water in the acid system was successfully achieved by engineering the acid formulation in the presence of another organic compound that is readily soluble in the acid.

A series of benchtop carbonate dissolution experiments were performed under static conditions at room temperature to identify the optimal engineered formulation needed to achieve the desired retardation effect. The retardation behavior of this system was further supported by reaction rate studies, coreflood measurements and corrosion loss data. The proposed acid system was evaluated at temperatures and pore pressures up to 350°F and 3000 psi, respectively.

Experimental results confirmed that the engineered acid system requires only 0.28 PV to achieve a breakthrough (12 inch core), which represents a significant reduction as compared to some reported emulsified acid systems. Importantly, the fluid formulation was systematically fine-tuned in order to impart the desired fluid-property characteristics: low-viscosity (est. 4 cp), high dissolving power (4.16 lb acid/gal), fast wormhole propagation rate, low corrosion loss (<0.05 lb/ft2, 275°F) and high thermal stability (>300°F). The acid system can be readily mixed on-the-fly with existing equipment. This is a desirable feature particularly when it comes to offshore operations as no special preparation methods are required.

It is the opinion of the authors that this novel acid system provides the industry with a suitable fluid alternative that may offer the potential to enhance oil and gas production in carbonate reservoirs. The fluid is stable at high temperatures and may have the potential to be used in a broad range of stimulation applications. Importantly, this low-viscosity retarded acid system presents the industry with a novel acid alternative where acid retardation by polymer addition or emulsification in diesel is no longer required.