bluuebunny/crossref_metadata_2025 huggingface dataset:
The Impact of Submarine Slides on Pipelines: Outcomes from the COFS-MERIWA JIP
Authors: White D. J. , Randolph M. F. , Gaudin C. , Boylan N. P. , Wang D. , Boukpeti N. , Zhu H. , Sahdi F.
Published: April 2016

This paper presents key outcomes of a 3-year Joint Industry Project funded by 6 Operators on the impact of submarine slides on pipelines. This JIP developed new techniques to simulate slide runout, and assess the resulting loading and deformation of seabed pipelines. The work was distilled into guidance for practical application, which has found adoption on projects.

The JIP spanned (i) characterization of soils at the solid-fluid transition, (ii) computational modelling of slide runout – via depth-averaged and continuum finite element methods, (iii) physical and numerical modelling of slide runout and pipeline impact, and (iv) analytical studies of pipeline response during slide loading. These elements combine to provide an improved practical basis for quantifying the risk associated with slide-pipeline interaction.

To characterize very soft seabed soils, a new geotechnically-based framework was devised based on extensive measurements of different soils. This framework spans the solid-fluid boundary that is crossed as slides evolve into a debris flow and turbidity current. It is shown that the geotechnical link between water content and shear strength extends continuously – with no phase transformation – far into the fluid domain, allowing a single rheology to be applied throughout.

Computational modelling of slide runout used a hierarchy of methods, from large deformation finite element analysis (LDFE) (with rate effects and softening at soil element level), through depth-averaged runout, to energy-based analytical solutions. In some regimes of behavior the simpler methods suffice, allowing efficient use of Monte Carlo methods to tackle uncertainty. More complex runout modes can be replicated by newly-developed LDFE techniques.

From a runout analysis results, pipeline impact loads can be assessed using new solutions for the bearing capacity and drag forces on pipelines developed from numerical and physical modelling, which again unify concepts from fluid dynamics and geotechnics. Finally, simple analytical methods for assessing the structural response of a pipeline to a known slide loading are provided. These solutions allow rapid assessment of the response of a pipeline to a specified slide loading.

These advances improve the methods available for quantitative assessment of slide runout and slide-pipeline interaction, allowing better determination of the resulting geohazard risk.
Assessment of Seafloor Trench for Suction Pile Moorings: a Field Case
Authors: Alderlieste E. A. , Romp R. H. , Kay S. , Lofterød A.
Published: April 2016

Seafloor trenching is recognized as potential threat for reduced holding capacity of suction piles for mooring facilities. Trench formation due to chain movements occurring in typical deep water soft soil conditions offshore West Africa has been identified by the industry. Trench heights approaching lug level have been recorded. This paper describes an assessment to account for chain trench development in front of a suction pile for in-place holding capacity.

The paper identifies the change in failure mechanism due to presence of a trench. Consequently, a downwards shift of optimum lug level is recommended to account for possible trench formation. Trench formation may adversely influence reverse end bearing capacity, which is generally relied upon for moored configurations. Reduction of the horizontal capacity is found to range from 20% for "fixed head" conditions, to about 32% for "free head" conditions, depending on the selected lug level and presence of global scour.

Based on finite element analyses and a yield envelope framework, an assessment of trenching effects on suction piles capacity is presented in this paper. Future suction pile designs could be optimized by considering the presented methodology.
The Electrically Trace Heated Blanket: A New Concept for Efficient Subsea Flowline Unplugging
Authors: Marret Antoine , Espinasse Philippe , Parenteau Thomas , Routeau Sylvain
Published: April 2016

Subsea Flowlines blockage due to hydrate or paraffin plugs, resulting from pour point issues or deposition, is a frequent concern in subsea production requiring expensive remediation methods. The expenditures associated with subsea flowlines unplugging can increase very quickly, especially when considering the associated loss of production as well as the various investigations needed to define the appropriate remediation strategy. Such investigations cover the identification of the plug's nature, its location, the assessment of the appropriate dissociation method as well as the flowline restart strategy.

In some scenarios, the plug dissociation method, like depressurization for hydrate plug and chemical soaking or pigging for paraffin plug, may take a long time ranging from several days to several months. Often, the remediation cannot be performed from the topside facility and will require the mobilization of an external drillship vessel to carry manifold or Xmas tree work over. Ultimately, the plug removal method may fail and therefore lead to flowline abandonment and/or replacement. From these observations, there is room for the development of a more efficient, predictable and reliable method to unplug subsea flowlines. With this regard, the development a new subsea flowline intervention system named Electrically Trace Heated Blanket (ETH Blanket) has been initiated.

The ETH-Blanket is a compact and modular system, with length adaptable typically up to 2km. The system is equipped with trace heating cables relying on Joule's Effect for heat generation to dissociate the plug and distributed temperature sensing (DTS) to monitor the flowline's bore temperature in order to identify the location of the plug, characterize its nature and follow-up the temperature and pressure profiles during plug dissociation. The ETH Blanket can be deployed onto any kind of existing flowlines (flexible or rigid) and in any condition (buried or not) from a Light Construction Vessel. The power required to dissociate the plug is low (typically <1MW) and once the dissociation is completed, the ETH Blanket can be recovered onto the intervention vessel and relocated.

This paper describes into details the ETH-Blanket assembly and its operating principles, its anticipated thermal performances determined using CFD modeling, as well as and its deployment method and spread. To illustrate the ETH-Blanket efficiency, a typical multiple hydrate plugs dissociation operation will be presented and compared to a conventional topside depressurization.

As a conclusion, the on-going fast-track qualification programme for the development of the Electrically Trace Heated Blanket Technology will be presented.
Design Aspects of Pipe-in-Pipe Systems for HP-HT Applications
Authors: Sriskandarajah T. , Ragupathy P. , Rao Venu
Published: April 2016

The High Pressure and High Temperature (HP–HT) subsea field developments are increasingly using Pipe-In-Pipe (PIP) systems for transportation of production fluids due to superior thermal conductivity performance compared to wet insulated single pipe system. PIP systems can provide the necessary thermal insulation with very low Overall Heat Transfer Coefficient (OHTC) in the order of 0.5 to 1.0 W/m2.K whether installed exposed on the seabed or trenched and buried. An additional inherent feature of PIP systems is that they offer increased protection against third party interaction such as fishing gear and dropped object impact.

PIP system will provide a very long "no touch time" before any intervention (e.g. depresurisation) becomes necessary. This aspect can also be improved by using e.g. hot water circulating and electrical heating in order to overcome difficulties which may arise from prolonged shutdown periods.

The mechanical design of a HP–HT PIP systems is more complex than conventional single pipe system and involves consideration of additional failure modes. This paper gives an overview of the PIP system design, with particular emphasis on in–service buckling and fatigue design. Design considerations for trawl gear impact on lateral buckling and operational aspects of clad and lined pipes for HP–HT and sour service applications are also discussed.
Application of a Novel Cement Spacer with Biodegradable Polymer to Improve Zonal Isolation in HTHP Wells
Authors: Li Li , Alegria Adriana , Doan Angela Anh , Kellum Matthew Grady , Castanedo Rodrigo
Published: April 2016

In deepwater drilling, spacers are widely used between drilling fluids and cement to effectively remove the drilling fluids and improve cement bond. A variety of spacer systems have been applied over the past decades with biodegradable polymers. However, most of these biopolymers are thermally stable only below 200 to 300°F and lose viscosity above their degradation temperature. In this study, a new spacer system for HTHP wells has been developed with a novel biopolymer and lost circulation materials.

The performance of new spacer is compared with a previous spacer system, which has been successfully applied to wells on land and offshore, especially for preventing and remediating lost circulation issues while cementing. The rheological properties of unweighted and weighted spacers (12 to16 ppg) were measured from room temperature up to 400°F with a stabilizer. The new spacer exhibited a superior rheological profile at elevated temperatures. The compatibility tests were conducted between the spacers and various types of drilling fluids and cement slurries. The new spacer improved the compatibility with synthetic/diesel-based drilling fluid and cement with less or no viscosification. The sealing performance of the spacers was determined in a fluid loss cell with 20/40 proppant. The new spacer effectively prevented losses by sealing the proppant under pressure. To date, several land operations have been successfully completed and one case history is discussed in detail.

In summary, the new spacer system is stable at high temperature, improves compatibility with drilling fluid and cement, and maintains good sealing performance. The new spacer is applicable in any types of wells and cementing operations, especially where high-permeability, fragile, unconsolidated and low-fracture-gradient formations are present. The new spacer is biodegradable, forms a seal to minimize filtrate invasion into the formation, effectively reduces cement losses and formation damage from filtrate migration, and enhances hole cleaning prior to cement placement.
Process Electrification and Offshore Grid Systems
Authors: Devold Håvard , Moen Tor Eivind , Maland Asmund
Published: April 2016

Oil and gas process electrification is recognized to reduce operating cost, improve energy efficiency and improve environmental factors. Offshore electrification has been limited by distance costs. Now extended reach for AC systems, improved HVDC systems, and emerging availability of offshore gridded systems that can include multiple power sources and consumers are providing improved economics.

The full economic and technical analysis is complex. We will examine how technical factors such as power requirements, distance, losses, and maintenance and operating costs combine with key economic criteria such as capital, operations and energy costs, and depreciation. We will then discuss models for how overall availability and operational stability are affected by the energy mix and the quality of the power management of the microgrid. Other factors such as HSE and environmental impact can also affect the investment decision.

Earlier models we presented, such as those in SPE-162504, considered mainly point to point connections. We here demonstrate how gridded systems, including long distance HVDC connections, combine with local AC grids that can integrate multiple offshore facilities and power sources. The paper is based on experience and ongoing projects in the North Sea and current studies in the Persian Gulf and Caspian Sea, where integration across multiple facilities and consumers and network dynamics of multiple sources such as Power from Shore, Local Generation and Offshore wind in microgrids have been studied. (We include actual data from concluded studies, or anonymized data subject to client permission.)

The study focuses on large offshore electrification systems that meet energy, stability and economic requirements in large offshore grids. New information includes the effects of changing from point-to-point connections to grids with many nodes, and includes the effect of renewable power on the grid and the effect of battery energy storage / hybridization.
Technology Qualification for ADNOC Group Operations in the Arabian Gulf
Authors: El-Gharbawy Sherif , Beydoun Wafik
Published: April 2016

The Exploration and Production industry faces increasing challenges as a result of a volatile market outlook and declining short-term returns. The fluctuating demand for energy, when coupled with declining production from older reservoirs and stricter standards for sustainable operations, require more efficient recovery from existing assets. The Abu Dhabi National Oil Company (ADNOC) and our Group of Operating Companies (OPCOs) have focused attention on New Technology Development and Qualification, acknowledging that, in the coming years, innovation will be paramount to realizing our strategic production targets.

To qualify new technologies for deployment in field operations, we have historically relied on disparate processes in each of our operating companies. Alternatively, our operating companies have relied on their respective International Shareholder processes which had been developed and tested for environments that may be dissimilar to that of the Arabian Gulf. Our increasing reliance on innovation has called for the development of our own, bespoke standard processes for the maturity and qualification of new technologies. Key to the adoption of a new process was to communicate the benefits of centralization to, and obtain early buy-in from, our operating companies. Our approach to the design of the new process has been to accommodate the established practices of the operating companies and then to capture and integrate the best and most relevant elements of the International Shareholders' processes to our operating environment.

Our work has led to the development of the ADNOC Group standard process for the qualification of new technologies. The process uses NASA's Technology Readiness Level (TRL) tool as a backbone structure in its development. Strategically positioned Stage Gates with Key Performance Parameters are utilized to assess the maturity and inherent risk associated with each new technology as it is allowed to advance from one stage of development to the next with better performance. We are integrating the new process into our research and development project contracts with partner universities so as to positively influence the maturity of our new technologies and hence enhance the chance of success of our technology development efforts by bridging the gap between the stage gates. The standard process has been pilot tested throughout 2015, with full deployment targeted for Q2 2016.

The new technology qualification process benefits from the collective experiences of our operating companies, their International Shareholders and qualified service companies. The process was developed to be specific to the local environment and most responsive to the relevant technical challenges of each of our OPCOs. It allows only technologies with managed risk and improved performance to reach Operations.
Field Test for Real Time Monitoring of Piezoresistive Smart Cement to Verify the Cementing Operations
Authors: Vipulanandan C. , Ali M. , Basirat B. , Reddy A. , Amin N. , Mohammed A. , Dighe S. , Farzam H.
Published: April 2016

In this study, a field well was installed and cemented using the smart cement mixture with enhanced piezoresistive properties. The field well was designed, built, and used to demonstrate the concept of real time monitoring of the flow of drilling mud and smart cement and hardening of the cement in place. The well was installed in soft swelling clay soils to investigate the sensitivity of the smart oil well cement. A new method has been developed to measure the electrical resistivity of the materials using the two probe method. Using the new concept, it has been proven that the resistivity dominated the behavior of drilling fluid and smart cement. LCR meters (measures the inductance (L), capacitance (C) and resistance (R)) were used at 300 kHz frequency to measure the changes in resistance. The well instrumentation was outside the casing with 120 probes, 18 strain gages and 9 thermocouples. The strain gages and thermocouples were used to compare the sensitivity of these instruments to the two probe resistance measure in-situ in the cement. The electric probes used to measure the resistance were placed vertically at 15 levels and each level had eight horizontal probes.

Change in the resistance of hardening cement was continuously monitored since the installation of the field well for over 100 days. Also, a method to predict the changes in electrical resistance of the hardening cement outside the casing (Electrical Resistance Model - ERM) with time has been developed. The ERM predicted the changes in the electrical resistances of the hardening cement outside the cemented casing very well. In addition, the pressure testing showed the piezoresistive response of the hardened smart cement and a piezoresistive model has been developed to predict the pressure in the casing from the change in resistivity in the smart cement.
Reduction of Energy Consumption When Using a Grab for Deep-Sea Mining Operations
Authors: Kuiper Roel J. , Chen Xiuhan , Frumau Jan C. L. , Miedema Sape A.
Published: April 2016

Recent developments for deep-sea mining have shown multiple scenarios of gaining mineral deposits of Seafloor Massive Sulfides (SMS). One of the problems for these scenarios is the overall large energy consumption of processing rock material which are a technological challenge and are increasing production costs. This paper compares two methods for deep-sea rock excavation on their energy consumption, based on rudimentary calculations.

The best known scenario for gaining mineral deposits from the seabed is to excavate rock materials with a crown or drum cutter and pump the fluidized crushed materials to the vessel at the surface. This process requires high cutting forces deep-sea due to the hyperbaric effect at large water depths, when cutting with full cavitation. This high energy consuming process therefore requires a considerable amount of subsea installed power.

An alternative scenario is to use a hydraulic grab for excavating mineral deposits and not crush all the materials entirely subsea. Using a grab would be very beneficial in rough terrains and unstable seafloor conditions, compared to track-driven vehicles typically used for crown or drum cutters. Also specific cutting forces are much lower when using a grab, because it is not cutting at full cavitation in hyperbaric conditions. However the main advantage is to keep most of the rock intact which allows the material to be crushed at the surface. Mechanically uplifting large pieces of rock therefore could have the advantage that most of the required power can be installed at the surface, rather than subsea for the traditionally proposed hydraulic pumping systems. The rock can then be further crushed under atmospheric pressure at the surface, avoiding the hyperbaric effect. The combination of using a grab and further crushing at atmospheric conditions is more energy efficient and therefore requires substantially less installed subsea power.

Using rudimentary calculations, a great reduction of energy consumption is found for using a grab compared to typically used crown or drum cutters. Substantially less subsea installed power is required for excavating the mineral deposits with a grab. Although additional crushing needs to be done at the surface, the overall required installed power for using a grab still can be much less than fully subsea excavating and crushing.
Smart Production Monitoring & Management Information Systems
Authors: DeVries Stan
Published: April 2016

While oil and gas operations have used a variety of software systems, especially during the early years of "digital oilfield", very few produced sustainable "smart" work. This industry is arguably in a new wave of the digital oilfield, with a renewed focus on transformed work and the software systems which are necessary to enable this transformation. While perspectives vary, there appears to be a growing consensus that "smart" operation is essential, and it is sufficiently different from "reacting better" or installations of operations centers with insufficient transformation of work and collaboration.

This paper will present a perspective on "smart" operation, and the value and approach of systems which enable and sustain this change. One example of current implementation will be presented, along with perspectives on newer technologies such as Cloud and Internet of Things as they can be applied to oil & gas operations.
Introducing a new Recommended Practice for Fit for Purpose Well Abandonment
Authors: Buchmiller David , Jahre-Nilsen Per , Sætre Stian , Allen Eric
Published: April 2016

Globally, operators and regulators are pushing to ensure wells are abandoned successfully and securely. DNV GL is introducing a new, risk-based Recommended Practice (RP) for performing and qualifying well abandonments, entitled DNVGL-RP-E103 "Risk-based abandonment of offshore wells." The RP lays out a process to assess and control subsurface pressures and prevent the free flow of pore fluids between formations and to the seafloor. The ultimate objective of the RP is to protect the environment and ensure safety standards are upheld.

Most of the current regulations use prescriptive requirements for well abandonment design and the necessary plugging operations. As an alternative to the established ‘one-size-fits-all’ approaches, the DNV GL RP analyzes the abandonment requirements for each well and field using a quantitative method that takes account of sub-surface uncertainties. This approach is founded on best industry risk management techniques. Using these techniques, well-specific acceptance criteria for the environment and safety are established, setting the abandonment requirements for each well.

Up until now, offshore wells have been plugged generically and not according to well-specific requirements. Results from case studies have identified solutions ensuring long lasting integrity, robust well abandonment designs and tremendous cost savings potential by using fit for purpose abandonment methodology. Environmental protection and safety considerations are maintained when using the DNV GL RP, while saving operators considerable rig time and overall cost. Differing flow potentials in the reservoir and overburden formations have been studied quantitatively, leading to the development of the DNVGL-RP-E103. The fit for purpose method uses environmental mapping, quantitative risk calculations and well seepage models to evaluate each well and evaluate the suitability of the final abandonment design. By combining disciplinary expertise, the RP sets a new standard for well plug and abandonment (P&A).
Roll Performance of an LNGC with Partially-Filled Spherical Tanks
Authors: Zhao Wenhua , Efthymiou Mike , Wille Sjoerd , McPhail Finlay
Published: April 2016

Objective/Scope

Roll performance of an LNG carrier (LNGC) plays a critical role in side-by-side offloading. Liquid cargo motions can couple with the global motions of an LNGC, affecting the roll response and affecting the operational window for side-by-side offloading. In this study, a series of model tests has been conducted in a wave basin, and the roll characteristics of the LNGC are studied with liquid cargo in spherical tanks.

Methods/Procedures

Scale model tests were conducted with an LNG carrier-like model under waves in an artificial wave basin, whereby the model was positioned in the centre area of the wave basin through four horizontally arranged spring lines. The time series of the vessel motions and the internal liquid cargo motions were measured. To quantify the liquid cargo effect, several sets of tests were performed for which the tanks were empty, but the vessel properties modified to a ‘frozen’ approximation. Decay tests were conducted with the model oscillating freely in calm water, excitation by a given initial heel angle.

Results/Conclusions

Spectral analyses have been conducted to obtain the response amplitude operators (RAO) from the test results. Based on the obtained RAOs, short-term spectral analyses were conducted to understand the most probable maximum roll response in side-by-side offloading sea states. For the first time, the effects of cargo motion have been clarified for LNGCs with partially-filled spherical tanks. The findings reveal that the operational window may not be estimated robustly using a simplified method which ignores the liquid cargo and considers only the ballast condition. Based on the results in five different loading conditions, the most responsive loading condition is examined for spherical cargo tanks. It is suggested that intermediate load conditions with explicit inclusion of the effects of cargo motions to be utilised in side-by-side operability studies to robustly ascertain offloading availability. To facilitate potential numerical simulations, suggestions on selection of linear or nonlinear roll damping coefficients are provided as well. In conclusion, this study provides a better understanding of roll performance of an LNGC with liquid cargo motion in spherical tanks.

Novel information

The hydrodynamic performance of a ship with partially-filled spherical tanks has been clarified, for the first time. The findings in this study provide a foundation for improved numerical modelling with relevancy for side-by-side offloading operations, one of the key challenges associated with FLNG facilities.
Value Improving Practice (VIPs) for Optimization of a Marginal Oil Field Development in ONWJ Indonesia
Authors: Gani Arliansyah Abdul , Aryawan Wasis Dwi , Girindra Yuyung S.
Published: April 2016

An oil and gas company in West Java Indonesia operates an oil field located on the Offshore North West Java (ONWJ) block. For maintaining production rate for oil and gas, its marginal oil field will be developed in the near future in order to meet management policy for national oil and gas demand. However, global oil prices have fallen sharply over the past year, leading to significant revenue shortfalls in the company, and having it sharply cut investments in exploration and production. The current production concept used contribute surface facility cost is high and it is not comparable with the reserve to be developed. The approach will be applied for ONWJ marginal field development is to cluster some fields in an integrated and developed in a sequential manner utilizing floating structure to support production.

This paper describes the selection of floating structure technology using Analytical Hierarchy Process (AHP) method. This paper also presents an effective management tool Fuction Analysis System Technique (FAST) to be used as the rationale and integrated methodology for working through Value Improving Practices (VIPs) to improve fuction or cost floating structure system. Benefits of this approach are discussed including cost savings and future development flexibility.

The cluster and sequential development approach with the utilization of floating structure described in the paper provide management with alternatives to current operation concept for ONWJ marginal field development.
To Buckle or Not to Buckle - Best Practices for HP/HT Pipelines Lateral Buckling Design in Shallow Water
Authors: Hakim M. Abdel , Azouz A. , Awda H.
Published: April 2016

Mitigation of lateral buckling is one of the key design challenges for HP/HT subsea pipelines. Case studies of lateral buckling designs in shallow water developments are used to examine the merits and shortcomings of the different mitigation techniques. The case studies include both Greenfield and Brownfield developments as well as existing pipelines in operation. The assessment covers the design methodology, design challenges and methodology adopted to overcome those challenges as well as interaction with other pipeline design activities. Key factors such as technical feasibility, constructability and cost-effectiveness of the different mitigation techniques are considered.

The different lateral buckling mitigation techniques described are generally applicable to subsea pipelines in shallow water developments. The methods can be classified into two main approaches. The first is to prevent buckling and the second is to allow buckling to occur in a controlled manner. Hence, a key decision for the designer is whether to aim for buckle prevention or buckle control i.e. to buckle or not to buckle.

The assessment of the different techniques used for lateral buckling demonstrates that there is no ‘one size fits all’ solution. Unlike deep water applications where buckle prevention might be technically unfeasible or prohibitively expensive, the prevalence of shallow water in the Arabian Gulf region makes both buckle prevention and buckle control generally feasible and cost effective solution. However, each mitigation approach has its own pros and cons as well as limitations on its applicability and therefore the mitigation approach should be determined on a case by case basis based on comprehensive techno-economic assessment. Hence, understanding the merits and shortcomings of the different approaches is considered instrumental for proper selection of lateral buckling mitigation technique.

This paper provides guidance to the designer for the selection of mitigation approach through consolidation of the understanding of the merits and shortcomings of typical lateral buckling mitigation techniques in shallow water applications.
Chain-Soil Interaction in Carbonate Sand
Authors: Frankenmolen S. F. , White D. J. , O'Loughlin C. D.
Published: April 2016

The design of mooring anchors of Floating LNG systems on Australia's North West Shelf (NWS) is challenging due to the high mooring loads and the seabed which comprises carbonate soils. Anchors with an embedded padeye require engineering of the chain inverse catenary and management of interfaces between the anchor and mooring system design teams. While considerable investigation of the anchor line performance in clay has been conducted, there has been limited investigation into the anchor line behavior in sand, and none in carbonate sand. The limited relevant information in the codes and standards and public domain may therefore result in over-conservative design for the ground chain, the anchors and the overall mooring system.

In order to optimize the design of the mooring systems in relation to a developing Floating LNG project, a program of chain-soil interaction tests has been performed in a geotechnical centrifuge at the Centre of Offshore Foundation Systems in the University of Western Australia. The purpose of the testing was to provide data to allow better assessment of the shape and load distribution on the chain inverse catenary of a large mooring chain at high loads in carbonate sand. The testing achieved scaled loads equivalent to the 10,000 year return period storm experienced by an FLNG facility on the NWS, and included detailed profiling of the inverse catenary at different loading stages. The program spanned a range of chain sizes and soil densities as characterized by miniature cone penetrometer tests.

This paper outlines the design considerations for chain-soil interaction and provides guidance for interface management, which sets the centrifuge modelling program in context. The results of the centrifuge program are presented and interpreted against the backdrop of conventional design assumptions and existing theories for chain-soil interaction. Using the interpreted results, a new method for the analysis of chain-soil interaction in carbonate sands is proposed, which includes the use of cone tip resistance profiles. The method and input parameters are calibrated via the centrifuge test results. The insights gained have resulted in improved design assumptions for the conditions modelled, and further refinements of the analysis approach are foreshadowed. These outcomes have led to improved estimates of the inverse catenary configurations and mooring anchor loads, and future work is anticipated to allow more general improvements to design practice.
Technology for Extension of Lifetime
Authors: Kristiansen Karstein Berge
Published: April 2016

Looking at statistics for subsea producing wells in North America, Brazil and Norway the numbers indicate that approximately 50% of these wells were installed before 2005. Most of them rely completely on copper based communication i.e. no fiber optics installed, or at least not used. No Standard communication standard do not exist for neither topside nor subsea in systems installed before 2005 and communication throughput tends to be in the lower range of kilobit pr. second.

A large portion of existing wells are experiencing operational problems related to performance degradation in infrastructure and equipment, and are not capable of delivering communication interfaces for upgraded instrumentation and control requirements like multiphase meters, permanent reservoir monitoring and Subsea PowerGrids.

This paper looks into solutions for increasing communication throughput while simultaneously mitigating problems due to degeneration of copper cable umbilcals in a cost efficient way. Increased throughput is utilized as expanded connectivity, delivering new standardized communication interfaces both subsea and topside, and at the same time being backwards compatible for already installed subsea equipment.

The combination of being backwards compatible with the use of standardized communication interfaces gives extended lifetime for valuable communication infrastructure; umbilicals. Large benefits of the proposed solution are also achieved during upgrading of subsea installed equipment since not all subsea installed units must be upgraded at the same time as the topside-subsea communication link are upgraded.

To be able to supply enough electrical power to new subsea units on an existing umbilical already almost fully utilized a transformer based solution are described.

For umbilicals with very low IR (Insulation Resistance) values, a transformer setup for lifetime extension of the umbilical are also described.
Successful Sweeping Control Technology Test for Offshore Heavy Oilfield—Case Study of QHD32 Reservoir in Bohai Bay
Authors: Wu Xingcai , Chen Weiyu , Xiong Chunming , Huang Bo , Meng Hongqu , Wu Qinghui , Ma Chao , Xu Hanbing , Ye Yinzhu
Published: April 2016

Waterflooding offshore heavy oilfields features large injection-production well spacing and thick vertical oil layer. Besides, formation heterogeneity and oil-water viscosity difference exist commonly. All of the above cause injected water fingering, tonguing, and even channeling in deep reservoir, leading to low sweep efficiency, which seriously affects the technical and economical waterflooding effect.

A new set of sweep control technology (SCT) has been tested. The technology takes slug combination consisting of traditional highly viscous continuous-phase polymer gel and the new particle-type polymer dispersion with low viscosity. The particle diameter distributes from nanometer to sub-millimeter, which can be designed based on formation pore/throat sizes. The particle swells in water, but keeps no change in oil. The slug set can inhibit flowing of injected water in channels, and make injected water diverted in deep reservoir and directly access into medium-low permeability zones where more remaining oil exists, improving sweep efficiency.

QHD32 Filed has high porosity, 25~43%, high permeability, 500~18443mD, high gravity oil, with API gravity of 14.3~17.3, and effective pay thickness of 32.6m. The field started production in 2002, and up to 2012, the average oil rate per well was only 31m3/d, and oil recovery was only 5.74%, but the water cut is high, 85%. So far, totally 13 well patterns have been conducted with the sweep control technology in the field, with total injected agent amount of 102000m3. Results showed cumulative oil incremental of 100195m3, cumulative water production decrease of 185153m3, average daily oil rate per well increase of 20%, and input-output ratio of 1:10.9 under oil price of 100 USD/bbl as oil price. Even under current low oil price, 30 USD/bbl, it is still feasible economically, and the input-output ratio is 1:3.3.

Field test results show that the combined slug of highly viscous crosslinked polymer gel and new particle-type polymer dispersion can inhibit water channeling and enlarge sweeping volume. Even under low oil price, the technology has achieved success in technical and economic aspects, which provides a new IOR/EOR method for offshore waterflood heavy oil fields.
An Integrated Approach to Stampede Field Development, Deepwater Gulf of Mexico
Authors: Mohapatra Gopal , Nabasir Andry , Strauss Steve
Published: April 2016

Reservoir compartmentalization, stratigraphic complexity, and fluid contact uncertainty are the three key issues in the development of the Stampede field. We studied these issues in detail by integrating structural and stratigraphic interpretation and using state-of-the-art 3D dual coil seismic data, fault-seal analysis, pressure and fluid data from wells, core datasets, and logs. We used the products and knowledge from this integration effort to build the geological model. Key focus areas included: trap geometry, sealing capability of faults, environment of deposition (EOD), facies distribution, geochemical analysis of fluids, and oil-water contact (OWC) estimation. We built the geologic model honoring the data and observations to capture all the uncertainties and their ranges. We used this model for flow simulation resulting in a 10-well development plan, with six producers and four injectors for the base case.

In this paper we discuss some of the components of this multi-disciplinary effort toward the field development plan at Stampede, highlighting the challenges and solutions. The work helped us (a) incorporate fault-seal related compartmentalization into the simulation model, (b) properly represent facies types in the geological model, (c) better understand the compartments and associated OWCs, and (d) understand their impact on flow simulation and field development.
Thermal Design Approaches for Pipe-in-Pipe Tiebacks for the Transportation of HP/HT Oil and Gas
Authors: Paul Samuel , Sathananthan Ratnam , Legge Matthew
Published: April 2016

The purpose of a pipe-in-pipe flowline is to provide a highly insulated system to minimise the transfer of heat between the transported fluids and the surrounding ambient environment. The dry environment between the concentric pipes allows high performance dry insulation to be used, ultimately achieving a thermal performance greater than that which is possible with a simpler wet insulated flowline. For the exploitation of High Pressure / High Temperature (HP/HT) reservoirs, a pipe in pipe system can provide the necessary thermal insulation and the integrity for transporting hydrocarbons at high temperatures above 120°C – the current limit of conventional wet thermal insulation.

Compared to a wet insulated pipeline, the mechanical configuration of a pipe-in-pipe is inherently more complex and consists of several components (insulation, centralisers, water stops, field joints) which all have differing heat transfer properties. The magnitude of each component’s effect on the overall thermal performance must be understood during the design to avoid either under or over insulating the system potentially leading to operational problems and/or wasted expense. However, due to the relatively complex heat transfer processes at work, very accurate quantification of the effects is often cumbersome to calculate with little or no added meaning due to greater uncertainties in other parts of the design.

However, there are cases when the design comes together in a way such that a small change in insulation thickness may tip the design into requiring a larger sleeve pipe diameter to accommodate the extra thickness. As pipes are most economically purchased in standard diameters (8, 10, 12 inch, etc.) the jump from a 14 inch to a 16 inch sleeve pipe for example not only adds significant material cost, but may have huge implications to the installability of the pipeline.

Hence before making the jump to a larger pipe diameter, it makes sense to first evaluate the basis for the required thermal performance (e.g. the criticality, operational and flow assurance impacts of a marginally reduced thermal performance), and also the calculation methodology – often conservative simplifications are included early on in the design when the fabrication and installation implications are not fully evaluated or understood.

This article aims to provide an overview of the current thermal design approaches for pipe-in-pipe systems, and to highlight the choices available to the engineering team and the areas with scope for optimisation. The relative magnitude of the various resistances to heat transfer will be quantified, with focus on the most relevant aspects of the heat transfer with respect to pipe-in-pipes.

While this paper does not address active heating, the improvements to the passive insulation discussed would directly affect the power requirements of actively heated systems.
Strategies to Monitor and Mitigate Asphaltene Issues in the Production System of a Gulf of Mexico Deepwater Subsea Development
Authors: Gonzalez Doris , Gonzalez Fabio , Pietrobon Marney , Haghshenas Mehdi , Shurn Megan , Mees Amber , Stewart Carlos , Ogugbue Chinenye , Duvivier Giles
Published: April 2016

An asphaltene threat has been identified in production wells located in a Gulf of Mexico (GOM) deepwater field. After production started from different reservoirs and the operating conditions for some of the wells reached the asphaltene precipitation onset, solid deposits were detected at different points in the production system, which caused production deferrals, disturbed the operating strategy of the field, and increased the operational expenditure. To remediate asphaltene deposition in deepwater subsea wells, a rig-less remediation costs up to $0.12 million (MM); a well intervention that requires a rig costs approximately $20 MM, and a vessel-based pumping remediation costs about $5 MM. These costs do not include the impact of production deferrals.

A plan was developed to acquire and interpret the required information to properly understand and manage the asphaltene threat. The methodology includes: Acquisition of suitable downhole reservoir fluid samples for asphaltene and wax studiesCharacterization of the reservoir fluids in the laboratory using the latest asphaltene and wax technologies.Observation of the effect of chemicals on solids builds up during field trialsSurveillance of damage near wellbore using Pressure Transient Analysis (PTA) and Multi-Rate Test (MRT)Real time monitoring of normalized nodal analysis based on frictional pressure losses.

During the characterization of the reservoir fluids, asphaltenes were identified as key risk factor for successful field development. The laboratory tests showed the propensity for solids formation and confirmed that the variety of reservoir fluids had an asphaltene deposition envelope that extended from the reservoir rock to the topsides facilities. Solids collected from pigging returns, surface equipment, and failed downhole equipment confirmed the reservoir fluid's asphaltene deposition tendency. In some cases, field trials showed that increasing the concentration of asphaltene inhibitor injection resulted in increased build-up of organic deposits. PTA and MRT enable the identification of flow restrictions from the reservoir to the permanent downhole gauge location and real-time monitoring of normalized nodal analysis help to identify where the impediment to flow is located in the production system.

This paper presents an integrated approach to evaluate the key elements of asphaltene risk for deepwater projects, the strategy to manage the issues during production implementation, and lay out the aspects to be considered in the mitigation of the negative impact of asphaltene thread in the field development plan.
Practical Applications of Structural Analysis Support to Decommissioning
Authors: Abdelaah Ahmed M A , Cresswell S M , Manzocchi G M E , Thistlethwaite C
Published: April 2016

This paper will illustrate some of the challenges facing decommissioning in the harsh environment of the North Sea and the latest efforts spent on analytical and practical fronts to achieve a safe and efficient removal of some of the biggest North Sea structures. The need for efficiency has never been greater, with current low oil prices potentially bringing forward the decommissioning of assets that are no longer cost effective to operate.

The authors have considerable experience providing analytical support to the planning and safe decommissioning of major North Sea structures using commercial structural analysis tools and methods developed in-house. This paper describes several practical examples of the use of applied structural analysis to support the decommissioning of concrete and steel offshore platforms. Examples include: analysis support for the piecewise removal of a steel jacket structure; structural assessment of transportation of a complete topside incorporating a novel approach to define simultaneous peak response combinations; and finite element modelling methods to manage end of life production for a concrete platform prior to decommissioning and the long term degradation of concrete under reduced draw down post decommissioning.

The experience of supporting the removal of a major platform has demonstrated the importance of using a live model for real-time decision making. For the single lift removal of a heavy topsides, the statistical approach to extreme member force combinations for code checking provides efficient and safe guidance for assessment and minimizing costly strengthening. Long term analysis under decommissioned loading conditions of concrete platforms can provide sufficient confidence in long-term platform integrity in a derogated state.

The real-time analysis support is a first of its kind for a major North Sea jacket removal allowing rapid decision support to the removal operation. The random seas analysis approach is a novel and efficient change to the standard transportation design-level approach and is appropriate for a structure destined for scrap. Collaborative research with academic institutions provided the basis for industry leading probabilistic long-term degradation of large concrete structures in extreme environments.