bluuebunny/crossref_metadata_2025 huggingface dataset:
Analysis of Potential Conservatism in Foundation Design for Offshore Platform Assessment
Authors: Gilbert Robert B. , Chen J.Y. , Materek B. , Puskar Frank , Verret S. , Carpenter J. , Young Alan G. , Murff James Donald
Published: July 2010

There is a common perception that the design method for pile foundations in offshore platforms is conservative. However, we found no direct evidence of excessive conservatism in detailed analyses of thirteen case study platforms where the foundation systems were loaded to near or beyond their capacities. In eight cases, the foundation systems, including piles and well conductors, survived as they were predicted to do. In the one case we do have of a foundation failure occurring in a hurricane (a pile pull-out failure in clay), the failure was predicted. In two cases, the survival in a hurricane is consistent with realistic (not conservative) assumptions for the lateral capacities of piles and well conductors. In the last two cases, a potential overturning failure of the foundation system was predicted but not observed, most likely due to the lack of a site-specific soil boring to predict foundation capacity. Due to the small number of cases analyzed, these results do not preclude the possibility of foundation capacities being greater than expected based on design, particularly for piles tipping in sand layers.

The perception of conservatism appears to be related to the common analysis methods used by the offshore industry. The assessment of existing foundations is different from new design and needs to be treated accordingly. Recommendations to improve the practice of platform foundation assessments include the following:When the foundation controls the assessment, include a geotechnical engineer familiar with platform assessments on the analysis team.Include well conductors and jacket leg stubs realistically and explicitly in the structural analyses.Consider using average rather than nominal yield strength for steel piles and well conductors.Use static versus cyclic p-y curves for lateral soil resistance.Be careful in specifying the input parameters for sand layers.Be careful when relying on a soil boring that was not drilled at the location of the platform or was not drilled using modern methods of sampling and testing, particularly when sand layers are present.Try to obtain pile driving records as well as soil boring logs to help estimate axial pile capacities.When the pile foundation system is governing the capacity of the platform in a pushover analysis, check the sensitivity of the foundation system capacity to the lateral and axial capacities of the piles independently.Do not arbitrarily increase the shear strength of the soil to account for perceived conservatism in foundation design.Provide specific guidance for characterizing pile foundations in platform assessments into a code format suitable for the American Petroleum Institute Recommended Practices.

In the future, detailed analyses of platforms that were destroyed by hurricanes could provide valuable information about how pile systems and the jackets they support performed under extreme loading conditions.
Recent Advances in Development and Application of Wide Azimuth Seismic Technology
Authors: Summers Tim , Michell Scott , Barley Brian James , Foster Mark
Published: July 2010

The proportion of deepwater acreage in oil company portfolios increased considerably over the past decade. New subsurface imaging challenges were encountered and required technology breakthroughs to meet business objectives. In many of these deepwater areas, the imaging challenges were increased due to complex overburden that distorted the seismic signal at the reservoir. Additionally, the requirement to extract more resources from mature basins put increased demand on seismic data quality requirements for field development and production.

Conventional narrow azimuth marine seismic acquisition was reaching a technical limit in these environments and new approaches were necessary. Both towed streamer and ocean bottom seismic solutions were required to improve reservoir imaging along the value chain, from exploration to production and from shallow to deep water. Wide azimuth techniques, combined with state of the art processing, velocity modeling and depth migration became the tools of choice for seismic surveying to address the emerging subsurface imaging challenges Success in field trials led to early business uptake. New technology development, both in acquisition equipment and processing algorithms, combined with innovations in survey design and operational efficiency, enabled at-scale implementation. As a result, the last five years has seen considerable wide azimuth data coverage in some major marine basins by both operators and contractors. The momentum continues to build with the increased use of wide azimuth methods opening up new opportunities and spurring new technology development.

Introduction

Since 2005 there have been significant developments in marine wide azimuth seismic acquisition which are applicable to a range of subsurface imaging challenges across the value chain from exploration to production. BP has been an industry leader in this area of technology across a spectrum of activity as described by Barley & Summers (2007). At-scale field trials of towed streamer and ocean bottom techniques over fields in a number of basins proved the concept of new robust acquisition designs. This led to widespread application of these methods and enabled illumination of reservoirs previously invisible using conventional methods.

The ability to model and analyse cost effective and appropriate acquisition designs along with learning from application has developed considerably in recent years. As such, the scale of implementation across the industry has had considerable business impact. The key to effective usage is the ability to understand the relative merits of different acquisition techniques to a particular business problem and evaluate parameterization for that situation.
SS: FPSOs and Floating Production Systems: The Monitas system for the Glas Dowr FPSO
Authors: Aalberts Pieter , van der Cammen Jeroen , Kaminski Miroslaw Leck
Published: July 2010

The paper is one of five papers about the Advisory Monitoring System (AMS) for controlling the fatigue lifetime consumption of FPSO hulls. The system has been developed within the Monitas Joint Industry Project (JIP) and is referred to as the Monitas system. The name Monitas stands for Monitoring Advisory System. The paper describes the Monitas system developed, installed and running for two years on-board the Glas Dowr FPSO operated by Bluewater Energy Services (BES) at the Sable field, offshore South Africa. The paper describes how the Monitas system advises on fatigue lifetime consumption based on the fatigue design data, fatigue design tool and the monitoring data of hull girder loads, global and local stresses, wave frequency motions, ship's loading condition and heading, and the environmental conditions. The paper concludes that contrary to conventional structural health monitoring systems, estimating the actual fatigue lifetime consumption, the Monitas system can explain potential deviations from the design assumptions. In this way the Monitas system provides designers with feedback about the quality of their design tools and made assumptions, and advises the FPSO operators on actions required to ensure a safe operation and, if needed, can be used to justify lifetime extension.

Introduction

Hull fatigue of FPSOs is an important design consideration which has been addressed in several Joint Industry Projects (JIPs) in the last two decades. In the late 90s, hull fatigue was investigated in the FPSO Integrity and FPSO Capacity JIPs. The FPSO Integrity I and II JIPs were headed by MARIN and their aim was to investigate the fatigue loading on an FPSO hull. For this purpose, BES's FPSO Glas Dowr (see Figure 1), at that time located at the Durward & Dauntless field at the UKCS, was instrumented with an extensive measurement system to collect data on hull loading. An extensive overview of this JIP and the monitoring system are given by Bultema (2000) and Boom van den (2000). The FPSO Capacity I and II JIPs were led by DNV and their main aim was to investigate and develop methodologies to describe the fatigue capacity of typical FPSO structural hull members. An extensive overview of these JIPs can be found in Lotsberg (2000). Although a lot of knowledge was acquired in these JIPs, additional development was needed in the FPSO Live JIP, which was led by BES in cooperation with MARIN and DNV. This JIP developed a hull fatigue calculation procedure in the time-domain and investigated a minimum monitoring system, i.e. the minimum amount of sensors required to derive fatigue loads on the hull of an FPSO.
SS: Perdido Development Project: Great White WM12 Reservoir and Silvertip M. Frio Field Development Plans and Comparison of Recent Well Results with Pre-Drill Models
Authors: Eikrem Vern , Li Ruijian , Medeiros Michael , McKee Bryce J. , Boswell Betsy Lorene , Shumilak Edward E. , Mohan Raj
Published: July 2010

The Great White and Silvertip Fields are located in the southern Alaminos Canyon area of the far western Gulf of Mexico. Shell is the operator of the Great White and Silvertip Fields. Along with Shell, Chevron and BP are the Great White JV partners. Chevron and Shell are JV partners in the Silvertip Field.

This paper will provide an overview of the current Great White Field WM12 reservoir development plan, will compare the results of the recent six development wells with the pre-drill predictive model, and the impact of the well results on our understanding of this frontier area, Paleogene age reservoir. In addition, excellent results in two horizontal wells drilled in the Silvertip Field shallow M. Frio reservoir are also highlighted along with the well construction challenges in drilling and completing them.

Oil in the Great White Field WM12 Sand reservoir is trapped in a large, highly faulted anticlinal structure. A high-resolution 3D seismic survey shot over the field has enabled us to map this structurally complex field reservoir in detail, identify hundreds of faults, and estimate reservoir thickness and quality away from sparse exploration and appraisal well control.

The Great White JV partnership plans a staged development of the WM12 Sand reservoir. Staged development of this frontier area, ultra-deepwater field mitigates the downside production risk associated with Great White's structural uncertainty, the scarcity of well data, the lack of reservoir production data, and the potential for reservoir compartmentalization due to sub-seismic faulting and / or stratigraphic barriers to flow.

Development drilling at Great White began in 2007 and to-date six pre-drill wells have been drilled and completed prior to first oil. Well results drilled prior to first oil at the Perdido Spar and at the subsea Southwest Cluster locations are in-line with our pre-drill expectations and so far, have confirmed our large estimated oil-in-place volume in the WM12 Sand reservoir in the field.

The M. Frio oil reservoirs at Silvertip Field are located in shallow M. Frio canyon-fill sands. The M. Frio is relatively unconsolidated and contains high viscosity, heavy oil. Because the M. Frio reservoirs are relatively shallow, drilling margins are very low and the wells push the boundaries of extended reach drilling. With detailed planning, we have been successful in drilling and completing these long horizontal wells and had better than expected well results.
Directional Casing While Drilling (DCwD) Heralds a Step Change in Drilling Efficiency from a Producing Platform
Authors: Dawson Graeme , Buchan Andrew , Kardani Ilen , Harris Andrew , Wercholuk Lonnie , Khazali Khairul Amir , Sisson Keith , Halim Abdul , Hermawan Heru
Published: July 2010

Directional casing while drilling (DCWD) utilizing a rotary steerable system or a steerable positive displacement motor is a recent enabling technological application of proven casing while drilling. DCWD has been successfully applied in wells in the North Sea and Middle East using both rotary steerable systems and PDMs, proving up its operational reliability. The technology has most recently been utilized in a project from a producing platform in the Asia Pacific region. While this DCWD application increases the challenges of directional drilling, the project was completed successfully in terms of increasing ROP and lowering the time and cost to drill the top hole section of the well.

Top hole directional drilling of wells in high density locations such as multi-well producing platforms require carefully planned, detailed procedures and reliable techniques to result in a safe and efficiently drilled wellbore. The procedure, in addition to directional capabilities, requires that the well meet the demands of anti-collision concerns within the torque and hydraulic operating parameters of the formation. The drive for continuous improvements led the field operator to choose DCWD technology to deliver step changes in drilling performance while meeting the company's strict operational and safety directives.

The successful effort was a carefully planned and implemented operation that required the close cooperation of the operator, directional drilling company and drilling contractor during the entire procedure. This close interaction between all parties led to three world records and the world's first application of another enabling technology, including:World's deepest 13 3/8?? DCWD job;World's highest angle directional well with 13 3/8?? DCWD;World's fastest rate of penetration for a 13 3/8?? DCWD;World's first application of Gyro MWD with DCWD.
SS: Perdido Development Project: World
Authors: Snyder Dale , Townsley Bill
Published: July 2010

The Perdido Development Project is an ultra-deep water development of the Great White, Silver Tip and Tobago fields in the remote southwestern Gulf of Mexico (Figure 1). Perdido will be the first to produce from the Lower Tertiary (Paleogene) geologic setting in the Gulf. Moored in 7817 feet (2,382m) of water in Alaminos Canyon Block 857, the spar host will be the world's deepest drilling and production facility. In 9627 feet (2,934m) of water, the Tobago subsea oil well will be the deepest producing well in the world. This paper will provide an overview of the Perdido project, discussing the challenges that had to be overcome and the innovations that had to be developed to successfully deliver the project.

Perdido Development facilities (Figure 2) consist of:Truss spar with light weight, " single-lift?? topsidesSix-slot, wet-tree, direct vertical access (DVA) well system with a full capability drilling rig34 subsea wells including the 22 DVA wells under the sparAll production commingled on the seafloor, gas separated from liquids and liquids pumped from the seafloor up to the spar hostThroughput: oil 100 mbopd, gas 200 mmscfd, water 40 mbwpd, water injection 80 mbwpdOil and gas export pipelines

The significant challenges to delivering Perdido fell into the categories of safety, the need for new technology and low cost solutions, and overcoming overheated market conditions. With all of the many difficulties to be overcome, the team committed itself early in the project to intensely focus on safety as the highest priority. The result has been both outstanding project execution safety performance across many locations and in the raising of the bar of how safety is incorporated into platform designs. As to the technical and cost challenges, Perdido's difficult reservoirs, high well count and ultra-deep water made the development uneconomic with conventional deepwater technologies. To produce the wells, reduce the size of the host and reduce the cost of development, an innovative system of new technologies was required, consisting primarily of wettree, direct vertical access (DVA) wells with a Subsea Boosting System. Sanctioning and executing the project during one of the industry's most overheated markets created numerous cost, quality, resourcing and delivery problems, requiring extraordinary effort from the project team and contractors to keep the project on track.
SS: Perdido Development Project: Surveillance & Operations Technology
Authors: Purdy Gill E. , Littell Howard Steven , Lajeunesse Susan , Coulon Todd , Durham Kevin , Lee Amanda
Published: July 2010

- Description

Operating in the ultra deep-water environment at Perdido (7800-9200 ft) makes Surveillance readiness essential on this complex, technologically challenging asset. Early work on integrated production system modeling, an operations training simulator, ESP surveillance tools, collaborative work environments, remote accessibility, and real time interactive process data trending have enabled an accelerated learning pace for Perdido. This paper will communicate the efforts required to successfully meet this ultra deepwater challenge during the early field development and startup. This work has been completed by Shell on behalf of the Perdido joint venture partners Chevron & BP.

- Application

Surveillance & Operational technologies developed for this deepwater environment will allow for the smooth startup of the Perdido Field and for the collection of critical reservoir data needed for further field development. This technology can be applied to other deepwater fields to optimize field startup while gathering critical early surveillance data and minimizing the number of personnel required on location.

A process simulator was used to simulate field operations and to interface with the actual control system. It synthesized realistic responses to Operator inputs for training & scenario trouble shooting purposes.

- Results, Observations and Conclusions

Due to the Operational challenges at Perdido, staffing for an Operational Readiness team was started 4 years prior to first oil. This team has grown over the years and was fully staffed around 6 months before startup. Their job was to develop the operating procedures & manuals for Perdido, and then train the team how to start up & operate the field. Similarly, staffing for the Engineering Surveillance team began 24 months before first oil and was completed 12 months before startup. The team's job was to build the systems, procedures, & collaborative processes that would be required for a smooth startup & surveillance of Perdido. All these technologies & detailed planning should result in the smooth & flawless startup of Shell's first Spar platform in the ultra deepwater.

- Significance of Subject Matter

Ensuring that Operations personnel are properly trained to operate the field is imperative for a smooth startup of Perdido. In addition, proper preplanning & training will be critical for startup & ramp up of the Perdido field.
Deepwater Mooring Systems - Advances in Connector Technology and Implementation Practice
Authors: Green Brian
Published: July 2010

The time has come for dedicated deepwater mooring systems that accurately reflect the practical and technological demands of deploying mooring systems beyond 10,000ft (3,000m). This paper describes how new developments in mooring connector design and polyester ropes will provide operators with dedicated deepwater mooring systems.

Installing long-term, deepwater moorings for spars, floating production units, FPSOs and their associated Submerged Turret Production (STP) / Submerged Turret Loading (STL) Buoys is proving to be increasingly time-consuming and costly, as mooring equipment and practices developed for shallow water are applied to deepwater environments.

The paper will review the elements of deepwater mooring with particular reference to the integrity of deepwater mooring connectors and the excessive complexity of mooring line interconnectivity, resulting in increased installation times and vessel costs. In addition, it will report on developments in mooring line and connector technology that are designed to improve the engineering integrity of rope connectors and the application of ‘lean installation’ practices to deepwater mooring line deployment.

Introduction

There is a need for dedicated deepwater mooring systems that accurately reflect the practical and technological demands of deploying mooring systems beyond 10,000ft (3,000m). Deepwater is defined as water depths greater than 1,000ft (305m), and ultra-deep water is water depths greater than 5,000ft (1,524m).

Recent deepwater mooring projects such as SBM Atlantia's Thunder Hawk Floating Production Unit (FPU) moored in 6,050ft (1,800m) of water (Fig. 1), and Shell's Perdido Truss Spar Development project in the Gulf of Mexico, moored at a depth of 8,637ft (2,632m) are part of the growing trend in deepwater and ultra deepwater production in the Gulf of Mexico (GoM). In 2010 the first deepwater FPSO in the GoM will be deployed in the Cascade-Chinook fields, with a submerged turret production buoy moored in 2,500m of water.

As moorings go deeper, so issues surrounding the mechanical and practical demands on the design and deployment of mooring systems are coming to the fore. Installing long-term, deepwater moorings is proving to be increasingly time-consuming and costly, as mooring equipment and deployment practices developed for shallow water are applied to more demanding deepwater environments.

Deepwater Exploration, Development and Processing

The trend towards deepwater exploration and processing is gaining momentum, in the search for new oil and gas fields. The US Department of Interior's Minerals Management Service (MMS) believes there is more than 50 billion recoverable BOE still to be discovered in both GoM deepwater and ultra-deepwater regions.
Revisiting the Subsalt Trap Archetype Classification Scheme After Eight More Years of Gulf of Mexico Subsalt Drilling
Authors: Hart Bill , Albertin Martin L.
Published: July 2010

Subsalt exploration in the Gulf of Mexico (GOM) remains an area of intense focus by the oil and gas industry. Successfully accessing economic hydrocarbon accumulations beneath the extensive allochthonous salt sheets in the northern GOM basin requires solving a number of geophysical, geological, and drilling challenges. In 2001, Hart and Albertin presented a geological tool which, given imaging challenges associated with complex allochthonous salt, could be used for qualitatively ranking subsalt exploration prospects according to their structural attributes.

The ranking scheme proposed by Hart and Albertin is comprised of a collection of subsalt trap archetypes, each archetype representing an important structural variation with specific trap merits and risks. These archetypes are grouped into four genetic play families, calibrated for overall prospectivity by a statistical analysis of subsalt well success rate. The statistical analysis in 2001 used a database of 69 subsalt wells; since then, at least 122 new subsalt traps have been drilled by the industry. We used this new subsalt well data to revisit the classification scheme and answer a few specific questions: does the trap family priority hold up given the subsalt successes and failures of the past eight years, do the original archetypes still represent the full range of observed salt styles, and are any revisions to the classification scheme warranted?

At a high level, the subsalt trap family prioritization still holds. All but two of the 45 new subsalt discoveries can be positively attributed to the top ranked autochthon-rooted trap family. With only two possible exceptions, where root style could not be determined, none of the other subsalt trap families yielded a single discovery in the past eight years. Further analysis of the 107 new autochthon-rooted subsalt tests suggests the following descriptive and statistical updates to the autochthon-rooted trap family:the overall success rate of autochthon-rooted traps, which currently stands at 42%, has been favorably impacted by the emergence of the Paleogene (Wilcox) play trend,the trap family has been broadened to include cases where traps form above deep Cretaceous salt allochthons, and above Louann salt that has crept onto younger oceanic basement,northward and westward expansion of the deepwater subsalt play fairway necessitates the addition of new end-member archetypes within the autochthon-rooted family,the industry will be challenged to maintain the high success rate for the autochthon-rooted trap family as subsalt exploration focus within the GOM shifts from the lower slope to more complex subsalt traps of the middle to upper slope.
Flexible Pipe Integrity Monitoring: A New System to Assess the Flexible Pipe Annulus Condition
Authors: Dion Dominique H. , Murray Nuala Mary , Roques Jean-Philippe , Balague Benoit , Audouin Gregoire
Published: July 2010

One of the main concerns regarding flexible pipe integrity is its annulus condition, as a flooded annulus can lead to excessive corrosion and reduce fatigue life of the armor layers. The current approach to address this is to periodically perform a vacuum or pressure test to check the annulus integrity and to measure its gas-filled volume, in order to detect an accumulation of condensation water, or the ingress of sea water (Bondevik, 2004). These measurements are sometimes complemented by a continuous measurement of the flow rate of gas escaping the flexible riser's vent ports (MCS International, October 2002). The vacuum or pressure test is a costly operation, performed intermittently, while the conventional vent-gas monitoring does not provide reliable information on gas diffusion rates or water vapor emissions.

To address these issues, TOTAL and Schlumberger have developed the subC-racs* riser annulus condition surveillance system for continuous monitoring of flexible riser integrity, which eliminates the need for vacuum tests.

The gas that permeates the riser pressure sheath is depressurized while measuring its pressure, temperature, and flow rate. As in a well production test, the pressure drawdown and buildup curves are analyzed to give detailed information about fluid content and connectivity. The instrument's resolution and accuracy allow frequent calculations of gas diffusion rate and of the volume of liquid that may have entered the annulus, weekly, daily, or more frequently, depending on gas diffusion rate and riser parameters.

In this paper we describe the measurement principle and hardware, modeling of the gas diffusion in the annulus compared with experimental results, and field test results on various risers in a West Africa field. Emphasis is placed on the measurement results, but the implementation in hardware and real-time software for alarms and remote monitoring is also shown.

Introduction

Monitoring of flexible pipe integrity is a main concern for all offshore fields. It has become more significant as the number of flexible risers increases, and as they age.

The main issues for flexible risers are the status of outer sheath and the presence of water in the annulus due either to condensation or by damage to the outer sheath (Figure 1).
Understanding SMS Behavior to Define the Subsea Mining Operating System
Authors: Espinasse Philippe
Published: July 2010

Seafloor deposits are a very promising source of mineral ore for the near future, discovered over the last 40 years. In particular, Seafloor Massive Sulphides (SMS) are very high grade hydrothermal mineral deposits distributed on the mid ocean ridges, arc and back arc basins in the deep confines of the world oceans. The most commercially attractive minerals are copper and gold, combined with large quantities of lead, zinc and silver. The first deposits that will be developed are located in 1600 to 2000 m water depth. Production will start on a commercial level by 2011.

Applicable cutting and lifting technologies must be defined and tested rapidly so that the full production system can be engineered and built in a very short time frame. Existing oil and gas deep water developments is a proven source of technology that can be used as the basis of knowledge and experience to meet this challenging schedule.

As a company at the forefront of deepwater developments, Technip is deeply committed to this new industry. A strong and comprehensive R&D effort has been put together to characterize the ore, its behaviour under load, its effect on the lift system and all related flow behaviour within the riser system.

The R&D effort is split in four topics, all closely inter-related:Rock characterization performed in cooperation with Ifremer which has made available its SMS samples gathered over 30 years of deepsea exploration campaigns to determine mechanical and chemical behaviour of the SMS.Crushing test in hyperbaric conditions to evaluate the effect of pressure on cutting forces and determine rock size distribution.Slurry transportation models were performed using state of the art CFD modelling, both in two-phase and three-phase flow. This will be confirmed through large scale test loop experiments.Abrasion tests have been performed to select the preferred liner material for jumpers and risers. These liners will be tested in the test loop to confirm their behaviour over time.

This paper describes the test program, provides the main available results and identifies the way forward to meet this technological challenge.

INTRODUCTION

Seabed Massive Sulphides are the subsea equivalent of Volcanic Massive Sulphides which have been exploited on land over the years. These hydrothermal mineral deposits are very high grade ore accumulations present on the seabed, located on the back arc basins and mid ocean ridges. Of particular interest are those located on the Pacific rim of fire, within the exclusive economic zones of various countries, in water depths of less than 2500m.
Subsea Sensors for Non-Intrusive Monitoring of Temperature, Pressure and Asset Integrity
Authors: Thivend Guillaume , Murray Nuala Mary
Published: July 2010

The growth in deep water field developments and the need for increased oil recovery with reduced capital expenditure are pushing the technical boundaries of subsea asset design. One of the challenges facing these new developments is monitoring the structural health of their subsea production asset in an inherently inaccessible location. This is usually done through structural modeling and either spot monitoring campaigns using MEMS accelerometers or through subsea conventional strain gauges. Both technics present weaknesses: MEMS sensors usually require a great deal of data processing to obtain functional strain information at a desired location and strain gauges are complicated to install in a marine environment, many failing during pressure testing or installation. Both are also suseptible to electromagnetic fields which can biais their measurement.

This paper presents details of a new non-intrusive integrity monitoring sensor systems recently deployed in the Gulf of Mexico and West Africa on production lines. Inherently reliable, as presenting no moving parts, these sensors use optical fibers embedded within a composite frame for their measurements. Using field proven subsea fiber optic mapping technology these systems have delivered high frequency un-biaised, on the pipe, strain from which is derived pipe bending and axial loading in addition to temperature and pressure monitoring.

By providing electromagneticly immune, low noise, un-biaised, strain measurements to structural engineers to verify and improve their fatigue behaviour models, the non-intursive integrity monitoring system has proven a reliable alternative to MEMS and strain gauges. Furthermore unlike alternative solutions, this system also monitors pressure, illustrating this technology's capability at providing production and flow assurance data in addition to integrity data making it an ideal tool within a subsea production surveillance strategy.
Leading Edge Subsurface Technologies for AKPO, A Complex Condensate Field
Authors: Bandele Victor Abimbola , Claudel Gilles
Published: July 2010

This paper addresses geophysical, geological and reservoir engineering aspects of AKPO, a complex deep-offshore field operated by Total Upstream Nigeria Limited (TUPNI). This world-class field is under development in OML 130 in a region with about 1400m water depth, 135 km off the coast of Nigeria. The objective of the AKPO project is to produce condensate from Miocene turbiditic sandstone reservoirs deposited on a faulted anticline in submarine channels and lobes. The reservoirs are unconsolidated, highly permeable and present a complex and heterogeneous architecture. These ingredients, together with the thermodynamic properties and peculiarities of the reservoir fluids, place AKPO in a league of its own and combine to make challenging and demanding reservoir management. After a start-up on 4 March 2009, the field is in the initial production stage with a number of deviated and horizontal subsea producer and injector wells still planned to be drilled as per Field Development Plan.

With nine months of production history, the challenge for the Operator is to carry on the development of the field in order to sustain the condensate production plateau of 175,000 bbls/d in the success vein of the first 24 wells. The application of leading edge technology comprising seismic, reservoir characterization and numerical simulation through integrated subsurface work by a Nigeria-based multi-cultural core team, produced for AKPO a creative combination to optimize production and secure reserves. This is the best preparation for long-term reservoir management and geological vagaries.

The OML 130 license is operated by TOTAL with 24% interest, on behalf of the Nigerian National Petroleum Company (NNPC - Nigeria), South Atlantic Petroleum Company (SAPETRO - Nigeria), PETROBRAS (Brazil) and China National Offshore Oil Company (CNOOC - China).

GENERAL SETTING

The deep-offshore field developed by Total Upstream Nigeria Ltd is in OML 130 located 135km off the coast in a water depth of 1400m. AKPO is a large anticline structure located in the translational zone of the offshore Niger Delta. The structure is clearly defined as a faulted four-way-dip closure anticline slightly elongated in an EW direction with a vertical structural closure of nearly 500 m at the reservoir levels. The discovery was made in 1999 (Well Akpo-1) and four appraisal wells were drilled in 2000-2002 to confirm the potential of this giant condensate field with 620 MMbbls estimated reserves. The AKPO core consists in two main sectors with central pools (Reservoirs B, D, EF and G) and an eastern pool (Reservoir A). The trapping for the A channels has a stratigraphic component with the shaling out of the reservoirs toward the anticline crest. The western lobe, relatively much smaller in size than the AKPO core areas, was penetrated by seven wells so far but still suffers from large uncertainties. It is not part of the first phase of development.
AKPO Project -- Floating Production & Offloading System (FPSO)
Authors: Bernard Tchigique
Published: July 2010

This paper addresses the main characteristics of the AKPO FPSO. Although the FPSO is similar to other existing ones in terms of size, it is unique, in some particular technical details and principals which have been incorporated in the design, such as:An all electric FPSOAn early ICSS selectionE/I decentralized buildingsA 128 m flare with extensive heat shieldingCareful study of the space needed for Maintenance and handlingFlexibility in accommodation capacity of the living quartersBenefit taken from the tow between Korea and Nigeria

Because of these particular characteristics, it was possible to start-up the AKPO field in a limited time frame (ahead of schedule) and without any major problems.

AKPO DEVELOPMENT

TOTAL, is the Operator on OML 130 with a 24% interest. The partners are Petrobras of Brazil, Sapetro of Nigeria, CNOOC of China and NNPC of Nigeria.

Akpo is a standalone development based on a spread moored Floating Production Storage and Offloading (FPSO) moored in 1314m water depth with a storage capacity of 2 million barrels of condensate. The stabilized condensate is exported via offloading lines and a deep water buoy located 2 km away from the FPSO.

The Akpo development involves five reservoirs, deposited in a complex channels and lobe arrangement, situated at depth ranging from 2950mSS to 3750mSS. The reservoir fluid is a critical fluid, which implies that the fluid type is dependent on pressure, temperature and depth. The liquid produced is light oil/condensate (42° to 53° API), with a high gas-liquid ratio (GLR = 1600 to 7300 scf/bbl). Pressure maintenance in the reservoirs is necessary, with water injection in 4 of the reservoirs and gas injection in one.

The development includes 44 subsea wells (22 production, 20 water injection and 2 gas injection) drilled in clustered subsea architecture. For the initial production start-up, around half of these wells are required to be online for production and reservoir pressure maintenance purposes.
Offshore Diamond Mining in the Early Days
Authors: Swoboda John J. , Swoboda Jay
Published: July 2010

In 1961, there was a handful of visionary pioneers who knew very little about mining but were willing to gamble their ideas, tenacity, determination, future and fortune against the most inhospitable waters off the West Coast of South Africa. Their reward, if the gamble paid off, was a new method of harvesting diamonds from the ocean floor. This venture was a tremendous undertaking because there was no previous history of success and the extremely dangerous environment in which it was undertaken.

Dredging up sand and gravel from the seafloor had been successful in moderate seas. However, this effort would have to succeed in the shallow surf zone along one of the most dangerous coastlines in the world; even its name was foreboding - the Skeleton Coast. These men and their equipment would be subject to heavy swells averaging 20-30 feet with gale force winds. The shore offered little respite, nothing but desert in all directions. These forces of nature challenged these pioneers and on several occasions subjected their ideas, methods and equipment to devastating results. But this band of hearty Texans, Afrikaans and others took all nature threw at them and persevered. From 1961 to 1965 they developed the technology and techniques and proved to the world that offshore diamond mining was commercially viable.

Equipment and methods were improved and altered based on the successes and problems that arose. Nothing stood still. When the shipyard couldn't build the next vessel in time, they started their own company to do it. When the diamond cartel offered to market their diamonds at a reduced rate they created a new mystique and market. When the vessels drug anchors, foundered or had other difficulties, the crews did whatever it took to get them back in service.

Mining diamonds offshore has grown from finding a handful of stones in 1961 to current production of over a million carats per year from the sea. The challenge for today's leaders is to rekindle and develop that pioneering and entrepreneurial spirit, drive and attitude - that same spirit that changed the world of diamond mining 50 years ago.
Performance Benefits of the MinDOC Hull at the Mirage Field in a Post-Katrina/Rita Environment
Authors: Herman Dan , Garrett David L. , Shivers Robert M. , Veselis Todd
Published: July 2010

The MinDoc3 platform, a dry tree capable, spread-moored deep draft floater featuring three columns braced together, was selected for Mirage field development because of flexibility, functionality and ability to fabricate in the US Gulf Coast. This paper presents the MinDOC's global performance and discusses impacts from hull form, mooring design and riser interaction and makes comparisons to previous design standards. The Mirage Field is located in Mississippi Canyon 941/942 in 4000 ft WD. The weather criteria includes the impact of hurricanes Katrina/Rita, and allows for maximum wave heights and robust mooring considerations.

The MinDOC's global performance has been modeled experimentally and numerically with good correlation. VIM behavior was determined experimentally, and suppression is achieved by only straking the interior portion of the upper columns, which simplifies horizontal construction.

The MinDOC was chosen for its payload, robustness and low motions. The mooring system is a relatively typical 3x4 semi-taught chain-polyester-chain system with a radius of approximately 6700 ft. The MinDOC hull form global motions are sufficiently low to permit the use of Top-Tensioned risers and Dry Trees. The low motions reduce riser stroke, which also reduced tensioner stiffness, and reduce the coupling impacts on the global motions. The low motions were achieved by a conscious effort to concurrently design the hull, risers, tensioners and mooring systems.

Introduction

MinDOC hull design was initiated in late 2006 with design and fabrication commencing nearly in parallel. The initial design site is for the Mirage field, located in Mississippi Canyon in Blocks 941/942. The location is near the edge of the shelf and the mooring system water depth varies from 3,822 ft in the north, to 4,288 ft in the south.

The mooring pattern consists of 12 lines arranged in three bundles spaced 120° with each bundle having four lines grouped in two pairs. The platform bow orientation is 156 degrees. The leg numbering starts with the SE most line, counting clockwise around. Each mooring leg is chain-polyester-chain and consists of 5" R4 studless top chain, 9.75" Polyester and 5" R4 studless bottom chains. The nominal radius is approximately 6700 ft from the fairlead to the anchor chain touchdown. The total nominal length of each line is 7,500 ft. (Figure 1).
Considerations For Standalone Development of Small Deepwater Fields
Authors: Shivers Robert M. , Frazer Ross
Published: July 2010

This paper describes development planning for the Mirage & Telemark Fields located in 4000 - 4500 ft WD in the Gulf of Mexico. These fields are relatively small, short lived oil fields with multiple pay zones. Factors driving development planning include:Lack of accessible nearby infrastructureMultiple pay horizons & short field lifeLimited availability of MODU's for pre-drillingPotential satellite tiebacks in the vicinityParallel vs. sequential development of the nearby Telemark FieldFunctionality & Residual value in floating infrastructure

These fields have 2 - 4 pay zones in each well, so a dry tree concept was preferred. Because the floating platform design life is over 20 years vs. estimated field life of only 5 - 7 years, the development facilities need to be designed for convenient relocation to other deepwater fields in order to maximize residual value.

The MinDOC3 (Minimum Deepwater Operating Concept) hull was selected for field development because of flexibility, functionality and ability to fabricate in the US Gulf Coast. Hull construction required installation of the first graving dock for offshore construction in the US Gulf Coast.

Introduction

The Deepwater Gulf of Mexico, like most oil & gas provinces, is characterized by early development of relatively few very large fields which provide a cornerstone for primary infrastructure development, but with many smaller fields left behind for later development. A recent report issued by the Minerals Management Service showed that through 2008, only 9 proven deepwater fields had reserves >250 MMBOE, but 150 fields had reserves <50 MMBOE.1

ATP Oil & Gas focuses on acquisition and development of discovered, deepwater fields and typically, these are smaller fields (<50 MMBOE) which are nearing the end of their primary lease term. Leasehold preservation in these circumstances often requires rapid submission of a field development plan, leaving little time for extensive appraisal drilling or concept evaluation. Short term field development planning is further complicated by the fact that these fields usually are not large enough to justify extensive appraisal drilling and well testing. Long term development planning must allow for cost effective platform relocation and reuse because of the short field lives (3 - 7 years) compared to the life of the floating platform (20+ years). Therefore, floating infrastructure investment must provide flexibility and functionality for future fields in different water depths and with different combinations of dry vs. wet trees.
Qualification and Use of IR-Cured XLPE for Flexible Pipes
Authors: Procida Inger-Margrete , Nielsen Niels-J. Rishoj
Published: July 2010

Unbonded flexible pipes constitute key components in floating production systems for the offshore oil and gas industry and it is important to continuously improve the performance of these pipes to meet the demands of production regularity under increasingly severe operational conditions.

The polymeric pressure sheath is a critical component in flexible pipes as the function of the layer is to make the pipe leak proof. Therefore, it is important to carry out material research to enhance the performance of this layer thus further securing the long term integrity of the pipe. A new method to cross-link HDPE pressure sheath in flexible pipes using Peroxide in combination with infrared radiation (IR) has been developed. This method is unique in the sense that it is an inline process where extrusion and cross-linking is done in one step. The IR-cured XLPE technology will be described in this paper with emphasis on presentation of detailed results from the comprehensive qualification programme which has been carried out according to API Spec 17J / ISO 13628-2 [1]. Also, actual field applications of these pipes will be presented including ID15?? flowlines.

The newly developed IR cross-linking method significantly expands the application envelope of the conventional XLPE flexible pipes, for example with respect to increase of allowable bore pressure and temperature, and the manufacture of large size pipes up to ID16?? or more with uniform cross-linking of the entire thick-walled pressure sheath. Further novel applications which this technology enables include the manufacture of cross-linked intermediate and outer sheath layers. The paper will present comprehensive qualification test results from both material and mid-scale pipe testing which document that the new IR cross-linking technology is superior to the conventional cross-linking technology previously used for flexible pipes. In particular, it is shown that the new XLPE material can sustain considerably higher pressure and temperature loads compared to existing industry standards, for example as specified in API RP 17B / ISO 13628-11 [2].

Introduction

Flexible pipes are complex multi-layered structures built from a number of helically wound metallic wires or strips combined with concentric layers of polymers, textiles, fabric tapes and lubricants. The number, type and sequence of the component layer depend on the specific design requirements. Figure 1 shows a typical unbonded flexible pipe build-up, which according to API RP 17B / ISO 13628-11 [2] is categorized as a Family 3 pipe structure, with carcass (inner-most layer), internal pressure sheath, pressure and tensile armour layers, and outer sheath.