bluuebunny/crossref_metadata_2025 huggingface dataset:
Thermo Chemical In-Situ Heat Generation Technique to Remove Organic Solid Deposition: Effective Tool for Production Enhancement and Flow Assurance
Authors: Singh K. , Saidu Mohamed A. , Alian S. Sheykh , Ismail M. , Anwar M. , Mohamad W. Wan , Ghani S. Abdul
Published: May 2013

Most of the fields in Malaysia have been producing for more than 20 years. At this advanced stage of depletion, reservoir natural driving forces are low. Organic depositions (mainly wax and asphaltenes), particularly in the near-and-around well bore region and in production tubing, can further reduce the production by restricting the flow from reservoir to wellhead. Such deposits also have the tendency to change rock wettability from water wet to oil wet. A study to address this issue with a view to rejuvenate these wells was conducted through laboratory analysis and pilot field implementation. A unique thermo-chemical system was developed as an effective tool for:Removing organic deposits near-and-around wellbore and production tubing, henceEnhancing production from the treated wells.

The chemical system consists of two components/pills which are injected simultaneously into the well through production tubing. Upon mixing, the pills will produce heat and reaction products. The heat generated is capable to melt /dislodge the organic deposits, while, the solvent and reaction product (ester) will further dissolve and disperse the deposits. The thermo-chemical also behaves as an excellent demulsifier and corrosion inhibitor based on the recommended dosage. Compatibility studies showed that the chemical is compatible with formation rock, reservoir fluids, well completion accessories and refin-ery products. When the chemical system is injected into the targeted location (i.e. well, pipeline, heat exchangers and etc.), the resultant pill will generate in-situ heat of up to 200ºC and produce ester. Combining the effect of thermal energy and chemical solvency has proven to be highly effective in dissolving, dispersing, dislodging and removing the organic solid de-posits. This technology has been applied in 23 wells in Malaysia, 2 wells in Brunei and 1 pipeline in India. From the two (2) case studies, average production increased to more than 100% and cost saving of up to USD 100, 000/well was realized since mechanical wax removal was not required after the thermo-chemical treatment.
Innovative Geophysical Logging Techniques Used for the Definition and Characterization of Mass Erosion Sediments
Authors: Thomas Stephen , Digby Adrian John
Published: May 2013

In areas dominated by mass transport and mass deposition of sediments the potential risk to seabed installations of re-occurrence is widely recognized and must be fully evaluated. These sediments are often complex however and the risks are difficult to evaluate unless a fully integrated investigation is carried out. An integrated investigation is likely to include high resolution seismic, geotechnical, sedimentalogical, biostratigraphic, chronostratigraphic and high-resolution wireline geophysical data. The frequency and size of mass transport deposits is key to any risk assessment and this paper presents analysis of gamma CPT cone data used for the first time within a mass transport complex. The addition of the natural gamma was proposed in this investigation because of the complexity of the site and to enable direct correlation between CPT data and borehole data where continuous high resolution natural gamma logs were also run.

This paper looks at the innovative use in deep water of these geophysical measurements on the sea-bed and borehole CPTs and the study was based primarily on comparison with and interpretation of 3D seismic, 20m surface piston cores, 40m surface cone penetration tests (CPT) with natural gamma (gamma cone), one 192m borehole with downhole CPT and second borehole at the same location with discontinuous push samples, with associated onshore laboratory testing. Both boreholes had high-resolution wireline geophysical data.

The determination of the size and frequency of the mass transport deposits required the careful integration of the various data sets within the regional stratigraphic framework provided by the interpretation of the seismic data, combined with the lithological interpretation of the continuous wireline geophysical data. The 3D depositional model for the area resulted in better understanding of the occurrence and type of mass transport processes through time. This in turn led to more reliable frequency data for input into a quantitative risk assessment of mass transport deposits to the future development.
Importance of Pressure Management in CO2 Storage
Authors: Simmenes Trine , Hansen Olav R. , Eiken Ola , Teige Gunn Mari Grimsmo , Hermanrud Christian , Johansen Stian , Nordgaard Bolaas Hege Marit , Hansen Hilde
Published: May 2013

CO2 injection implies displacement of water, and thus aquifer pressure build-up or displacement of water to other rocks. Both may be problematic. Pressure build-up may result in seal failure and / or restrict injection rates, whereas displacement of brine to other rocks may have undesired effects on the environment, such as contamination of potable drinking water. CO2 storage capacity also depends on pressure management, especially in closed systems where displaced water cannot be adequately displaced in the subsurface or vented to the surface.

Fluid pressure management at individual storage sites will be planned based on theoretical considerations as well as practical experience. The theoretical work includes analyses of widely different subjects such as stress tensor analyses, fracture propagation dynamics, reservoir connectivity and 3D permeability distributions. Practical experience will come from a growing number of injection sites, of which the experiences from the ongoing Snøhvit CO2 injection project are currently the most important.

Statoil has injected CO2 at Snøhvit since 2008. Injection took place in the Tubåen formation which underlies the Stø Formation natural gas reservoir. Fracturing of the caprock from the CO2 injection could thus result in CO2 leakage to the overlying producing reservoir. The CO2 injection resulted in an initial well pressure increase, probably caused by precipitation of salt in the near wellbore area. This challenge was resolved by injection of methylethylenglycol (MEG). Continuous downhole pressure measurements nevertheless documented a continuous pressure increase, albeit at a lower rate. This pressure increase was interpreted as evidence of insufficient far-field permeability to displace formation water laterally rather than of storage space shortage.
Hydrate Prevention in Subsea Oil Production Dead-Legs
Authors: Cai Jing Jing , Abedinzadegan Abdi Majid , Hawboldt Kelly , Sundgaard Candice , Haghighi Mohammad
Published: May 2013

A study was conducted to better understand the hydraulic and thermal behaviour of dead-legs within a stacked spool arrangement designed to produce two well streams from a single manifold. The study included scenarios under different rigid spool orientations and active line flow conditions. The ultimate goal of the study was to optimize inhibitor injection procedures with respect to loss of inhibitor and contamination of the production fluids.

A Computational Fluid Dynamics (CFD) technique was employed to simulate the flow and thermal conditions within the flow lines and dead-legs. The results of the simulations were validated with two sets of experiments and in two different scales (sizes). The findings of the study suggest that the thermal and/or hydraulic status of the dead-legs during long shut-in periods pose little risk of hydrate formation.

Introduction

A dead-leg is defined as an inactive portion of the pipe where the flow is stagnant or has very low velocity. This inactive pipe is normally connected to an active pipe that carries the main flowing stream. Due to the low or stagnant flow created in dead-legs, there is a risk of cool-down and hydrate formation. The stagnant conditions within the dead-legs could also promote corrosion.

The formation of hydrates is a well known phenomenon in the oil and gas production and processing systems. Hydrates can form under low temperature and high pressure when water is present in contact with gaseous or live crude oil and light liquid hydrocarbons. The fluids present in the well-stream contain a certain amount of gas which is saturated with vaporized water. Free produced or condensed water can collect in the low-points of the pipeline including pipe segments within dead-legs. Hydrates can be formed as a solid block when the line is left inactive and can potentially plug the pipeline.

When hydrate formation happens, the hydrate plug in the pipeline may be either removed by depressurization or injection of inhibitor. By depressurizing one or even two sides of the plug, the hydrate plug starts to melt and can potentially move with high velocity, which could cause severe damage to subsea components. The formation of hydrates in the rigid spools connecting the subsea trees to the main subsea production manifolds could result in complex consequences. The manifold-subsea tree interconnecting spool is connected to the manifold from one side and can be relatively easily depressurized; however the tree side of the spool cannot be depressurized readily and may require costly subsea intervention and an extended loss of production. Addition of hydrate inhibitor will reduce the melting temperature and reduce the thermodynamic potential for hydrate formation. Flushing dead-legs with inhibitors such as methanol can protect them from hydrate formation during shut-in periods.
Control of the Integrity of Swaged Weld on Insulated Pipe-in-Pipe
Authors: Mallik Ajit , ATIN Cesar , Wang Jue , Deleye Xavier , Legras Jean-Luc
Published: May 2013

In typical insulated Pipe-in-pipe (PIP) systems, both extremities of the outer jacket pipe are swaged down close to the inner pipe and are welded directly to the outer surface of the inner pipe. This full penetration weld (hereafter called swaged weld) works as a structure connection between the inner and outer pipes and seals the annulus between the two pipes. The integrity of this swaged weld ensures the structure integrity of whole PIP as well as its thermal properties.

The non standard geometry of this swaged weld presents a real challenge for its Non Destructive Examination (NDE). Despite of its long existence and its importance, the inspection of this swaged weld has always been performed by Manual Ultrasonic Testing (MUT) or Semi Automated Ultrasonic Testing.

This paper presents an Automated Ultrasonic Testing (AUT) system recently developed to inspect this type of weld more efficiently and more completely. The principle of this system and its Det Norske Veritas (DNV) qualified performance in term of defect detection capability and sizing accuracy will be described.

To enhance the integrity of the inspected welds, fitness-for-purpose acceptance criteria have to be developed for this AUT system. Due to the range in weld geometry, the analytic approach conventionally employed for girth welds is no longer applicable. A Finite Element Analysis (FEA) based on Engineering Critical Assessment (ECA) approach has to be applied and this approach will be presented.

In a recent West African SURF project, this AUT system coupled with fitness-for-purpose acceptance criteria has been applied with success.

1. Introduction

Developments of the high temperature high pressure (HTHP) field bring on stage more strict requirements on thermal insulation of the pipelines. Conventional wet thermal insulation such as 5-layer polypropylene foam (5LPP foam) or 5-layer syntactic polypropylene (5L syntactic PP) turns out to be limited both in terms of the insulation efficiency (U value over 1.5W/ m2.K or 0,264BTU/hr.ft2.°F) and the maximum service temperature (approximately 130°C or 166°F). The Pipe-in-pipe (PIP) system presents a good alternative where conventional wet thermal insulation is not applicable. A typical PIP system can provide U value down to 0.5W/ m2.K or 0.09BTU/hr.ft2.°F, which extends the cooling down time of the pipelines and reduces the risk of hydrate formation and waxing during shutdowns and start ups.

PIP systems were introduced to the fields inWest Africa more than a decade ago. The first typical PIP system was installed in Tchibeli field; one PIP production line, with a length of 25km, was installed in 1999. More recently such system was installed in several other fields such as Bonga and Kizomba Satellite.
Contractors: A Help or Hindrance to Your SEMS Program
Authors: Carmichael, MS, CSP Pisces
Published: May 2013

Application

The new regulatory era for offshore oil and gas exploration and production in the United States Outer Continental Shelf (OCS) is still evolving and requires operators to take a hard internal assessment of how they stand against current US regulations like Title 30 Code of Federal Regulations (CFR) 250, Subpart S- Safety and Environmental Management System (SEMS).

Results, Observations, and Conclusions

The SEMS regulation has created a combination of interest, anxiety, and uncertainty within the upstream industry. Recent BSEE district investigation data shows that contractors are an important factor in incident records. Clever offshore contract organizations have taken a proactive approach to establish their own comprehensive SEMS-like program before (or in case) it becomes specifically required of them by the BSEE. This approach will help ensure proper planning into future projects, costs, and contract resources.

Significance of subject matter

For those interested in the contractor SEMS impact, the primary learning objectives and outcomes of this paper include:Review contractor-specific SEMS elements and requirementsUnderstand four important SEMS contractor takeawaysOperators must conduct initial SEMS program audits by November 2013 and then every 3 years thereafter.Operators must conduct and document contractor selection processes, safety evaluations, and verify contractor personnel knowledge and skills in advance of performing work.BSEE will take SEMS enforcement action against contractors not meeting expectations.Within 30 days of the audit close, operators must send BSEE a detailed corrective action plan (CAP) that identifies each responsible person by name and job title.Review BSEE district investigation report data findingsGain knowledge of existing contractor management guidance, ideas, and resources

Description of the material

This paper provides operators with the necessary information to understand the minimum SEMS contractor expectations to ensure their contractors are a help and not a hindrance to their regulatory compliant and effective operator SEMS program and audit.
Buoyant Tower: Concept Selection - An Economic and Technical Evaluation
Authors: Spies Richard , Ortega Cesar , Ledgard Durkin
Published: May 2013

Based on a review of the BPZ CX-15 project, this paper outlines the business opportunities and challenges in delivering offshore oil and gas developments in Peru. Aging existing infrastructure and the need to create local capabilities combine with highly economic reserves of oil and gas to provide opportunities to enhance the Peruvian economy.

The development of new offshore fields in remote locations, such as Peru, where there are limited assets available to economically adopt conventional methods requires the use of innovative approaches to enable such projects to proceed. With design challenges driven by extreme seismic loading criteria, with local fabrication capabilities available but limited and with very limited locally available marine assets to perform drilling and construction operations there are considerable challenges to be overcome.

The paper details the economic and technical evaluation performed to demonstrate the benefits of the world's first application of buoyant tower technology. It also reviews the decision making process adopted in the evaluation of the different development solutions assessed including economic, schedule and other risk factors. This demonstrates that the adoption of such technology for offshore field developments in remote locations will enable more such developments to occur than would otherwise be the case using conventional solutions.

Introduction

About BPZ Energy. BPZ Energy, the operator that commissioned the CX-15 platform, is a small exploration and production company, with average production in 2012 of approximately 3,500 BOPD. BPZ Energy itself has limited resources but has a capable, if small, technical staff. Company operations have included over 100 oil field personnel and marine personnel to support operations in Block Z-1. Due to the limited marine support services available in this area, when operations ramped up to support first production, the company elected to form its own marine service operation, mainly by supplying and operating tank barges used as floating oil storage and conventional deck barges used as tender support for platform drilling operations or as crane barges with limited heavy lift capacity.

Financial resources of the company were tested by the CX-15 project, but the project was ultimately completed with bank financing as well as the sale of part of the Block Z-1, including the CX-15 project, to a 49% partner that entered the project when the CX-15 project was well underway.
Service Life and the Definition of Failure of Coatings and Cathodic Protection
Authors: Gibbs Brian , Graf Thomas
Published: May 2013

When corrosion protection systems fail to function correctly, all too often, the finger-of-blame is pointed at the technology used for corrosion protection as being the root cause. In reality, the failure is almost always in a management system that either is not correctly applied or is overlooked, and the physical breakdown is only the manifestation of the error. At the outset of a project, it is essential that clear expectations are established and agreed by all the stake holders. These expectations must consider both the capital project and operating phases of the intended facility, and a balance must be achieved between minimizing project time and cost and optimizing maintenance budgets and down time. Using risk analysis methods, these expectations should be transformed into performance standards and project specifications that are well understood by all involved parties, including those responsible for design, procurement, manufacture, construction, commissioning, operations, and maintenance. This presentation will highlight the important considerations and discussions that must take place before the corrosion protection system is designed. This must start with defining the expectations, which then leads into establishing the systems and controls that are needed to deliver the expectation. The focus of this presentation is creating the corrosion management systems that are need to be in place to achieve safe- and cost-effective service, and weighs the balance between CAPEX and OPEX constraints.
Buoyant Tower Design Innovation: Applying Deepwater Technology to Shallow Water Challeges
Authors: Hegler Russell , Finn Lyle
Published: May 2013

This paper presents a discussion of a new buoyant tower design for developing fields in mid-water depths (50 m to 250 m). A tower using this design was installed offshore Peru in the fall of 2012. This new buoyant tower design applied a number of deepwater technologies to shallow water. These technologies include the cellular construction of the hull, a suction pile like foundation, float-over deck installation, air over water ballast system, fixed ballast at the bottom, and unconditionally stable design approach.

Introduction

The buoyant tower concept is not a new idea for the oil business. A number of bottom founded structures held upright by buoyancy were installed in the North Sea years ago. The Brent flare tower and the Beryl articulated loading tower are two examples. All of these early buoyant towers used a mechanical pivot at the base. Some of them used a truss structure to connect the upper buoyancy modules to the base pivot. However, the offshore structure recently installed offshore Peru is the first buoyant tower to be used for drilling and producing operations.

The tower offshore Peru is also different from its predecessors in that the mechanical pivot was replaced with a suction can foundation (SCF). This foundation element performs the same functions as the mechanical pivot in that it allows the tower to rotate about the base in a compliant manner while restraining the base from moving vertically, laterally, and torsionally.

The idea of using a can in the soil to form a pivot also is not new. The test guyed tower installed in the Gulf of Mexico (GOM) in 1975 was supported at the base by a spud can. This spud can effectively formed a pivot in the soil allowing the tower to remain compliant to the wave forces. This tower experienced numerous winter storms during its four year stay offshore with no detectable vertical, lateral, or torsional movement.
Improving Durability of ROV Tether Cables by UHMWPE Fiber
Authors: Eijssen Marc , Gabrielsen Andreas
Published: May 2013

This paper describes the durability enhancement of Nexans' conventional ROV tether cable design by using a strength member made with a bending optimized Ultra-High Molecular Weight PolyEthylene (UHMWPE; also refered to as HMPE) fiber, manufactured by DSM Dyneema and branded as Dyneema®, and herewith creating opportunities for more costeffective ROV operations and more flexibility in the design of ROV tether cables. The improved ROV tether cable is manufactured by Nexans and branded as ENABLE®. As a physical connection between a Remote Operating Vehicle (ROV) and its tether management system (TMS), ROV tether cables are exposed to small bending diameters and relatively sharp directional changes in the TMS. During ROV operations the cables are exposed to axial loading, severe multiple bending in arbitrary planes and hydrostatic pressure. The internal friction caused by motions and hydrostatic pressure induces mechanical deterioration of the strength member in ROV tether cables, hence a loss of functionality and regular re-termination and cut-backs of the ROV tether cable. In conventional tether cable designs aramid fibers are commonly applied in contra-helically stranded layers around an electro-optical core. After a while in operation internal abrasion, misalignment and compressive failure of these fibers, especially at the section of the tether cable closest to the ROV, become apparent. Based on its physical characteristics, UHMWPE fiber holds promise to overcome these failure modes.
Summarizing the Deepwater Horizon/Macondo Reports
Authors: Sutton Ian S
Published: May 2013

Whenever there is a serious incident, such as the Deepwater Horizon/Macondo explosion and oil spill it is normal for one or more authoritative bodies to write an in-depth report. Such reports are generally very thorough and are prepared by people of high credibility and professionalism within the industry or from related industries. Typically these reports describe:What happened: the sequence of actions and non-actions that led up to the event, followed by an assessment of the effectiveness of the emergency response systems.How the Safety Management Systems, both technical and managerial, failed to prevent the event from occurring and/or failed to mitigate the event once it was under way; andRecommendations to prevent further incidents of this type from occurring. These recommendations cover changes to regulations, developments in management systems and improvements in technology.

Finally, the reports may, on occasion, suggest a new paradigm for for managing safety in the industry covered. Examples of such paradigm shifts occurred in the 1990 (the Cullen report and Piper Alpha) and in 2007 (the Baker report and the Texas City explosion).

Of the many reports written to do with the Deepwater Horizon/Macondo (DWH) event of April 2010, four have been selected for review in this paper. In chronological order they are:National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling. Report to the President. January 2011.BOEMRE (Bureau of Ocean Energy Management, Regulation and Enforcement). Report Regarding the Cause of the April 20, 2010 Macondo Well Blowout. September 14, 2011.Transportation Research Board. Special Report 309: Evaluating the Effectiveness of Offshore Safety and Environmental Management Systems. 2012.SPE (Society of Petroleum Engineers). Summit Paper. The Human Factor, Process Safety and Culture. Eds. Patrick Hudson and John L. Thorogood. November 2012.

The third and fourth reports did not address the Deepwater Horizon event in detail. However both of them were profoundly influenced by the need to respond to this catastrophic event and provide guidance as to actions that can be taken to improve the culture of the offshore oil and gas industry.

Figure 1 shows a binder that contains a print-out of the four documents (along with copies of SEMS and the proposed SEMS II). They are printed single-sided on standard paper. The binder is 5 inches thick and weighs approximately 10 pounds, thus illustrating the scope of such reports, and the challenge that the offshore community faces in reading them and understanding their findings and recommendations.
In-Situ Requalification of Pressure Tubes: A New and Efficient Methodology
Authors: Harding Alan , Lawrence Lee , Irani Roy S. , Dickens Mark
Published: May 2013

This presentation focuses on a novel, newly published Standard, which will ensure off-shore companies operate safely and efficiently. British Standards Institute, has recently developed a unique standard BS 8562, allowing retesting ‘Pressure Receptacles’, without disassembly, from their operation. Vessels tested using this approach, often called ‘Jumbo Tubes’, are sometimes impossible to access fully after installation, on off-shore platforms, within semi-submersible drilling rigs/submarines hulls/buildings etc. Because of these adverse locations where the examination/ inspections are conducted, a critical part of the re-qualification requires the site's pre-testing assessment, to identify potential hazards, which need to be considered during the actual test programme. A 'Competent Person', whose qualifications are strictly defined and who must demonstrate know-how and judgement skills, at all times, undertakes the testing. The standard's title, " Gas cylinders. In situ, non-destructive examination and testing of refillable seamless steel tubes of water capacity between 150 and 3000 L, used for compressed gases??, speaks for itself.

Recently published, this standard has been successfully deployed in several harsh/inaccessible locations. An external visual inspection of all accessible surfaces is mandatory, whilst classical techniques such as corrosion mapping, magnetic particle/dye penetrant inspection, even hydraulic testing (where feasible and believed necessary) etc. may be performed. However, focus is on modern techniques:- ultrasonic examination (thickness surveys/flaw detection), eddy current testing, and possibly the most useful method of all, acoustic emission testing. Work has commenced to deploy this standard globally as EN/ISO standards. The use of non-destructive techniques has saved, on average, about 20% of the cost that would have been incurred, compared to conventional test methods, whilst also avoiding an immeasurable amount of operational disruption. For completed international Naval (submarine) applications the savings have amounted to over 60%!

4. A unique route of re-qualifying pressure receptacles, which otherwise would remain in a state of uncertain safety, has been developed. Actual savings apart, this approach is very 'green' too: none of the vessels are transported, whilst testing is during an actual filling operation. Additionally, the standard is invaluable to operations where the downtime involved would hinder either the installation's safe operation or its service.
Field Development Overview of Liuhua 11-1 and Liuhua 4-1 Oil Field
Authors: Zuan Yue , Yiyong Liu , Jianjun Yang , Jiayou Mao
Published: May 2013

The Liuhua 11–1 oil field, to date, the largest oil field in the South China Sea, is located in approximately 310 meter of water. It was the first deepwater field in the South China Sea originally developed by a consortium of Amoco, CNOOC and Kerr-McGee in 1995. The development includes a Floating Production System (FPS) with a subsea production system, and a Floating Production Storage Offloading (FPSO) located approximately 3km northwest of the FPS. The development of a nearby field, the Liuhua 4–1, about 11km away from Liuhua 11–1, was approved in early 2010 and produced in 2012 through the Liuhua 11–1 FPS facilities via subsea tieback, which requires to FPS life extension and topsides capacities upgrading for another 15 years. There are significant technical challenges for the life extension and dry dock upgrade of the FPS, as well as the subsea tie-back of the Liuhua 4–1 field. The FPS mooring and subsea control risers need to be disconnected and reconnected after the FPS drydock. The new 11km subsea pipeline between two oil fileds, control umbilical and electrical cable risers need to be installed. The FPS upgrade project started in 2010 and completed successfully in 2012 with the reconnection of the mooring and risers to the FPS. Both the Liuhua 11–1 and the Liuhua 4–1 fields are currently producing. This paper gives an overview of the Liuhua11–1 and Li uhua4–1 development as a case study for South China Sea deepwater development and also discusses the technology and project execution for developing nearby marginal fields.

Introduction

Liuhua 11–1 Oil Field is the deepest oil field on production in China to date, located in South China Sea, started first oil production on March 1996. She was called a " crown jewels" in offshore oil industry with a series of technical innovation at that time, and she is still on production after 17 years service. Liuhua 4-1, as a marginal oil field, was developed via tie back to the Liuhua 11–1 Oil Field, raised new requirement on the existing offshore facilities. China National Offshore Oil Corporation (CNOOC) faced serious challenges on facilities upgrade, FPS disconnection, re-hookup, and technicalogy and project management. The Semi-Submersible Platform FPS Nan " Hai Tiao Zhan" was disconnected on Oct. 2011, went to Dry Dock upgrading, re-hookup on location on May 2012. Liuhua 11–1 production resumed on June and Liuhua 4–1 started the First Oil on July and all 8 wells were on production in Sept. 2012.
High Strength Carbon Steel and CRA Lined Pipe for Reel-lay Installation
Authors: Toguyeni Gregory Alexandre , Pepe Nuno , Barritte Graeme , Banse Joachim , Schmidt Tanja , Jones Richard Lloyd , Mair John A
Published: May 2013

There is increasing demand for pipeline installation, including SCRs, in deeper water, coupled with a requirement for higher operating pressures and temperatures and the need to transport corrosive constituents. For such applications, the use of high strength steel, Grade X80, offers significant benefits including a reduction in pipeline weight and savings in material and fabrication costs. Furthermore the reduction in linepipe weight reduces buoyancy module requirements and facilitates installation by existing pipelay vessels which would otherwise require increased top tension capability if lower strength pipe was used.

Reel-lay offers a cost effective offshore installation method for high strength steel pipe. Hitherto reel-lay installation has been limited to Grade X65/70 strength pipe. Subsea 7, in collaboration with Vallourec and Mannesman Tubes, (refer to hereafter as V&M Tubes) has performed a qualification programme for reelable X80 linepipe. V&M Tubes manufactured seamless X80 pipe of 323.9mm OD × 18mm WT pipe in accordance with DNV OS-F101, supplementary P requirements. Subsea 7 developed and qualified a mechanised girth weld procedure based on the GMAW-CMT/PGMAW welding process. Procedure qualification was successfully performed in compliance with DNV OS-F101, including mechanical, fracture toughness and sour service testing.

In order to address the need to transport more corrosive constituents, Butting manufactured Alloy 625 and 316L mechanically lined or BuBi® pipe(323.9 x17.5+3.0mm) using the X80 pipe supplied by V&M Tubes. Subsea 7 developed a novel girth welding procedure utilising internal welding of the CRA lining and external welding using conventional C-Mn filler wire. The latter facilitated the achievement of overmatching weld metal strength which is necessary for reeled pipe. Girth weld procedure qualification was successfully performed in accordance with DNV OS-F101 including a full scale bending trial.

The development of linepipe material and welding solutions for reelable high strength carbon steel and CRA lined pipe are considered to be key enabling technologies for the exploitation of deep water oil and gas reserves in the future.
Geophysical Pore Pressure Prediction in Complex Geologic Environments, Offshore Libya
Authors: Huffman Alan R.
Published: May 2013

In recent years, methods have been developed to enable robust pressure prediction in the presence of multiple pressure mechanisms including undercompaction, unloading processes (secondary pressure mechanisms) and at great depth, the onset of secondary chemical compaction. These models utilize geological and geophysical information to constrain the calibration models and the depths at which they must be applied to develop a multi-layer pressure calibration model that will accurately predict pressures for prospect-level analysis and pre-drill prediction. These models are then integrated with the velocity field and the geological and geophysical information to predict pore pressures and fracture pressures at greater depths than have been previously feasible. This methodology has been tested in multiple basins and has been proven to be effective in helping drilling engineers improve well performance through more effective mud and casing program designs that significantly reduces well costs and rig time.

Recent application of elastic and acoustic inversion in complex carbonate environments have also proven effective in predicting pressures in environments where the shales can be separated from the carbonates. The approach requires that the inverted data be separated into the shale and carbonate velocity trends to allow the shales to be used for effective stress prediction while the complete velocity field is used for time-depth conversion. These studies have revealed that pore pressure prediction from mixed lithology (carbonate and shale) environments is feasible using advanced inversion methods. Successful pressure prediction in this type of geology requires seismic data that is of sufficient quality to enable a robust acoustic and/or elastic inversion to be performed that can separate the shale velocities for effective stress calculation, and perform time-depth conversion from the complete velocity field. As the amount of shale present in the geologic section becomes smaller, the ability to predict pressures decreases. The presence of marls also presents a problem because the carbonate material within the shale suppresses the sensitivity of the shale velocity to pore pressure.
Closed-Loop Drilling, Cementing, and Frequent Dynamic Formation Integrity Testing
Authors: Hannegan Don M
Published: May 2013

" State of the art" is defined as the highest level of development, as of a particular device, technique or scientific field, achieved at a particular time. There are a number of examples in today's drilling industry that meet these criteria within their respective category. However, today's emphasis on well control, isolating potential flow zones during deepwater well construction & abandonments and growing need to safely drill otherwise un-drillable prospects to increase recoverable reserves are unquestionably topics of great significance to the industry, regulatory community and public at large. This presentation speaks to ‘state of the art’ drilling technologies in respect to the circulating fluids systems used for drilling and isolating potential flow zones during well construction and plug & abandonments (P&A) on challenging deepwater drilling programs.

Closed-Loop Drilling on deepwater rigs is enabled by a rotating control device (RCD) configured above or below the riser tension ring and a dedicated PLC automated choke system for mitigating drilling hazards such as narrow, shifting, or relatively unknown drilling margins, loss circulation, and kick-loss scenarios for the purposes of achieving deeper open hole sections with less non-productive time (NPT) and safely drilling otherwise un-drillable prospects.

Dynamic Formation Integrity tests (FIT'S) are conducted much more frequently than industry norm (no need to stop drilling and exercise the BOP), perhaps after each stand is drilled in critical zones to spot weaker than predicted formations and to determine if the mud in the hole at the time is capable of preventing scenarios which may manifest excessive non-productive time and/or a well control incident of some significance.

Closed-Loop Cementing enables actual (not predicted) data inputs to cementing simulator models, precise slurry displacement via annulus backpressure and ability to ascertain in real-time an induced fracture which may consume a quantity of the predetermined volume of cement required for effective zonal isolation and plug & abandonments (P&A).

Deepwater drilling with closed circulating fluids systems (vs. conventional open-to-atmosphere annulus returns) and where mass flow in/out and other critical parameters of drilling and cementing hydraulics are precisely measured, controlled and documented in real time, enables safer & more efficient decision-making on challenging deepwater drilling & completions programs. Equally important, the methods described provide valuable documentation of compliance with API Standard 65, Part II - " Isolating Potential Flow Zones during Well Construction" with remote monitoring capability.
High-Resolution 3D Laser Imaging for Inspection, Maintenance, Repair, and Operations
Authors: Richardson Donald , Embry Carl , Manning Neil , Pappas James Marcus , Nickerson Brett , Hardy Mark
Published: May 2013

In January 2011, 3D at Depth was awarded a RPSEA contract to bring high-resolution three-dimensional (3D) laser imaging technology from the lab into an underwater environment for the oil and gas industry. Throughout the project, CDL Inc. provided expert engineering support and materials to marinize the system. Thus far the project has included design of the core technology for reliable operation in a deep-water environment; pool testing; reliability testing; integration with a work-class ROV; demonstration in a ROV test tank; and turbidity testing. Open water testing is to commence in the first half of 2013.

3D laser imaging is a powerful data collection system that provides 3-D information for a specific area of interest. It is the predominate technology for terrestrial survey, construction, as-built analysis, and large-scale retro-fits. The 3D laser imaging market is a mature multi-billion dollar industry with an eco-system of software, expertise, and best practices. Developing the technology to provide high-definition subsea laser imaging enables the deep water industry to use the current state of the art in 3D metrology and related best practices developed for the terrestrial market.

This paper builds on last year's paper (OTC 23006-PP) and will discuss updates to the system and demonstrations that have occurred over the last year. Top of the line terrestrial laser scanners produce cm spatial and range accuracy at up to one- hundred meters range. Due to the absorption of water, realizable deep-water systems are limited to tens of meters range depending on the target and water conditions. To our knowledge, this is the first time millimeter class measurement accuracy will be demonstrated at greater than 8m range for an underwater laser system mounted to a ROV.

This technology is essential for improving the safety and reliability of deep water assets. The lack of timely and accurate survey-quality 3D measurements poses an integrity management challenge for such assets. A lack of accurate data results in either higher risks or higher costs to build and maintain environmentally safe production and product transportation systems. The speed and precision of the technology developed by this project reduces operating costs for underwater inspection, maintenance, and repair; reduces environmental risk through more accurate inspection; significantly improves construction practices and quality / reliability; reduces risks to high value assets; and provides rapid access to sharable survey-quality as-built data before, during and after construction.
Decision Making on the Ocean Floor: A Simulation Framework To Assess Uncertainty and Variability in Deepsea Mining
Authors: van Gelder Ricardo , Alvarez Grima Mario , Wambeke Tom
Published: May 2013

As land resources decrease, commodity prices increase and technology evolves, deep sea mining is becoming a viable and sustainable alternative to meet the increasing demand for minerals. Successful deep sea mining operations are built on sound identification of the resource, proper selection of equipment, a thoughtful production plan and good project management. The four key activities can be further optimized by analyzing how the spatial variability in ore body properties impacts the final mining operation.

To address this problem MTI Holland, the R&D institute of IHC Merwede, has developed a simulation framework, which makes use of advanced statistical interpolation techniques to model the spatial distribution of geotechnical and ore grade properties. The software captures the spatial correlation of each parameter and calculates the best estimate and corresponding uncertainty distribution at each unsampled location. The resulting collection of spatial distributions is subsequently inserted into physical models, which translate the geological parameters into financial or operational performance indicators. These models, the so called utility or transfer functions, can be used to compute for example cutting forces, power requirements, bearing capacities and cash flows. Contrary to geological properties, these performance indicators are convenient during decision making.

The main advantage of this simulation framework lies in the fact that the spatial variability and uncertainty is propagated through the whole equipment design and mine planning process. As such, the whole procedure results in a risk robust decision, adding value to the project. During a number of business cases, the framework proved to be successful in assisting the equipment design as well as in developing sound mining strategies.
Reliable High Power ESP Tubing Hanger Connector Systems for Deepwater Downhole Applications
Authors: Spahi Sami , Parsley Pamela
Published: May 2013

Electrical Submersible Pumps (ESPs) play a major role when it comes to artificial lift in deepwater reservoirs. Reliability of subsea equipment is an indispensable requirement in deepwater applications due to the high cost of interventions. Tubing hanger connector systems can be a critical failure mode for the ESPs in a High Pressure and High Temperature (HP/HT) environments. Through use of reliability tools such as the Fault Tree analysis, Failure Mode Effect and Criticality Analysis (FMECA), and systems Reliability Block Diagrams (RBD) it was established that improving the reliability of the tubing hanger connector system has a direct impact on the un-intervened life of the ESP electrical system.

In collaboration with the Operator, the Connector System supplier designed and developed a 3-phase 7kVAC, 220 A high power (medium voltage) ceramic based ESP tubing hanger connector system for 1200 hp ESPs. The design is based on the existing High Power connector technology with each phase of the electrical system isolated and adequately electrical stress relieved for long-term reliability. The design employs various insulation materials including, ceramic, thermoplastic, and multi-layer elastomeric seals to achieve phase isolation in addition to mechanical sealing within challenging space constraints and exposure to corrosive fluids and gases.
New Test Method for Field Evaluation of Asphaltene Deposition
Authors: Alapati Rama R , Joshi Nikhil
Published: May 2013

Organic solids deposition such as asphaltene deposition in subsea wells and flowlines can lead to unacceptable levels of lost production revenue, high cleanout costs, and potentially losing a subsea well. Producers invest significant resources in assessing the risk associated with asphaltene deposition, by collecting and storing the needed high pressure reservoir samples, conducting exhaustive and expensive lab testing. In addition, Producers also incur significant OPEX (operational expenses) associated with chemical injection in the hope to mitigate asphaltene related challenges with limited to no success. Extensive research work has been done in the past 5 years to understand the asphaltene onset conditions and deposition tendencies in subsea flowlines and wellbore. A number of test methods and methodologies have been developed to date by producers, commercial laboratories, universities, and chemical vendors. Each test method that has been developed so far has its success stories of applicability and failures as well. A documented evidence of any one test method that would predict the asphaltene deposition issue consistently with high confidence and evaluate the performance of an inhibitor/dispersant accurately is still lacking.

In addition to a testing method in the lab to predict asphaltene instability and deposition tendencies, field techniques are required to monitor performance and make changes to asphaltene dispersant injection requirements. A thorough and objective review of current test methods with data from different fields needs to be presented for the benefit of flow assurance engineers in the industry. Also, identifying possible research paths and outlining equipment needs that would cover the gaps with the current test methods is valuable.

Asphaltene inhibitors and or dispersants are considered as part of the solution but lack of proven test method makes it difficult to validate the value of the chemical solution. Also, new product development requires a reliable, field proven test method. The new testing technique is being developed that would simulate the harshest of the conditions and without requiring high pressure reservoir samples and or expensive and time consuming experiments. The equipment available currently in the industry currently does not meet these requirements. This new test method could be used in the field and will produce results in a shorter time frame, will resolve the current limitations and has the potential to improve the accuracy. Evaluation studies with model fluids and black oils with severe asphaltene deposition tendency will be presented. Data with Evaluation of chemicals will be included as well.