bluuebunny/crossref_metadata_2025 huggingface dataset:
Structure and Hydrocarbon Prospects of the Russian Western Arctic Shelf
Authors: Stoupakova A.V. , Kirykhina T.A. , Suslova A.A. , Kirykhina N.M. , Sautkin R.S. , Bordunov S.I.
Published: June 2014

The Russian Western Arctic Basins cover the huge area including the Barentsand Kara seas, the western part of the Laptev sea and adjacent territories withsome archipelagoes and islands (Spitsbergen, Franz Josef Land, SevernayaZemlya, Novaya Zemlya, etc.). They comprise the Barents and Kara Basins, thenorthern areas of the Timan-Pechora Basin, the North West Siberia, includingYamal and Gidan peninsulas and the Yenisey-Khatanga Basin. Within the RussianWestern Arctic basins the following main tectonic elements can be identified:extensional depressions (Central-Barents, Yenisei-Khatanga, West Siberia, EastUrals) with sedimentary thickness is more than 12–14 km; platform massiveswith average thickness of sediments of 4 – 6 km, monoclines and tectonic steps, like transition zones between extensional depressions and platform massives. Western Arctic basins are filled by mainly Palaeozoic and Mesozoic sedimentarysuccessions. In the sedimentary cover of this large region, many commonstratigraphic complexes and unconformities can be traced within Palaeozoic andMesozoic complexes that show similarity of geological conditions of theirformation. Analysis of the Russian Western Arctic basins, their structures andhydrocarbon prosepctivity shows the areas, which are favourable for hydrocarbonaccumulations. Deep depressions, as areas of long-term and stable sinking, arehighly promising zones for the accumulation of predominantly gas fields. Theyform regional gas accumulation belts, extending for thousands of kilometres, where the largest fields can be expected in the zones of their intersectionwith the major tectonic elements of another strike. Within the Barents-Karashelf, the large belt of predominantly gas accumulation extends from the northof the West Siberian province through the South Kara basin and into the BarentsSea. The second potential belt of predominantly gas accumulation may beassociated with the North Barents ultra-deep depression. On the flanks of thedepressions the sedimentary cover profile does not contain the complete set ofoil-and-gas-bearing complexes, identified in the central parts of theextensional depressions. The reservoirs can be filled by HC due to the lateralmigration of fluids from the neighbouring kitchens or from their own dominantoil-and-gas source rock strata. For the formation of oil accumulations, themost favourable are platform massifs and ancient uplifts areas.
Numerical Prediction of Spilled Oil Behavior under Sea Ice Conditions: Modification of the 2011 Model
Authors: Nakazawa N. , Ono J. , Yamaguchi H. , Ohshima K.I. , Kurokawa A.
Published: June 2014

This report describes an updated version of the numerical prediction systemfor oil spilled under sea-ice conditions in the Sea of Okhotsk that wasdeveloped by the authors and presented at ATC 2011 (Paper Number: OTC 22123). Our previous version enabled the computation of high resolution predictions ofthe ice-spilled-oil behavior using only PCs; a one-week forecast of spilled oilbehavior could be computed in a few hours. This previous method computed thebehavior prediction serially: first step, computation of sea-ice behavior forthe entire Okhotsk Sea (grid size of 16 km × 16 km); second, higher resolutioncomputations (grid sizes of 4 km × 4 km or 2 km × 2 km) using the dataresulting from the first step such as ice concentrations and velocities asboundary conditions; third, final computation of predicted sea-ice andspilled-oil behavior; and fourth, processing and displaying the results in agraphical interface. Since shorter computation times would be advantageous foroil-spill cleanup procedures, we modified the previous serial method to enableparallel computation not only to shorten the processing time but also todisplay spilled-oil/sea-ice images as the computation progressed. This paperincludes an example of computed predictions that model the behavior of spilledoil under three conditions, namely, in open water, in water at the margins ofice-covered water, and in ice-covered water, all located near Soya Strait.
Freeze-Up Processes in the Alaskan Beaufort and Chukchi Seas
Authors: Leidersdorf Craig B. , Scott Christopher  P. , Vaudrey Kennon D.
Published: June 2014

This paper characterizes the processes that presently occur during freeze-upin the Alaskan Beaufort and Chukchi Seas, based on joint-industryinvestigations conducted in 2009-10, 2010-11, and 2011–12. The studies weredesigned to address five specific objectives:describe the ice conditionsthat evolve during the freeze-up and early winter seasons;locate and mapfeatures of potential importance for offshore exploration and productionactivities, including ice movement lines, leads, polynyas, first-year ridgesand rubble fields, and multi-year floes;locate and quantify ice pile-upson natural shorelines and man-made structures;correlate significantchanges in the ice cover with the corresponding meteorological conditions; andcompare present-day freeze-up processes with those that occurred in the1980s.

Each study included an analysis of meteorological data, ice charts, andsatellite imagery in concert with a series of aerial reconnaissance missions. The study findings are presented in seven categories:air temperatures,first-year ice growth,the timing of freeze-up,landfast ice,multi-year ice,ice pile-ups, andextraordinary ice features discoveredoff the Chukchi Sea coast.
An Improved Method of Extremal Value Analysis of Arctic Sea Ice Thickness Derived From Upward Looking Sonar Ice Data
Authors: Ross E. , Fissel D. , Marko J. , Reitsma J.
Published: June 2014

In the Beaufort Sea, observations of extreme draft sea ice features havebeen identified from upward looking sonar (ULS) datasets spanning severalyears. Using analysis methods from extreme value theory, the estimated 100-yearreturn values of the maximum ice draft have been derived. In addition, theapplicability of these statistical techniques to the Northeast Greenland iceregime is examined using one year of ULS data at two locations from 2008 to2009.

The methods have been developed for the Beaufort Sea region andsubsequently, further refined for use in estimating extreme ice hazards offNortheast Greenland. These estimates provide inputs to the design of offshoreplatforms and ships in support of oil and gas activities in these ice-infestedwaters.

Previous studies in the Canadian Beaufort Sea derived an empirical upperlimit on the maximum sea ice thickness resulting from deformation processesbased on the relationship of maximum ice thickness as a function ofsimultaneous values of undeformed ice thickness. Using the more extensive ULSice keel data sets now available, these methods were re-evaluated and updated. Similar analyses were carried out on ice thickness measurements obtained offNortheast Greenland which reveal distinct differences in the ice regime ofthese two geographical areas.

Improvements to extremal value statistical analysis methods for longrecurrence intervals of 100 years for ice draft (D100) are based on the threeparameter Weibull distribution which has been optimized for application to verylarge sea ice keels using a peak over threshold selection approach. Theseresults were compared to the maximum draft limit and undeformed ice thicknessrelationship. We developed techniques to refine at a high resolution the lowerthreshold on maximum draft and examine the implications of this filtering onD100. This is an important consideration as selecting the lower maximum draftthreshold is a balance between retaining enough observations to ensurestatistical robustness and sampling only the extreme tail of the maximum draftdistribution. Methods for performing these statistical analyses arepresented.
Developing a Turret Mooring System for Arctic FPSO units
Authors: Van Der Nat C.G.J.M. , Heideman R.R.
Published: June 2014

The prospect of large oil and gas reserves in fields below Arctic waters hasdriven the design development of production solutions for these areas. Thispaper presents the development of an Arctic Turret Mooring System technologywhich facilitates year-round station keeping of floating offshore structures, like FPSOs in the Arctic environment. The Arctic turret mooring system candisconnect the mooring when the FPSO encounters extreme ice loads, which couldotherwise damage its hull or mooring system. When disconnected, a mooring riserbuoy supports the production risers and control umbilicals. The system isdesigned to quickly disconnect and re-connect the mooring riser buoy. Especially the fast re-connection will reduce the downtime to the productionsystem when disconnection is necessary.

The Bluewater Arctic Turret is based on further development of existingBluewater know-how and designs of (quick) disconnectable Turret MooringSystems. However, in addition to existing designs, the Bluewater Arctic Turretuses a unique and patented design that allows the mooring riser buoy to bereleased from the turret, while being subject to the large (horizontal) mooringloads. In this design, the mooring riser buoy is released from the turret tosink below the FPSO hull, before the mooring system is disconnected from theturret. Following disconnection, the mooring riser buoy descends further to asafe equilibrium depth away from ice hazards. This allows the disconnected FPSOto sail from its production location and later return for reconnection andquickly resume production. The paper presents the unique Bluewater ArcticTurret Mooring concept, its design basis, the development process as well asconsideration to key aspects such as operational and safety issues.
Development of SCS Sandwich Composite Shell for Arctic Caissons
Authors: Marshall P.W. , Sohel K.M.A. , Liew J.Y. Richard , Jiabao Yan , Palmer A. , Choo Y.S.
Published: June 2014

There is a wide range of offshore structures which may be constructed byeither steel or concrete materials to be used in the arctic region, such assteel tower platforms, caisson-retained islands, shallow-water gravity-basecaisson, jack-up structures, bottom-founded deep-water structures, floatingstructures, well protectors, seafloor templates and breakwaters. One commonfeature of these structures is that they must be able to resist the highlateral forces from the floating ice and transmit these forces to thefoundation. This study explores the use of Steel-Concrete-Steel (SCS) curvedsandwich system for arctic caisson structures. SCS sandwich system, whichcombines the beneficial effects of steel and concrete materials, has promisingbenefits over conventional plates and stiffeners design and heavily reinforcedconcrete design because of their high strength-to-steel weight ratio and highresistance to contact and impact loads. Shear connectors have been proposed toprovide bonding between the external steel plates and high-performancecementitious core materials. Finite element analyses and large-scale testresults showed that SCS sandwich panels without mechanical bond enhancement arevulnerable to interfacial shear failure and impairment of structural integritywhen subject to shrinkage and thermal strains, accidental loads, and impact. The proposed SCS sandwich system features mass-produced mechanical shearenhancement and/or cross-ties. It can reduce structure complexity, particularlyin the number of weld joints which are prone to fatigue, hence increasingservice life, cutting down the cost of fabrication, and reducing the manpowercost to operate, inspect, and maintain the structure in the long run. Considering local ice load, the punching shear and shell bending strength ofthe SCS sandwich composite shell is studied experimentally. Test results showedthat the SCS sandwich panels, which are designed using the ISO ice load, arecapable of resisting the localized contact and punching loads causedthereby.
Novel Energy Efficiency Technologies for Reduction of Offshore COEmissions
Authors: Walnum Harald T , Mazzetti Marit J , Neksa Petter Luis , Hemmingsen Anne Karin T
Published: June 2014

This paper will discuss novel technologies for increasing the energy efficiency of offshore oil and gas platforms. Three case studies are in progress based on actual oil producing platforms, two on the Norwegian Continental Shelf (NCS) and one in the Brazilian Basin. The current focus is on developing compact, novel bottoming cycles for recovery of waste heat from the gas turbine as well as heat recovery from the compressor train for gas export. The technologies investigated utilize steam as well as alternative working fluids, such as CO2 and hydrocarbons. All the fluids investigated in this project are natural working fluids hence they will not cause any unexpected environmental issues in the future.

A case study was performed looking at an eighteen year period of operation on an actual platform and a scenario where one gas turbine is removed and replaced with a CO2 bottoming cycle utilizing the the exhaust heat from one of the other gas turbines. The beauty of this scenario is that it would not increase the weight on the platform since the crate containing the gas turbine to be removed is of a similar weight to a crate that contains a CO2 bottoming cycle. The substitution would not affect the ability to cover the heat demand on the platform as a Waste Heat Recovery Unit (WHRU) can be installed on the platform's other gas turbine.

The case study indicates significant reduction in CO2 emissions of 22%, or 63 000 tonnes/yr, and does not involve adding additional weight or volume to the platform. If operating on the NCS the annual savings in reduced fuel costs and CO2 tax from implementing Scenario 2 would be US $17M, albeit much lower in other territories.
Value of Well Test Acquisition Strategy and Advanced Interpretation Methodology in Peregrino Field
Authors: Vasconcelos Daniel Francisco Maia , Torres Diego Martins
Published: June 2014

The Peregrino field is a heterogeneous heavy oil field located offshore Brazil in the Southern Campos basin. The field is planned to be developed with 30 geosteered long horizontal producers completed with ESPs for lift and 7 water injectors. As per July 2013, 19 producers and 3 injectors are on stream. The reservoir deposits are characterized as complex shallow marine and gravity driven sedimentation processes in shore phase to offshore environments.

Information deduced from the pressure transient analysis (PTA) are highly valuable in complex and heterogeneous reservoir deposits for increased reservoir understanding enabling optimization of the production and development strategy. The well test information has the potential to provide average rock properties on a larger scale related to permeability, sand continuity, fluid properties and distance to reservoir boundaries (such as erosional features, faults and fluid contact) that can be used as conditioning points for reservoir modeling and characterization.

This paper provides a description of the PTA acquisition strategy and the advanced interpretation methods for ensuring high quality data and maximized derivation of information that can be used to optimize the production and development strategy for the Peregrino field. High viscosity oil, wells with long reservoir sections, ESPs for lift and well interference makes this especially challenging. Since the pressure waves propagate slowly through the reservoir, the deconvolution technique has been implemented in order to maximize the value of repeated PTA in the same well and thereby enabling identification of reservoir features with the minimum amount of downtime for the production wells and also enhancing its value as a predictive tool. The reservoir information is used to update the reservoir model, optimize the well spacing and optimize placement of wells in relation to the oil water oil. The importance of prioritizing this type of data acquisition from day one in the field development will also be presented.

Introduction

The Peregrino Field is located in block BM-C-7, in the southernmost part of the Campos Basin (Figure 1). The area is located 85 km southeast of the nearest coastline, approximately 100 km southeast of Macaé, Brazil. The Peregrino Field was discovered in 2004, with production start-up in 2011. The water depth in the area varies from 95 to 135 meters, over an area of approximately 350 km2. The reservoir depth in the field is between 2150 and 2350 meters TVD. The Peregrino Field is one of the heaviest offshore oil developments in Brazil. PVT properties for Peregrino are shown in Table 1.
Advanced Control Systems for Offshore Production Platforms
Authors: Simoes Saul , Santos Wilson Trindade , Campos Mario Cesar Mello Massa de , Pimenta Austin , Teixeira Alex Furtado , Von Meien Oscar Felippe , Stender Alberto Santanna
Published: June 2014

The discovery of new reserves of oil and gas located at great distances from the coast, with increasingly stringent regulations for safety, energy efficiency, environment and quality of products, poses new technological challenges for automation and control. Advanced control systems can play an important role to improve stability and profitability. The main objectives of advanced control systems are:Maximize the production;Ensure the specification of products;Minimize energy consumption;Minimize the process variability which increases safety and minimizes the flare (loss of products);Minimize operational costs, operating the equipment in a stable environment thus reducing the number of unscheduled stops resulting in lower maintenance and logistics costs.

Although advanced control system is a reality in many industrial areas (refineries, petrochemicals and gas plants), it is not widely used for offshore production units. There are many causes that justify why advanced control is not widely utilized in offshore platforms, like:A platform has many transients (shutdown, different well alignments, etc.), many disturbances (slugs), uncertainties and noise.Oil and gas production is never in a steady state because it is a time-varying process (gas-oil-rate, water cut, sand production, gas coning, water coning, etc.).Few instruments available, for example there aren't many pressures and temperatures instruments inside subsea pipelines and wells, etc.There are no advanced control specialists onboard to install and keep these tools working properly.

This paper will present some solutions to promote the use of advanced control on a platform, for example:New control strategies to minimize the effects of transients (adaptive algorithms to find out optimum PID tuning) and disturbances (anti-slug control) and also new algorithms to optimize the process.A methodology in order to help the implementation of these tools that change the way the operators interacts with the production process.

This paper will show and discuss some results of the implementations of these advanced control systems in offshore platforms, emphasizing the gains of stability and profitability. The offshore plants are becoming more complex and require these advanced tools to support the operators.

Introduction

The regulatory and advanced control, as well as real time optimization systems can provide many advantages for the industrial units, as improved stability and safety, respect to constraints and higher profitability. Figure 1 shows a schematic automation pyramid containing the regulatory and advanced control layers.
On the Role of HISC on Super and Hyper Duplex Stainless Steel Tubes
Authors: Salvio Filipe , S. Silva Bruno Raphael , dos Santos Dilson Silva
Published: June 2014

The Super duplex stainless steels (SDSS) are characterized by a remarkable combination of corrosion resistance and mechanical strength, mainly in chloride containing environments. Because of this, its demand is growing every year in offshore applications, becoming an alternative to the ferritic and austenitic stainless steels. Nevertheless, due to the lack of oil, the offshore companies are moving toward deeper waters and harsher environments, where it calls for the need of stronger materials. Facing this scenario, the Hyper duplex stainless steel (HDSS) was developed to achieve better properties than SDSS.

Despite the pronounced properties, the duplex grades can suffer environmentally induced cracking, as recorded in some failure cases of subsea structures. The driven force for these occurrences was the combination of three main factors: stress/strain, inappropriate microstructure and presence of hydrogen due cathodic protection (CP). In general, this set of events is called Hydrogen Induced Stress Cracking (HISC) within the offshore industry.

The SDSS and HDSS tubes in as-received condition were divided in two groups. One group was strain-hardened in order to simulate fabrication and laying operation. The second group was tested in annealed condition. For each, the tubes were cathodically charged for 160 hours in artificial seawater, under or without elastic stress, at cathodic potential equivalent of -1350 mVSCE. Then, the charged tubes were submitted to tensile testing and their HISC susceptibility was assessed. The fracture surfaces were analysed in order to identify the active micro mechanisms of failure.

The results showed that for the stressed/strain-hardened samples the embrittlement was more pronounced than the unstressed/annealed ones.

Introduction

Super duplex stainless steels (SDSS) are dual-phase steels containing austenite (γ) and ferrite (δ) as close to 50/50% distribution as possible. The synergic effect between both phases promotes a good combination of high mechanical strength and excellent resistance to stress corrosion cracking in chloride solutions, as well as in the presence of H2S and CO2. Due to the excellent agreement of properties, these steel grades are widely employed in the petroleum industry, highlighted in offshore applications such as subsea equipment, umbilical tubes and liner pipes [1–4].
Compact Electrostatic Treaters for Floating Offshore Production Facilities
Authors: Sams Gary , Sellman Erik L , Mandewalkar S Pavan Kumar
Published: June 2014

Floating production facilities are very sensitive to equipment weight and footprint. New electrostatic technologies have enhanced the dehydration and desalting process for crude oils by improving treater hydraulics and increasing the electrostatic field strength of the treaters.

Efficient vessel hydraulics is essential for achieving maximum dehydration performance and efficient utilization of the treater vessel volume. Not only is the oil distribution critical but oil collection is equally important to maintaining treater dehydration and desalting performance. A new distributor can increase the treater utilization from low 50% to 95% allowing for the use of smaller and light weigt treaters for crude oil dehydration and desalting.

The crude oil dehydration and desalting performance also decreases as the crude oil conductivity increases, whether this is caused by an increase of heavy solids, asphaltenes or polar organic components, the electrostatic field strength can be reduced significantly. One method for maintaining the electrostatic field strength is to utilize high frequency electrostatic field to quickly replenish the effective voltage and reduce its decay. Modulating the voltage amplitude has also proven to be effective for increased dehydration performance.

Another treater improvement is the use of composite electrodes, which increases the water tolerance of the treater and also improves the treater dehydration performance.

This paper describes compact (light weight and reduced foot print) electrostatic treaters and how these technologies can provide lower CAPEX as well as lower OPEX for offshore crude oil treating facilities. The role of vessel hydraulics, electrode materials and electrostatic field strength to maintaining efficient dehydration and desalting performance will also be discussed.

Introduction

Floating production platforms are used for production facilities installed in deep waters. The Cameron Dual Polarity® and Dual Frequency® technologies have been around for more than one decade and have rapidly developed a solid installed base for crude oil dehydration and desalting on floating production facilities such as FPSOs, SPARs, semi submersibles and other floating production facilities. The higher electrostatic field strength of the Dual Polarity and Dual Frequency type electrostatic treaters allows the use of smaller treaters which provides both weight and space savings. The ElectroDynamic Desalters® also provide an opportunity for use of a single desalter in lieu of two stage desalter arrangement. The Dual Frequency technology combines higher electrostatic field strength with a higher coalescing power and thus allow for the use of drastically smaller treaters.
Smart Reamer Calliper - Real Time Wellbore Diameter and Underreaming Verification
Authors: Alcure Marcos , Placido Joao Carlos Ribeiro , Rasheed Wajid , Lage Antonio Carlos V.M.
Published: June 2014

This paper outlines the R&D methodology of an innovative Smart Reamer Calliper for measurement while drilling. The concept was progressed from design to prototype with long hours downhole drilling qualification completed in 3 years. Existing calliper measurement technology is limited for numerous reasons not least BHA placement and erroneous readings due to changes in fluid density. The prototype tool overcame these limitations by building on-board proper calibration and multiple sensors that allow 360 degree mapping of the wellbore shape. Further optional Measurement While Drilling (MWD), magnetic, vibration and underreamer position sensors can be added.

A R&D project was established with incremental tests identifying root-cause failures/design issues before moving to the next stage. This iterative process ensured proper prototype manufacturing and minimised risk at critical test points. At the same time parallel activities enabled the project to reduce overall time associated with common project tasks. The whole R&D consisted of 4 stages: design and FEA, small scale testing, full scale testing and long hours field test drilling.

The prototype tool was first tested in sliding, rotating and underreaming BHAs for actually drilling a total of 900 m in chalk, clay and sands. Small scale lab tests including high pressure and temperature at 13,053 psi and 150°C for 100 hours were conducted in England. Full scale under-reaming testing occurred in Norway with a wireline calliper for cross-check of the wellbore diameter measurement, and finally another qualification test in England comprising 59 hours on bottom drilling. Lastly, MWD integration was performed using standard MWD pulsers. The new Smart Calliper tool is being developed to accurately measure and provide both memory and real-time data of the 3-D wellbore allowing the drilling team at rig-site to:Pinpoint narrow or under-gauge wellbore sections, verifying underreamer performance and measuring wellbore diameter above the reamer allowing for corrective reaming trip to be performed while drilling BHA is still in hole.Offer better cement volume estimate to minimise excess.Eliminate wireline calliper deployment.Eliminate a wiper trip typically carried out prior to running long casing string.Offer monitoring of downhole tool vibration and separate directional survey if required.
Advanced Forging Process (AFPTM), Super Duplex Stainless Steel for Increased Low Temperature Impact Toughness and Resistance to Hydrogen Induced Stress Corrosion Cracking (HISCC) Due to Cathodic Protection of API Forgings for Subsea Applications
Authors: Francis R , Byrne Dr. Glenn , Warburton Geoff , Schulz Zach John
Published: June 2014

As oil wells become deeper and run at higher temperatures and pressures, there becomes a need for high strength, corrosion resistant material that will withstand the more severe service conditions of these projects. Over the years many projects in various locations around the world have successfully used duplex and super duplex stainless steels for subsea pipe lines, flow loops, flow lines and manifolds to contain the high temperatures and pressures and more demanding corrosive service required with the High Temperature High Pressure (HTHP) wells.

Additionally, operators have realized that they need to qualify the manufacturers of these materials following a number of problems experienced in the field. They see that the more severe conditions require a higher level of quality and security to go with the more demanding performance required. As such, the NORSOK M650 specification is seen as way to qualify the manufacturer and ensure a higher level of quality in the product. This has not solved all problems and a few operators are placing even greater demands on manufacturers to ensure they have the required metallurgical understanding and production facilities to produce parts in these more complicated alloys.

There is also a recent development for super duplex stainless steels to meet service conditions beyond usual requirements. A number of operators have projects where minimum design temperatures are calculated to be as low as −70°C, which is near the lower shelf toughness level for duplex stainless steels. This paper discusses the properties that can be achieved by optimizing the forging route and therefore minimizing nitride precipitation in these alloys. The resultant properties are sufficient to meet the impact properties typically required at temperatures down to −70°C. In addition, the improved ductility and toughness also increase the resistance to HISCC due to cathodic protection. Several end users and OEM's have already used ZERON® 100 AFPTM to benefit from the improved toughness at design temperatures as low as −70°C.

This paper will cover the metallurgy of duplex alloys and how improved understanding and processing can lead to less nitride precipitation, better morphology and austenite spacing that will have a beneficial effect on both toughness and HISCC resistance. The improved toughness values can also be seen across the full temperature range of most Oil & Gas projects with excellent properties at −50°C as well as at −70°C. Discussion of a few case histories also confirms the need for application of this Advanced Forging Process (AFP) of super duplex stainless steel.
Original View on Brazilian Local Content Regulatory Enviroment
Authors: Souza Robson
Published: June 2014

Since Law No. 9.478/97 was enacted, the ANP (National Agency of Petroleum, Natural Gas and Biofuels) has been looking forward to enhance local content for the areas offered in its rounds.

After several tender processes, local content requirements had become decisive for the concession contract winners. Consequently, all the concessionaire supply chain had to evidence the local content of its products and services in accordance to the existing rules. As result, the local content that could be achieved by each E&P (Exploration & Production) supplier becomes a great competitive differential in Brazilian oil market. In this context, foreign companies interested in taking advantage of the growing opportunities in the E&P segment in Brazil, started to look for alternatives and structures capable of adding local content to their products and services.

The concession contracts for offshore blocks have the highest local content commitments during the development phase. This is because there are huge investments in goods and services acquirement, particularly in the acquisition of a production unit like FPSOs (Floating production, storage and offloading) which are particularly efficient due to its mobility in different areas.

The construction and installation for a FPSO, for instance, generates significant demand for such goods and services that may impact the entire local supply chain. The lack of availability these acquisitions in the Brazilian market may adversely affect the attractiveness of projects. Thus, we highlight the importance of a more appropriate method that considers both the profit margin as local content committed by the concessionaires with ANP.

Considering the relevance of the scenario presented above, this paper aims to suggest a method that supports the decision-making that complies with the required local content index and the operator preference. The original view on Brazilian regulatory environment, contributes to improve local content strategy in petroleum industry. The work is developed briefly presenting: method of decision support; oil industry in Brazil; regulatory market and local content policies.
Application of Mesophase Technology for Reservoir Damage Remediation and Improve Hydrocarbon Producibility - A Successful Case History from Kuwait Field
Authors: Veluri Vijay Saradhi , Al-Ajmi abdullah , Al Barazi Naser K , Rasheed Al Enezi Dakhil , Sharma Sidhartha Shankar , Takate Yogesh , Clark David , Al-Mutairi Moute'a , Al-Ajmi Hadi Saad , Al-Rushoud Abdulazziz Saud , Suryavanshi Vijay , Yadav Prahlad , Jadhav Prakash Balkrishna , Sotomayor Ghery , Khan Yousuf , Al-ajmi Khaled , Al-Khaledi Ali , Awad Mohamed Omar
Published: June 2014

An operators renewed focus on horizontal well drilling and open hole completions, using Inflow Control Device (ICD) screens, necessitated the use of oil-based drill-in fluids (DIF) to drill and complete their reservoir. The challenges were increased by low reservoir pressure conditions, increasing the risk of drilling fluid invasion and possible reservoir damage. Comprehensive laboratory studies were carried out to evaluate DIF performance and ensure understanding of the possible damage mechanisms produced while drilling, considering the reservoir characteristics and drilling conditions.

The customized near-wellbore damage remediation system, with a delay-reaction, was designed based on Mesophase technology. This paper discusses detailed laboratory analysis for the clean-up system and its field applications in Kuwait horizontal wells. The applications included drilling carbonate and sandstone reservoirs, open hole ICD completion, and performing effective cleanup required for maximum production.

The effectiveness of the Mesophase clean-up system to remediate reservoir damage and improve producibility was evaluated immediately after well kick off and again after steady production levels were reached. This paper shows the results obtained after the application of the near-wellbore remediation technology.

The lessons learnt during the Mesophase application were incorporated on upcoming wells to standardize the operating procedures and improve field performance.

Background

To meet production targets from Raudhatain field, the operator initiated a horizontal well drilling campaign with open hole ICD completions in Mauddud (Carbonate) and Burgan (Sandstone) reservoirs. The ICD screens control flow rates across the completion for the entire length of the interval. This approach dramatically reduces the effect of water and gas breakthrough, while optimizing production rates across the full completion interval.

Challenges encountered during drilling these horizontal wells included increased non-productive time resulting from interbedded formations with varying formation pressures, wellbore instability in the reactive and stressed shale sections and hole cleaning issues. An oil-based drill-In fluid system was designed with a high oil water ratio (OWR) to overcome these challenges and protect the reservoir from drilling fluid damage.

The formation damage mechanisms analyzed included:Foreign particle invasionFormation clay swellingChemical incompatibilityOil wetting of the reservoir rockEmulsion blockingFluid invasion (Water Blocking)
Development of a Novel Kinetic Hydrate Inhibitor and Corrosion Inhibitor Package for Wet Gas Application
Authors: Jones Regan , Morales Noah , Anthony Jacob , Webber Peter Andrew , Harrington Ryan
Published: June 2014

A dual functional kinetic hydrate inhibitor (KHI) and compatible corrosion inhibitor (CI) package was developed to simplify production chemistry demands for operation in wet gas mode. As these two classes of chemistries are both water soluble and contain surface active components, they have a tendency for interference reducing the efficacy of each inhibitor. Their pairing in a production scenario requires both comprehensive performance testing as well as extensive secondary properties evaluation.

The KHI is to serve as a traditional KHI during steady-state operations while performing as a thermodynamic hydrate inhibitor (THI) during extended shut-ins and cold well restarts. This challenge required the development of a KHI which would retain performance upon significant dilution in a thermodynamic hydrate inhibitor solvent carrier (methanol, ethanol, monoethylene glycol, etc). Performance of this new KHI would be confirmed in blind rocking cell experiments, in the presence of the matched corrosion inhibitor, targeting a hold time of more than eight days at a subcooling of 8 ºC.

The CI is targeted to reduce the general corrosion rate to less than 0.1 mmpy and prevent localized attack. Due to the surfactancy of this class of chemistry, the tendency to induce and stabilize emulsions is of high concern. A robust formulation amenable to modification and potential dilution is required to address the application of chemical over a vast subsea network containing wells of varying age, existing infrastructure, production profiles, and operating conditions.

This paper describes the development, qualification process, related lessons learned, and field applications of this new KHI/CI package.

Introduction

The oil and gas industry often relies on chemical solutions to address challenges related to flow assurance and corrosion inhibition. The transport of produced fluids containing water and acid gases such as carbon dioxide and/or hydrogen sulfide in metal pipelines afford conditions susceptible both to gas hydrate formation and corrosion. Accordingly, production chemical strategies typically must consider a compatible corrosion inhibitor and low dosage hydrate inhibitor as a unified package.

Standard chemical compatibility often includes the mixing of two neat production chemicals with exposure at various temperatures to examine for hazing, phase separation, precipitation, etc. This exercise provides operators insight in the event that chemicals are accidently mixed in storage tanks or may come into contact in delivery lines. Though, the performance compatibility of a KHI and a CI presents a more challenging case.
Subsea Geo-Hazard Risk Assessment and Pipeline Integrity Management - A GIS-Based Data Integration Approach
Authors: Li Ming , McQueen Mark , Bik Marc , Zhai Dong
Published: June 2014

Geo-Hazard assessment is a critical part of threat identification, risk assessment, fitness for services assessment, and overall subsea asset integrity management. Successfully addressing the data management challenges will yield huge benefit to future achievement in quantitatively evaluating and managing geotechnical hazards. In addition, further data visualization and integration analysis is playing an increasingly important role in decision making of pipeline integrity management in today's subsea industry.

This paper proposes a GIS-based data integration approach to managing, analyzing, and visualizing the geo-hazard data, which will help facilitate the early asset integrity management planning.

A case study was presented.

Introduction

For subsea systems, Integrity Management (IM) should provide a solution throughout the whole life cycle of the key associated assets. From project execution perspective, this means the solution should be implemented throughout multi-phase stages which typically involve Pre-FEED, FEED, Design, Construction, Commissioning, Operations, and Decommissioning. This life-cycle driven concept adds a new perspective to the traditional operation-stage focused IM services. Following this philosophy, an effective Integrity Management Plan (IMP) needs to capture multi-phase project data and incorporate the subsequent risk and integrity assessment analysis throughout the life cycle of subsea assets. As a result, the life-cycle based IM approach, particularly through early stage implementation, can help verify key design and response uncertainties early in field life and demonstrate continued fitness for purpose throughout the life of field. However, despite major benefits, this new approach also poses some key challenges summarized as follow:

1) Data Management:

Life-cycle based IMP needs to include a compressive data management system component to effectively manage vast quantity and range of data acquired at multiple phases throughout project execution. Typical information that needs managing and analyzing includes:Historical process and production data, such as pressure, temperature, flow rate, pH, composition, etc.;Erosion and corrosion probe data, corrosion management strategies, etc.;Chemical injection data;
Integrated Modeling for 3D Geomechanics and Coupled Simulation of Fractured Carbonate Reservoir
Authors: Correa Antonio Claudio Franca , Newman Robert Bourne , Naveira Vanessa Palma , de Souza Antonio Luiz Serra , Araujo Tales , da Silva Alexandre Augusto Cardoso , Soares Antonio Claudio , Herwanger Jorg Volker , Meurer Gustavo Bechara
Published: June 2014

Geomechanical models have multiple uses in reservoir management and field development planning. In this case study from a producing deepwater fractured carbonate reservoir (water depth approx. 1500m) we use the same geomechanical model to understand (i) why hydraulic stimulation failed to open a hydraulic fracture due to high minimum principal stress, (ii) what the limits of mud weights for drilling horizontal wells into the pressure depleted reservoir are, and (iii) investigate what the effect of pressure depletion and associated stress changes are on fault permeability, thereby providing an explanation for an observed early water-breakthrough. Multiple data sources, including structural seismic interpretation and Amplitude-versus-Offset (AVO) inversion, well-log measurements and rock-mechanics laboratory tests were combined in building a mechanical property model, and the computed stress state was calibrated with wellbore observations of breakouts directions, induced fractures and leak-off tests.

Introduction

Reservoir geomechanics has become an accepted technology for the petroleum industry during last decades. There are many benefits on improving geomechanical understanding, including:A better characterization of reservoir volume deformation and impact on rock permeability (compaction and dilation);Prediction of surface subsidence;Reducing of risks of fault reactivation and out-of-zone hydraulic fracture propagation during waterflooding or other improved oil recovery process.

In Petrobras, Reservoir Geomechanics is a fundamental tool for development of fields with large number of faults/fractures, which is the case of several offshore sandstone reservoirs in Campos Basin, as well as some carbonates fields. Here we discuss the development of a comprehensive reservoir geomechanics study in an actual field of the Campos Basin. The presented technology has been developed as part of the Technology Cooperation Agreement on Reservoir Geomechanics between Petrobras and Schlumberger. A similar study has been carried out for a sandstone field and presented at a SPE Conference (Souza et al, 2012).
Case Study: Utilizing of Inflow Control Device To Control Oil Wells from Water Production and Regulate Waterfront Encroachment
Authors: Bajunaid Hani Ahmed , Moawad Taha Mousrafa , Al-dhafeeri Abdullah M , Abd Elfattah Mahmoud Mohamed , Mohammed Tawakol I.
Published: June 2014

Khafji offshore field, located in the Arabian Gulf, contains an unconsolidated sand reservoir subdivided into two, upper and lower reservoirs. Upper sandstone reservoir has relatively low reservoir pressure utilizing gas lift to help wells achieve production target rate. The main obstacle in upper reservoir is water encroachment due to unfavorably high-water mobility compared to oil; which presents a reservoir management challenge in the form of curbing water production linked to relatively high-permeability sandstone reservoir. In upper reservoir, water encroachment is dominated by active edge-water drive and it has irregular water-front movement because of the presence of high permeability streaks.

Excessive water production from the high permeability upper sandstone reservoirs causes major economic, operational, and environmental problems during oilfield operations. Water production can also cause secondary problems such as sand production, corrosion, emulsion, and scale formation. Although the reservoir has been on production more than 50 years, water sources are still considered to be a mystery. Many different concepts and scenarios have been considered such as channeling behind the casing, highly conductive faults, channeling through the high-permeability zones and high-permeability streaks, which accelerated water production. As a result of this issue, water breakthrough at crested wells in an edge-water driven upper reservoir and water production has increased.

Inflow Control Devices (ICD) completion has been installed in upper reservoir wells to overcome water production challenges. Low reservoir pressure is a major challenge for upper reservoir wells ICD completion design. During the course of this paper, Khafji field water encroachment study results have been discussed to show the latest water front movement expected scenario. In addition, ICD-completed wells performance was analyzed and compared to cemented perforated liner completion wells (Non-ICD completion) offset wells in upper reservoir. The parameters that were used during the ICD-completion design to overcome the main field challenges were highlighted. ICD completed wells showed positive performance results in water production control and higher oil production rate.