bluuebunny/crossref_metadata_2025 huggingface dataset:
1000 Km of Under Ice Seabed Survey with an AUV
Authors: Mills Richard , Fergsuon James , Laframboise Jean-Marc , Kaminski Chris , Crees Tristan
Published: December 2011

In March and April 2010, an ISE Explorer Autonomous Underwater Vehicle (AUV), built for Natural Resources Canada (NRCan), was deployed to Canada's high Arctic. Its mission was to undertake under-ice bathymetric surveys in support of Canada's submission to establish the outer limits of its continental shelf under the United Nations Convention on the Law of the Sea (UNCLOS). During this deployment several under-ice records were broken and several new technologies were demonstrated.

NRCan's AUV is an ISE Explorer class vehicle, with several innovative additions to make it suitable for arctic survey work. Most notable are a 4000 m depth rated variable ballast system, a 1500 Hz long-range homing system, and under-ice charging and data transfer capabilities. A Short-Range Localization (SRL) system was also developed for close range positioning. The homing and SRL systems were developed by Canadian defense scientists and engineers at DRDC (Defence Research and Development Canada).

The Explorer's range was extended to approximately 450 km by adding a hull section to accommodate extra batteries. The scientific payload onboard included a Seabird SBE49 Conductivity-Temperature-Depth (CTD) sensor, Knudsen singlebeam echosounder, and a Kongsberg Simrad EM2000 multibeam echosounder. In order to optimize battery endurance, the plan was to only turn on the EM2000 at strategic locations (i.e. potential sea mounts) along the mission path.

The Main Camp near Borden Island (78°14’N, 112°39’W) was the launch site for the AUV. It was launched from an 8 m by 3 m ice hole, cut through 2 – 3 m thick ice. After several test dives, the first mission was a transit to a Remote Camp, 320 km to the northwest. The AUV autonomously homed into the Remote Camp and was secured with the help of a small remotely operated vehicle (ROV). Without being removed from the water, it was charged and survey data was downloaded, all through a 1.3 m by 2 m ice hole. Subsequently, a second survey mission was undertaken in a region known as the Sever Spur (~79°N, 115°W), which returned back to the Remote Camp. Finally, it embarked on a return transit mission to the Main Camp for recovery. The AUV spent 10 days under ice before being successfully recovered. In total, close to 1000 km of under-ice survey was accomplished between the 3 missions. The AUV reached depths of 3160 m and transited at an average speed of 1.5 m/s at an altitude of 130 m above the seabed. From operating entirely under ice, to surveying in such a challenging environment, to the distances and objectives, this is an historic milestone in AUV and polar science. ISE, DRDC and NRCan are now preparing for a 2011 deployment to collect additional arctic survey data.
Offshore Pipeline Installation in Arctic Environment
Authors: Lange Frank , van Zandwijk Kees , van der Graaf Jan
Published: December 2011

In the arctic environment the installation of pipelines offshore and in the area between land and sea is a challenge. The remote logistics, the short and unpredictable season and the trenching and burial in often not well known possibly permafrost soils require novel approaches all under the requirement of leaving a minimal environmental footprint. Based on the experience Heerema Marine Contractors (HMC) has in the installation of pipelines and pipeline trenching and studies performed for the Baydaratskaya Bay crossing and for the Beaufort Sea, approaches will be presented for the installation of pipelines in arctic and extreme environments. They are based on recent studies partly done in-house and partly for and with industry clients.
Offshore Arctic Drilling System Selection Process: Water Depths from 50 - 500 meters
Authors: Simpson Richard
Published: December 2011

Recent offshore lease sales in Canada have made available the opportunity to explore for oil and gas in the Polar Arctic regions of the Beaufort Sea. BP Exploration Operating Company Limited (BP) was awarded Exploration Licenses 449, 451, and 453 in 2008. The focus of this paper is upon selection of an Offshore Arctic Drilling System for Exploration Licenses 451 and 453 as, BP formed a Joint Venture in 2010 with Exploration License 449 where operatorship was designated to another company.

Due to the wide range of ice conditions and water depths in the lease areas, determining the most capable Offshore Arctic Drilling System is a complex undertaking. Detailed are the considerations and methodologies utilized to recognize and quantify the key challenges involved. Once identified, these challenges were divided into discreet elements so as to progress multiple solutions in parallel in order to determine the true limits of opportunities to provide for a safe and efficient drilling program.

Rapid progress was obtained through extensive collaborative engagement with Drilling Contractors, Vessel Operators (including Ice Breaking, Anchor Handling, and Supply Vessel), Remote Imaging Service Providers (Satellite and Autonomous Vehicles), Numerical Modeling Specialists, Vessel Designers (Naval Architects and Marine Engineers), Equipment Manufacturers (Dynamic Positioning Systems, Mooring Systems, Thrusters), Drilling Subject Matter Experts, and recognized individual Arctic Experts.
New Well Foundation Concept, As Used at a Norwegian Sea Well
Authors: Sivertsen Trond , Strand Harald
Published: December 2011

A new and safer, high load capacity well construction concept has been developed. This new well foundation system as installed at a Norwegian Sea well location by Det norske oljeselskap ASA, is described herein, as well as its use and recovery. Heavy Blow Out Preventers (BOP) are normally used on drilling rigs designed for deep water and arctic applications, and heavier BOPs will have a negative impact on the stability of the well head. To mitigate these negative impacts, a new suction anchor type well foundation concept; CAN (Conductor Anchor Node) has been developed. The CAN unit provides sufficient load capacity for safely carrying heavy BOPs as well as X-Mas trees, thus protecting the well from fatigue capacity "consumption" in the drilling phase. The use of the concept will also reduce cuttings and cement disposal to the sea, which may be further important aspects in arctic and sensitive marine environment areas.

The CAN will also mitigate the risks of the well becoming over-loaded by undesired, accidental loads, e.g.: as a result of a rig drive off/drift off situation. This is achieved by mobilising substantial carrying capacity from the soil through the CAN's large cross sectional area and captured soil mass. This is an important aspect in view of risk mitigation and improving possibilities of applying contingency means in case of undesired events or disasters, such as the Macondo case.

The concept offers significant advantages in reducing rig time; as it enables pre-rig conductor installation, thus reducing top-hole construction costs and rig failure risk exposure. The concept's viability and advantages have been demonstrated by a number of full scale applications ranging from 270 m to 1 150m water depth on the Norwegian Continental Shelf.

The CAN will be a facilitator for safe jetting of conductors (only short length conductor needed), as well as being an enabler for achieving successful cement jobs (if installed by drilling and cementing), as the conductor remains supported and motionless during cement set-up.
Think Before You Shoot: Planning and Piloting Seismic to Maximize Value - Russkoye Field Case Study
Authors: Zhukov Artem , Priebe Hermann , Demushkin Alexey
Published: December 2011

Accurate reservoir models are an important pre-requisite for optimum development of oil and gas fields. In order to build these models good quality input data from well logs and seismic surveys are essential. The integration of these data provides a robust groundwork for generating reliable maps of subsurface structures and credible predictions of reservoir presence and quality distribution. Such well-constrained models can add technical and commercial value when used to generate, evaluate and optimize field development scenarios and production profiles.

Many hydrocarbon fields in Russia were discovered back in the 1960-70s and therefore are often short on good quality well and seismic data. Geological and geophysical data (especially well logs) were acquired a relatively long time ago and can no longer meet increasingly rigorous standards essential to support reservoir quality prediction and to maintain and update subsurface models (that integrate geological and seismic information) throughout life of field. It is the quality of this data, however, that drives optimization of well pad drilling, development drilling success rates and better reservoir management on field margins.

Key limitations associated with vintage log data are as follows:

Logs were traditionally run exclusively over main pay zones without investigating the full length of the wellbore; Limited logging programs with a modest range of log types (commonly missing formation density logs, full-wave sonic logs, etc.); Lack of vertical seismic profiling (VSP) data to accurately tie well and seismic data; Poor quality of well data acquisition and processing.
Potential For Oil And Gas Projects In The New Oil And Gas Province Shared Between Russia And Norway
Authors: Bulakh Maria , Zolotukhin A. B. , Gudmestad O. T.
Published: December 2011

The recent agreement between Russia and Norway regarding the border between the countries in the Barents Sea offers unprecedented opportunities for Norwegian-Russian cooperation in developing oil and gas fields. In this paper we summarize information about the agreed state borders in the former disputed ("grey") zone of the Barents Sea, see Figure 1, and suggest possible scenarios for the oil and gas fields’ development.

The "Grey Zone" area is about 175 thousand km2 in which, according to official estimates, is concentrated around 1% of world's undeveloped oil reserves. The resources of the former disputed territory are potentially about 410 million tons of oil and nearly 6 trillion cubic meters of natural gas. According to preliminary estimates the largest deposit is the Fedynskoe field. Its resources are expected to be around 10-12 billion boe or but may potentially be as high as 18 billion boe.

The "Grey Zone" can be regarded as a key for development of hydrocarbons in. the Barents Sea area due to following circumstances: it has favorable environmental and geographical conditions such as being year-round ice free, relatively shallow water – 200-300 meters and short distance to shore about 100 km. Its location is appropriate for easy organization of export of oil and gas from the northern regions.

The financial costs of the development of the "Fedynskoe raising" (Fedyn Arch) will be significantly lower than in other Barents oil and gas areas further North or East. There might be huge interest by investors in this area. The investments on the Shtokman field development could be reduced taking into account the possibility of a joint infrastructure solution for these fields’ development.

It seems interesting to consider an integrated planning. In the present paper we are discussing possible options for development and arrangement of the Fedynskoe field in relation to scenarios of Shtokman field planning.

Despite the favorable ice conditions in this region we cannot exclude the possibility of drifting sea ice and icebergs. Taking into account the tendency of ice melting it is needed to maintain ice drift forecasting. Furthermore, polar low pressures and sea spray icing are important operational and design considerations.

An analysis of existing technical solutions and facilities gives ideas for creating extraordinary and sophisticated oil and gas centre(s) in the Barents Sea region.
The Kara Sea Offshore as a Strategic HC Recourse Base in the 21st Century-Possible Solutions of Developing According to the Estimate of the Economy Uncertainties by Fuzzy Theory
Authors: Bulakh Maria , Zolotukhin A. B. , Gudmestad O. T.
Published: December 2011

Huge reserves of hydrocarbons at the Kara Sea offshore region which is adjacent to the west coast of the Yamal Peninsula are to be developed in the nearest years. This large oil and gas area has prospective resources about 56 trillion barrels of oil equivalents (boe). The Russia Federation has not other regions with similar concentrations of the undeveloped hydrocarbons. Creating this unique the Kara Sea gas production centre could provide in the years 2015-2030 a production at least 800 billion Sm3 of gas per year providing both domestic and external demand with this fuel. The paper presents the main problems and possible solutions of developing such a harsh region in the Arctic conditions.
Hindered Strength Development in Oil Well Cement due to Low Curing Temperature
Authors: Reinås Lorents , Hodne Helge , Turkel Mirkamil A.
Published: December 2011

This paper reports laboratory test results on early strength development of Portland Class G oil well cement slurries with different W/C ratio at ambient and low temperatures. One commercial slurry has been included for reference to industrial practices. The slurries have been cured and tested under laboratory conditions (+20°C) and at lower temperatures (+7°C, +4°C and 0°C) believed to be more representative of arctic and deepwater seabed conditions. Compressive strength development has been monitored using Ultrasonic Cement Analyser (UCA). The test results quantifies delayed initial setting and hindered development of compressive strength at low curing temperatures and with increasing W/C ratio.

In arctic subsea wellheads the curing condition for lead cement close to seabed will be low in temperature due to cooling from low seabed seawater temperatures. The time to reach 50 psi (0,345 MPa) compressive strength can be more than 24 hrs depending on the slurry temperature and its W/C ratio. Initial setting is delayed significantly with decreasing temperature and with increasing W/C ratio. Rate of compressive strength development is also significantly delayed with decreasing temperature and with increasing W/C ratio. Most lead cement systems used have a high W/C ratio. Typical time between cementing and connection of the BOP/riser in North Sea operations is 24 hrs. Once a subsea BOP/riser gets connected to a wellhead dynamic loading will start, resulting in movements of the surface casing relative to the conductor casing. This is a local effect concentrated to the upper part of the surface casing. If loading of the surface casing starts before the cement has developed ample strength, localized failure of the cement should be expected to occur.
Environmental Baseline Research in the Canadian Beaufort Sea
Authors: Pyc Cynthia , Fortier Martin
Published: December 2011

It is generally understood that hydrocarbon exploration in the circumpolar Arctic will increase in the coming years to meet growing global energy demands. Concurrent with consumer demand is an equally important obligation to demonstrate adequate environmental understanding and risk-based operations planning prior to conducting responsible exploration and development. This is particularly the case in sensitive, extreme and remote environments like the Arctic.

To demonstrate environmental knowledge and inform project planning and equipment selection early in the exploration drilling phase, BP Exploration in Canada collected environmental, geotechnical and geochemical data in the southern Beaufort Sea over two field seasons in 2010 and 2011. The research was conducted as part of the ongoing research effort of ArcticNet; an independent academic network of Canadian and foreign university and government scientists. From the Canadian research icebreaker CCGS Amundsen, a multi-disciplinary team of academic researchers and industry experts collected data on ocean circulation, chemistry and productivity; zooplankton, ichthyoplankton and benthos distribution, diversity and abundance; baseline contaminant levels in sediment and water; surface meteorology; ice properties and concentration; and marine mammal presence and movement. In addition, a significant geotechnical, geohazards and geochemical survey was completed using the hull-mounted sonars and coring equipment of the vessel.

The large amount of information collected is already informing operational plans related to drilling equipment, drilling design and environmental impact assessment. Key technical input includes ice-loads related to bearing capacity of drill systems; and sediment strength measurements input to anchoring and casing design. Geochemical analysis of piston cores collected during the field program has provided insights into the petroleum system of the area. Multibeam echosounder, high-resolution images of the sea floor are providing the accurate geohazards identification and understanding critical to safe well placement and design.

This paper describes how environmental data was obtained through industry-academia collaboration over two field seasons and how the data may input into oil spill trajectory modeling, cutting disposal modeling, environmental impact assessment, as well as mitigation and monitoring strategies.
Risks Management In Russian Offshore Geotechnical Prospecting
Authors: Kornishin Konstantin , Efimov Yaroslav
Published: December 2011

This paper presents a new approcah to risk essesment in offshore geotechnical surveys. A traditional deterministic method of time estimation needed for the survey can not be found satisfactory due to influence of uncertainties of different types, for example weather uncertainty and management uncertainty of the specific contractor. The proposed method of risk estimation is based on fuzzy logic and presents all uncertain values as fuzzy membership functions with high level of certainty.

The described methodology allows the client to choose a contractor in a situation when the client doesn’t have a long term joint experience with the contractor. It also allows the client to obtain a quantitative estimation of the work of contractor and to choose the most favorable start date for the survey.
The Oil Based Mud Formulation Improvement To Reduce ERD Drilling Risks In The Arctic Conditions
Authors: Voronin R.. , Valuev D.. , Korolev A..
Published: December 2011

One of the features of the drilling in YaNAO area is the long section of permafrost. This feature impacts on different technological processes of well constructing. Drilling fluid cools in the annular opposite permafrost without circulation in particular. This feature should be considered in the development of the mud program with oil based muds.

Non-aqueous based fluid is the drilling fluid of choice to drill ERD wells. They make it possible to drill long sections even with the unstable formations. But they have some features, such as quite high rheology and its temperature dependence. The oil-based mud formulation which allows to decrease temperature dependence of rheology was applied in April – July of 2011 on Yurkharovskoye field.

Lab research, extensive computer modeling and hydraulic simulations were performed to take into account temperature and pressure conditions of the north of YaNAO. Main features and results of the new OBM formulation field application are described. Comparative data of the rheology-temperature profiles of formulations used in other regions of Russia are presented in the paper.

The experience of new OBM formulation application in ERD drilling on Yurkharovskoe field provided in the paper can assist with planning and project execution of OBM implementation in Arctic areas.
Piltun Field PLT Results in Commingled-Reservoir Wells Drive Smart-Well Implementation & Field Redevelopment
Authors: De Wit Andre , Yakovlev Alexey , Sumrow Mike , Urazovskaya Oxana , Belonogov Andrey
Published: December 2011

The subsurface development and well intervention teams recently completed a campaign of five production logs (PLTs) in the extended reach and highly deviated production wells of the Piltun field. The challenges of running the PLT logs were considerable: 4,000 to 7,000 m long deviated wells, complex well trajectories, long tractoring intervals, risk of tool lift due to high oil and gas rates, high wellhead pressures of ~2000 psi, harsh winter conditions, the problem of hydrate formation on the wire and in the pressure control equipment when pulling out of hole. Despite these challenges, the logs were completed safely and revealed a number of surprises about production from these multi-reservoir commingled wells.

The logs revealed that major reservoir intervals, with excellent porosity and permeability development, were not flowing. Some lower completion intervals in these good quality reservoirs remained covered with completion brine and debris, while selective zones with high GOR development had dominated production from the wells. Prior to this learning, the team assumed production from the wells had followed a rate distribution profile matching permeability thickness (kh) distribution. The logs also revealed off-depth perforations in some cases, which may have contributed to productivity issues for those reservoirs.

The learning from the PLT logs has affected dynamic modeling history matching effort, influenced further field development plans, and has driven the need for workovers to install smart-well equipment in essentially all of the production wells drilled to date. Learning from the logs has also led the team to apply greater quality control and assurance to perforation operations, investigate the use of less damaging completion methods or perforation pills, and use smart-well equipment for newly planned development well completions.

This paper discusses the issues and challenges to further field development and how learning from the recent PLTs has affected this effort.
Key Lessons in Social Engagement and Impact Assessment in the Arctic
Authors: Southam Anne L. , Swanzey Kim R.
Published: December 2011

This paper presents lessons learned from recent case studies in Alaska and Greenland, and examines the steps for a successful social engagement and impact assessment strategy. These steps can be used to conduct impact assessment in Arctic conditions. The integrated approach presented herein complies with national and international guidelines, and addresses public expectation. Changing climate, improved technology and the demand for energy have ignited interest in Arctic oil and gas resources. Industry is challenged to address ecological risks, climate change, cumulative effects, impacts on subsistence, and community concerns through a successful impact assessment process. As a key requirement of national regulators, international finance institutions and other socially responsible investors, impact assessment sets the foundation for effective management of environmental and social performance. What defines successful impact assessment and social engagement in Arctic communities where there may be many uncertainties? An integrated approach recognizing the interdependence of society and the environment is paramount for facilitating an effective stakeholder engagement and impact assessment process.
Significant Production Improvement Through Effective Well and Reservoir Management On Sakhalin Energy's Astokh Area
Authors: Yambayev Marat F. , Foreste Kenny , Jones Malcolm Kevin , Brown David Archibald , Kovalevich Alexander Sergeevich
Published: December 2011

When improving field production, the traditional focus on drilling activity means that the benefits from effective Well and Reservoir Management (WRM) are often overlooked. Within Sakhalin Energy’s Astokh area, an integrated field management approach has realized significant oil gains with minimal well interventions.

When phase 1 of the Astokh development was completed in 2001, only seasonal production via an FSO was available. Associated gas was re-injected into the crest of the reservoir, leading to a secondary gas cap. When this caused gas coning in updip wells, oil production declined because the gas handling equipment limits were exceeded. Pressure maintenance wells in 2004 helped to minimise associated gas levels, but it was not until the Sakhalin Energy Phase 2 project came on stream in 2009 that year round export was available, allowing gas injection to cease. With the drilling rig not available until Q4 2011, the application of effective well and reservoir management was the only way to address the declining field production.

The primary focus was the depletion of the secondary gas cap. The first decision was to open high GOR updip wells whilst managing others through downhole shut-off / choking of zones. Secondly, water injection well volumes were optimized depending on levels of gas cap depletion in various areas of the reservoir. Thirdly, the reservoir model was regularly updated, reflecting gas cap behaviour seen through GOR levels in updip wells. Executing this approach required the gas compression facilities to operate at > 100% efficiency and put strain on the equipment, so a significant effort to maintain the reliability of the surface facilities was pursued.

Within a year of implementing this multi disciplinary approach, three wells more than doubled their oil production rates.
Differentially-normalized Method of Electroinvestigation (DNME) - An Efficient Instrument for HC Exploration Off- and Onshore
Authors: Legeydo P. Y , Ageenkov E. V.
Published: December 2011

Considerable costs of onshore and offshore wells drilling require effective geophysical methods of HC deposits exploration and study. One of such methods is DNME dealing with conductive and polarization medium properties.

In some cases electrical resistivity can indicate HC presence in reservoir that have increased resistivity or water having reduced resistivity. Polarizable medium properties alter in presence of HC. Such alterations are observed to the first regional confining layer, which typically occurs at depth to 1000m. Hence studying medium polarization properties HC occurrence can be detected even at relatively small depth.

DNME exploration is conducted both off and onshore. Horizontal electric lines are used as the source and the receiver of the electromagnetic signal. At marine exploration electric field potential differences of the first and second order are registered at several spans. Offshore measurements are carried out on the move of a vessel.

At that inductive sounding based on skin-effect is combined with induced polarization (IP) based on the geometric principle. Combined inversion of measurements on several spans allows studying distribution along with conductivity depth and polarization properties of geological environment.

In order to obtain quality electromagnetic data the series of measuring techniques was developed. Digital filtration also significantly increases S/N ratio.

Onshore and offshore DNME explorations are carried out all over the world: shelves of Sea of Okhotsk and Barents Sea, Caspian Sea, Sea of Azov, Baltic and Caribbean Seas, Gulf of Ob and Tar Bay, Volga-Ural Timan-Pechora, West Siberian, East Siberian, Peri-Caspian, Baltic, North-Caucasian oil-and-gas provinces, China, Cuba, Peru.

One of the examples of successful DNME usage offshore is the exploration in Barents Sea (Severo-Gulyaevskoye field). Technique of induction (EM) and IP fields' separation in the whole measuring range allowed to map deposit’s contour occurring in IP field. Geoelectric modeling showed polarizability coefficient increase in deposit's contour at depth complying to regional confining layer. According to well testing data this depth interval (500-600 m) contains high concentration of epigenetic pyrite. The same is observed directly above the oil-saturated reservoir at depth around 2500.
Basic Principles Underlying Permanent Scientific Support of Complex Field Development
Authors: Timchuk A. S. , Sokolov S. V. , Sunagatullin A. F.
Published: December 2011

Scientific and technical support of fields in the complex environment requires a unique approach for each field. Most of the new projects of TNK-BP, one way or another, are associated with extreme conditions, complex geological structure, lack of infrastructure and, therefore, higher investment risks. In recent years, TNK-BP has successfully brought a number of Uvat Project and Eastern Siberia fields into development (Urna, Ust-Tegus, Verkhnechonskoye). Besides, active work on future Yamal projects (Russkoye, SuzunϬ and other assets) is in progress.

The article describes the main methods used for scientific support for the development of the Company’s new projects. The main challenges of Uvat project, i.e. the remoteness from infrastructure, marshland, and poor predictability of net pay thicknesses, have been successfully solved by drilling of super-pads with big step-outs, up to 3 kilometers, and continuous support of drilling using geological and hydrodynamic models. The uniqueness of Verkhnechonskoye field is in very low temperatures, salinization, and high heterogeneity of reservoirs. The geological conditions are complicated by geography, i.e. Eastern Siberia is a new development area. The field is drilled out by horizontal wells using geosteering and detailed geological and hydrodynamic models. Russkoye and Suzun fields are, in fact, in arctic conditions, reservoir evaluation is made using a unique approach to modeling. The experience received in the process of development of such fields can be used in more extreme conditions of the Arctic Region, Yamal, and East Siberia.
Approach for Full Field Scale Smart Well Modeling and Optimization
Authors: Khrulenko Alexey , Zolotukhin Anatoly B.
Published: December 2011

Smart (or intelligent) well is a well equipped with downhole sensors and downhole valves to control fluid inflow from the separated perforated intervals towards well, in real-time mode and without well interventions, to optimize production.

The advantages of smart wells can be briefly comprised in the following four points: reduction of operational expenses;increased oil production;improved oil recovery;mitigation of the geological uncertainty impact on the project performance.

But disadvantages of smart well technology, that derive from its technical complexity, restrict a scale of its deployment. These disadvantages can be summarized as follows: High cost;Risk of the valves and sensors failures;

Thus, three questions must be addressed while screening possible smart well deployment: How to estimate the value added by smart completion?How to control smart well completions in order to gain the maximal effect?How to estimate possible losses in production due to ICV failures?

A lot of publications were addressed to these problems in recent years. Majority of researchers used reservoir simulation as the main tool. Within the frameworks of such a concept a reservoir model impersonated both a real field and its reservoir model and was used for optimization. This work, on the one hand, partly adopts these approaches and, on the other hand, suggests the optimization strategy in full field scale based on subdivision of the initial big task into several ones with smaller dimension that require less time for the evaluation. Optimization routine is based on using commercial reservoir simulator coupled with Matlab-based program controller that optimizes downhole valve settings by using Direct Search optimization routine and imitates valves failures. The introduced optimization routine has been tested on multiple realizations of generic reservoir model always showing good performance and the added value.
New Approaches to Improve Economical Efficiency of Development of Gas-Condensate Reservoirs with Thin Oil Rims
Authors: Yushkov A. Y. , Romanov A. S. , Mukminov I. R. , Ignatiev A. E. , Romashkin S. V. , Buchinsky S. V. , Glumov D. N. , Magdieva L. K.
Published: December 2011

Using BU161-4 formation of the Urengoy oil and condensate field deposit as an example the authors have demonstrated that today in the absence of developed transport infrastructure high CAPEX and OPEX investments are inevitable. It will result in negative economic results in developing oil banks in gas and condensate deposits located in the Northern and Polar regions of the Russian Federation. This factor decreases attraction of such assets for investors significantly and actually oil reserves in oil banks and gas reserves in gas caps are not developed and it is uncertain when these reserves might be developed. As a result the state will get less revenue from developing hydrocarbon reserves.
Design and Field Practice of Arctic Cement Systems Applied for Well Construction in Permafrost Zones
Authors: Korostelev A. S.
Published: December 2011

The requirements to improve the quality of well cementing in permafrost zones stipulate the application of unconventional multicomponent cement systems with proper technological characteristics (freeze-thaw durability, zonal isolation, short set times), which do not lose their properties during long-term storage periods in cold open-air conditions.

The new cementing systems are being introduced in the given article; they are plug-and-play non-gypsum blends of base cement and lightweight, stabilizer, expanding additives.

The results of laboratory researches and field application practices of such cementing systems in Yamal fields of Russia are being described in this paper.
The Vibration of Fixed Offshore Structures under Ice Action
Authors: Shkhinek Karl , Zhilenkov Alexander , Thomas Graham , Gebson Richard
Published: December 2011

Ice induced vibration of fixed offshore structures has been observed in different seas, for example: Beaufort Sea, Cook Inlet, Gulf of Bothnia, Bohai Bay, Sea of Okhotsk. It can have a significant impact, as it may lead to failure due to structural fatigue (Bohai Bay) or softening of foundations, or cause problems with the serviceability of platforms. Possible future arctic developments will be in deeper water, where the phenomenon of ice induced vibration may be one factor limiting the maximum water depths for the economic use of fixed (bottom-founded) structures. Therefore it is important to be able to predict the responses of structures of different shapes and sizes to the ice conditions specific to the region of interest, in order to optimize development options.

A 2D solution for the numerical study of ice induced vibration of vertical-sided fixed offshore structures based upon common assumptions and mathematical models of ice properties has been developed by St. Petersburg State Polytechnical University and BP. The solution considers the whole process of vibration as it develops in time: successive ice failure, structural response and mutual ice/structure interaction. The model has been applied in order to understand the environmental conditions and structural characteristics that are important to the incidence of ice induced vibrations.

Ice induced vibration of fixed offshore structures has been observed in different seas, for example: Beaufort Sea, Cook Inlet, Gulf of Bothnia, Bohai Bay, Sea of Okhotsk. It can have a significant impact, as it may lead to failure due to structural fatigue (Bohai Bay) or softening of foundations, or cause problems with the serviceability of platforms. Possible future arctic developments will be in deeper water, where the phenomenon of ice induced vibration may be one factor limiting the maximum water depths for the economic use of fixed (bottom-founded) structures. Therefore it is important to be able to predict the responses of structures of different shapes and sizes to the ice conditions specific to the region of interest, in order to optimize development options.

A 2D solution for the numerical study of ice induced vibration of vertical-sided fixed offshore structures based upon common assumptions and mathematical models of ice properties has been developed by St. Petersburg State Polytechnical University and BP. The solution considers the whole process of vibration as it develops in time: successive ice failure, structural response and mutual ice/structure interaction. The model has been applied in order to understand the environmental conditions and structural characteristics that are important to the incidence of ice induced vibrations.
Control of Gathering and Transport System for Multiphase Product on Russian Arctic Continental Shelf
Authors: Papusha A. N. , Nankin A. A.
Published: December 2011

Flow assurance is an engineering analysis process to assure hydrocarbon fluids are transmitted economically from the reservoir to the end user over the life of a project in any environment.

The term "Flow Assurance" was first used by Petrobras in the early 1990s, it originally only covered the thermal hydraulics and production chemistry issues encountered during oil and gas production. While the term is relatively new, the problems related with flow assurance have been a critical issue in the oil/gas industry from very early days. Hydrates were observed causing blockages in gas pipelines as early as the 1930s.

Another problem is slugging and liquid handling. The occurrence of slug flow in a transportation pipeline and a gathering system can cause many problems in design and operation processes, which include kinetic force on fittings and vessels, pressure cycling, control instability and inadequate phase separation. Slugging affects greatly the design of receiving facilities. In gas condensate systems, larger lines result in more liquid being retained in the pipeline at low rates. When the flow rate is increased, much of the liquid can be swept out, potentially overwhelming the liquid handling capability of the receiving facilities. The facilities can be flooded and damaged if the slugs larger than the slug catcher capacity. Therefore, quantifying the slug size, frequency and velocity is necessary prior to equipment design.
Can the Onset of Macropore Flow be Detected using Electrical Resistivity Measurements?
Authors: Moysey Stephen M.J. , Liu Zuolin
Published: December 2011

This study evaluated whether electrical resistivity monitoring could be used as a tool to detect the activation of macropores in soils. Experiments were performed where soil resistivity was measured using a Wenner array while individual soil macropores were sequentially saturated to simulate changes in macropore activation in a hydrologically active soil. The measured apparent resistivity was found to be highly dependent on the activated macropore porosity. An increase in macropore porosity from 0 to 4% decreased the apparent resistivity of the soil by up to 30%. A simple two‐domain model was developed to evaluate the controls on apparent resistivity in a macroporous soil by conceptualizing the macropores as fluid‐filled tubes embedded within a homogeneous soil matrix. The model qualitatively reproduced the trends of the observed data and provided reasonable bounds on the expected response of soils, suggesting that it captures first‐order influences of macropores on apparent resistivity measurements. The model indicates that the magnitude of the reduction in apparent resistivity is strongly dependent on the contrast in resistivity between the soil (ro) and macropores (rm), which can be readily estimated in field monitoring scenarios. The ro/rm ratio is therefore suggested as a useful diagnostic for evaluating conditions where changes recorded in resistivity monitoring data might be used to detect the onset of macropore flow in field‐based studies.
Bioavailable Phosphorus in Fine‐Sized Sediments Transported from Agricultural Fields
Authors: Poirier Simon-C. , Whalen Joann K. , Michaud Aubert R.
Published: December 2011

Sediments transported from agricultural fields in surface and subsurface waters contain particulate P (PP) that could be partitioned into two pools—one available for aquatic organisms including cyanobacteria, namely bioavailable particulate P (BAPP, determined by 0.1 mol L−1 NaOH extraction), and the remainder not bioavailable (non‐BAPP). This study aimed to quantify the PP and BAPP concentrations in surface runoff and tile drainage water from eight agricultural fields with clay and sandy soils in the Missisquoi Bay region of Quebec, Canada. Particulate P in surface and drainage water varied spatially (among fields) and temporally, with concentrations as high as 3181 μg P L−1 in surface runoff and 1346 μg P L−1 in tile drainage. About 30% of PP was BAPP regardless of the drainage pathway. The PP and BAPP concentrations were related linearly (R2 = 0.86) to total suspended solids (TSS) in fine (0.05–1‐μm) and coarse (1–100‐μm) fractions. About 68% of the PP in clay soils and 50% of the PP in sandy soils were associated with the 0.05‐ to 1‐μm size particles, which had more BAPP, on average 0.46 g P kg−1, than the coarser 1‐ to 100‐μm fraction (0.22 g P kg−1). Soil parameters such as Mehlich‐3 extractable (M3) P, M3Fe, and the degree of soil P saturation were related to the PP and BAPP concentrations in TSS and particle size fractions. We concluded that sediments with particle size <1 μm contained more BAPP and their loss from agricultural fields could contribute to the eutrophication downstream.
Effect of Moisture Content on Prediction of Organic Carbon and pH Using Visible and Near‐Infrared Spectroscopy
Authors: Tekin Yucel , Tumsavas Zeynal , Mouazen Abdul Mounem
Published: December 2011

This study was undertaken to investigate the effect of moisture content (MC) on the prediction accuracy of soil organic C (SOC) and pH of soils collected from Turkey and the United Kingdom using a fiber‐type visible and near infrared (Vis‐NIR) spectrophotometer. The diffuse reflectance spectra of 270 soil samples were measured under six gravimetric MC levels of 0, 5, 10, 15, 20, and 25%. Partial least squares (PLS) regression analyses with full cross‐validation were performed to establish models for SOC and pH. Before PLS analysis, the entire spectra were randomly split three times into calibration (80%) and validation (20%) sets. Results showed that the prediction performance of SOC in the validation set was successful, with root mean square errors of prediction (RMSEPs) of 1.26 to 1.55% and residual prediction deviations (RPDs) of 2.29 to 2.83, and rather poor for pH, with RMSEPs of 0.65 to 0.85 and RPDs of 1.29 to 1.65. The best accuracy achieved for SOC was for dry soil samples (RMSEP = 1.26%, RPD = 2.83), whereas the worst accuracy was for wet soil samples with 5% MC (RMSEP = 1.55%, RPD = 2.29). The best result for pH was obtained for dry samples (RMSEP = 0.70%, RPD = 1.65), although this accuracy was comparable to that of the 10% MC soil samples (RMSEP = 0.65%, RPD = 1.60). The ANOVA supported the conclusion that there was a significant effect of MC on prediction accuracy, although this effect was larger for SOC (P < 0.0000) than pH (P < 0.05).
Unsaturated Hydraulic Conductivity of Repeatedly Layered Soil Structures
Authors: Zhu Jianting , Warrick A. W.
Published: December 2011

This study examines the appropriateness of the harmonic mean function of unsaturated hydraulic conductivities in representing structured heterogeneity for a finitely deep profile typical of many applications such as water fluxes between the ground surface and saturated zone. The heterogeneity is constructed by forming repeated unit cells of homogeneous sublayers. We address the significance of water flux (both infiltration and evaporation), structural arrangement and compositional fraction within the unit cell, and number of repeated units on the applicability of the harmonic mean function in simulating fluxes through heterogeneous layered media. We demonstrate that both structural location and the fraction of coarse material in the unit cell are important indicators of whether the harmonic mean function will over‐ or underpredict fluxes. The harmonic mean function represents infiltration fluxes better than evaporation in layered heterogeneous soils. Under the evaporation scenario, the errors from using the harmonic mean function generally decrease with increasing coarse layer fraction. On the other hand, the errors generally increase with increasing coarse layer fraction for the infiltration scenario. As the number of layers becomes large, the fluxes through the heterogeneous layered soils converge to the flux predicted by the harmonic mean function; however, the convergence is from opposite directions for evaporation and infiltration.
Solute Diffusivity in Undisturbed Soil: Effects of Soil Water Content and Matric Potential
Authors: Laegdsmand Mette , Moldrup Per , Schjønning Per
Published: December 2011

Solute diffusivity in soil plays a major role in many important processes with relation to plant growth and environmental issues. Soil solute diffusivity is affected by the volumetric water content as well as the morphological characteristics of water‐filled pores. The solute diffusivity in intact soil samples from two different tillage treatments (soil from below the depth of a harrow treatment and soil from within a moldboard plowed plow layer) was estimated based on concentration profiles using a newly developed method. The method makes use of multiple tracers (two sets of counterdiffusing tracers) for a better determination of the diffusivity. The diffusivity was higher in the below‐till soil than the plowed soil at the same soil water matric potential due to higher water content but also due to higher continuity and lower tortuosity of the soil pores. We measured identical solute diffusivities independent of the tracer set used. We analyzed the whole data set using Archie's law and found a linear relation between Archie's exponent and the logarithm of the soil water matric suction in centimeters of water (pF). An analysis of seven data sets from the literature showed that this was a general trend for soils with moderate to low clay contents.
Iron(III) Coordination and Phosphate Sorption in Peat Reacted with Ferric or Ferrous Iron
Authors: Morris Amanda J. , Hesterberg Dean L.
Published: December 2011

The molecular bonding configuration of Fe(III) associated with organic matter (OM) in soils potentially affects its binding affinity, reducibility, mobility, and interactions with other cations and anions. Given that Fe(III) can be incorporated into soil OM either directly as Fe(III) or through oxidation of Fe(II), the coordination and reactivity of OM‐associated Fe(III) may depend on soil redox conditions. Our objective was to determine if the molecular coordination environment and phosphate sorption characteristics of OM‐associated Fe(III) depend on the pathway of Fe(III) incorporation. Pahokee peat soil material was reacted at pH 2.5 with either Fe(III) or Fe(II) at 300, 900, or 1200 mmol Fe kg−1 peat, equilibrated at pH 6.8 and oxidized. Extended x‐ray absorption fine structure and wavelet transform analyses indicated the presence of mononuclear Fe(III) coordinated with organic ligands in all samples along with polynuclear Fe‐hydroxide species at higher concentrations. The pathway of Fe incorporation did not significantly affect its local coordination environment or phosphate sorption isotherms. Our results suggest that OM‐associated Fe(III) formed under oxidized or reduced soil conditions would have similar molecular‐level coordination and be equally accessible for phosphate sorption.