bluuebunny/crossref_metadata_2025 huggingface dataset:
Gas Production From Oceanic Class 2 Hydrate Accumulations
Authors: Moridis George J. , Reagan Matthew T.
Published: October 2008

Gas hydrates are solid crystalline compounds in which gas molecules are lodged within the lattices of ice crystals. The vast amounts of hydrocarbon gases that are trapped in hydrate deposits in the permafrost and in deep ocean sediments may constitute a promising energy source.

Class 2 hydrate deposits are characterized by a Hydrate-Bearing Layer (HBL) that is underlain by a saturated zone of mobile water. In this study we investigated three methods of gas production via vertical well designs. A long perforated interval (covering the hydrate layer and extending into the underlying water zone) yields the highest gas production rates (up to 20 MMSCFD), but is not recommended for long-term production because of severe flow blockage caused by secondary hydrate and ice. A short perforated interval entirely within the water zone allows long-term production, but only at rates of 4.5 - 7 MMSCFD. A new well design involving localized heating appears to be the most promising, alleviating possible blockage by secondary hydrate and/or ice near the wellbore) and delivering sustainably large, long-term rates (10-15 MMSCFD).

The production strategy involves a cyclical process. During each cycle, gas production continuously increases, while the corresponding water production continuously decreases. Each cycle is concluded by a cavitation event (marked by a precipitous pressure drop at the well), brought about by the inability of the system to satisfy the constant mass production rate QMimposed at the well. This is caused by the increasing gas contribution to the production stream, and/or flow inhibition caused by secondary hydrate and/or ice. In the latter case, short-term thermal stimulation removes the blockage.

The results show that gas production increases (and the corresponding water-to-gas ratio RWGCdecreases) with an increasing (a) QM, (b) hydrate temperature (which defines its stability for a given pressure), and (c) intrinsic permeability. Lower initial hydrate saturations lead initially to higher gas production and a lower RWGC, but the effect is later reversed as the hydrate is depleted. The disposal of the large amounts of produced water does not appear to pose a significant environmental problem. Production from Class 2 hydrates is characterized by (a) the need for confining boundaries, (b) the continuously improving RWGCover time (opposite to conventional gas reservoirs), and (c) the development of a free gas zone at the top of the hydrate layer (necessitating the existence of a gas cap for production).
Internal Flow Induced Pulsation of Flexible Risers
Authors: Swindell R. , Belfroid S.
Published: October 2008

A Joint Industry Project, involving a number of operating companies and allied organisations (including ExxonMobil, BP, Statoil, the UK Health & Safety Executive, TNO and Bureau Veritas), is currently addressing the technical issues associated with high amplitude pressure pulsations generated by gas flow through flexible risers. Combining actual offshore measurement data; part and full scale test results at low, medium and high pressures; and both theoretical acoustic and flow simulations, a good understanding of the phenomenon has been achieved. Guidelines for existing and planned developments have been developed, based on precautionary measures, i.e. how to minimise the risk of this phenomenon occurring at the design stage, and practical assessment and mitigation measures for existing assets. This paper will describe the history of the concern and actual offshore experiences, review the work undertaken by the JIP and provide initial guidelines to address the issue.

Introduction

In the last 5 years, a number of offshore installations that utilise flexible risers for single phase gas service have experienced high levels of piping noise and vibration. This has resulted in at least two piping failures. The immediate means of minimising the risk of additional failures was to significantly reduce the gas export rate. The problem has been attributed to flow induced pressure pulsations from the flexible risers.

The pressure pulsations are generated due to vortex shedding on corrugations of the innermost layer of the flexible riser carcass. These pressure pulsations can be sufficiently extreme to cause vibration induced piping fatigue failures, for example to small-bore connections on both topside and subsea piping. The problem has been seen to occur for gas flow velocities as low as 1.5 m/s, which is potentially a severe limiting factor to an installation's production capabilities.

Fig 1 Typical flexible riser showing corrugated carcass (available in full paper)

As an example, one installation experienced severe noise and high frequency pipework vibration on the topsides gas export system once gas export commenced. A comprehensive measurement programme was undertaken which identified the cause as vortex shedding from the internal corrugated carcass of the riser locking on to discrete acoustic resonances of the gas within the export system pipework. The noise, vibration and dynamic pressure within the gas displayed clear tonal characteristics with the fundamental frequency varying with gas velocity (figure 2). The fundamental frequency varied from 84Hz to 208Hz over the range of gas velocities encountered; harmonics of the fundamental frequency were also seen.

Fig 2 Step change in pressure pulsation frequency with flow velocity increase (available in full paper)
Constructing the World's Longest Subsea Pipeline, Langeled Gas Export
Authors: Solberg Leif , Gjertveit Erling
Published: October 2008

Langeled is part of the development of the Ormen Lange Gas field, operated by Hydro in the development phase and by Norske Shell in the operating phase.

At plateau level, the Ormen Lange field will produce around 20 billion Sm3 gas per year, which is equivalent to 20 % of UK gas demand at the time of start-up of the gas deliveries.

The gas will be transported through the world's longest subsea pipeline over a distance of nearly 1200 kilometers, from Nyhamna on the west coast of Norway, via the Sleipner field in the North Sea, to Easington in the UK.

The Langeled project was developed by Statoil on behalf of the operator, Hydro, using personnel from both companies.

This paper covers the main technical, organizational and logistical challenges faced in developing the project. Key conceptual tasks, the massive construction task involving two of the world's largest pipe-laying vessels over two seasons; the logistics of producing, coating and transporting 100,000 pipe joints, the challenging riser installation and modification works on the Sleipner field and finally, the landfall and terminal construction in Easington UK are described.

Introduction

Ormen Lange is a large gas field located 120 km off the west coast of mid-Norway. The field has been developed with two subsea templates and with two 30" flowlines to shore at Nyhamna, where a gas treatment facility is being built. Hydro is the development operator, while Norske Shell will operate the field and the plant in the future.

As part of the Ormen Lange development, a dedicated large diameter export pipeline, called Langeled, has been installed to transport dry gas from Nyhamna to the east coast of England in order to supply gas to the UK market. The Langeled development project has been managed by Statoil on behalf of Hydro. Gassco, operating all the main gas export pipelines from the Norwegian continental Shelf, on behalf of the owners, is taking over the operator ship of Langeled in the operational phase. This was effective from September 1st 2006, when the Langeled South became operational.

Langeled is a 1200 km long pipeline from Nyhamna to Easington on the east coast of England, which is tied into the Sleipner field about midway across the North Sea. The northern half consists of a 42" diameter 250/215 bar pipeline, whilst the southern half from Sleipner to the UK comprises a 44" diameter 157 bar pipeline.

This paper will highlight the main challenges of the project;system description and concept selectionlandfall in UKright of wayenvironmental challengesexecution and market strategyconstruction and marine operationsmodifications and tie-in to Sleipnertie-in, testing and Ready for Operation (RFO) activitiessafety during the construction phase

System description and concept selection.

Market considerations.

The main driver for the concept selection of a gas field development is the market considerations. In case of Ormen Lange, several possible market scenarios and locations were evaluated.
The Setting and Possible Mechanism of the 2006 Green Canyon Seismic Event
Authors: Peel Frank
Published: October 2008

On February 10 2006, a significant seismic event occurred in the Gulf of Mexico within an area of vital interest for hydrocarbon exploration companies. The location of the event, in Green Canyon Block 344, is close to discoveries and producing fields, including Allegheny, Front Runner, Bison, K2, Marco Polo and Holstein, among others. This paper describes the structural context of the February 2006 event and reviews possible seismogenic process that could operate within the region.

Introduction

In order to define the possible influence of such an event on exploration or production, we need to know the strength, depth, displacement, rupture area, surface effect and likely recurrence interval of the event responsible. We cannot predict this from historical seismicity, because there is little historical data on natural seismic activity in the area, and the focal mechanism and depths are poorly defined. Therefore the best way to predict potential future activity is to understand the geological setting and structural mechanism of this event.

Seismological signal

The limited information made available by the USGS1 gives a location (27.632°N, 90.144°W, with lateral error +/- 10.8km) and an approximate depth (5km, with no vertical error margin quoted) but no information on focal mechanism. Assuming vertical positioning error is similar to the horizontal, the information provided by the USGS does not distinguish between an event at sea floor, one within the sediment sequence, or one at a shallow depth in the basement. The seismic effect of the earthquake was fortuitously detected by an OBS network in place over the Atlantis field. Dellinger2 et al. (2006) described the nature of the signal of the event as seen on the OBS data. An analysis of the teleseismic data by Nettles3 (2006) supports the general conclusions on the earthquake source, confirming the that general location lay within southeastern Green Canyon protraction area, with an indication that the source may have been 5-10 miles further north than reported by the USGS.

Nettles also concluded that the seismic signal does not permit a precise definition of the source signature, but the nature of the signal indicates that it is not that of a conventional deep seismic rupture (an effectively instantaneous slip event giving rise to the classic double-couple "beachball" with clear compressional first motion seen in two quadrants). Instead the signal is compatible with a seismological "landslide-type" mechanism. In this mechanism the movement takes a discrete length of time, such that the initiation of movement gives rise to a "beachball" with one polarity, and the cessation of movement gives rise to a signal of the opposite polarity. This is illustrated by the sequence of sketches shown in figure 1. The net effect of this as seen at a distance is a more confused signal, combining the responses from the start and end of movement, which does not have a conventional doublecouple signature.

Fig. 1 mechanism of the "landslide-type" source (available in full paper)
Oil Well Transient Testing by Injection of Miscible Fluid
Authors: Voelker Joseph James
Published: October 2008

This paper describes the general procedure and analysis of an oil well pressure transient test method in which a liquid that is miscible with reservoir oil is injected from the surface at constant rate. Injection significantly reduces surface production test separation and rate measurement equipment requirements, and flaring, thereby reducing testing costs, and safety and environmental risks. Injection of liquid provides for rate control to a precision difficult to attain during production, and although not strictly necessary, allows for a constant rate condition to be practically attained, potentially eliminating a time consuming shut-in and associated test duration and costs. Drilling non-aqueous fluid base oil is a viable miscible injection fluid. A well pressure model is developed that includes the effect of the viscosity difference between injected fluid and reservoir oil. The temperature effect on viscosity is also considered. The model indicates that the duration of the viscosity effect may be short under practical conditions, and is controlled by injection rate. Reservoir parameters estimated from the injection test are identical to those estimated with single-phase production pressure transient tests. A reservoir oil PVT sample must be obtained independently, prior to injection. Conventional pressure transient analysis applications may be used to analyze injection pressure transient data.

Introduction

This study originated from the desire to obtain reservoir permeability estimates as part of the exploration and delineation of an offshore basin in which the typical play is composed of stacked, fluvial sand reservoirs, forming three-way closures against trapping faults.

A method is desired to assess the productivity of as many of the stacked oil bearing intervals as may be discovered in many or all exploration and delineation wells in the drilling program. The success of future development depends on the exploitation of numerous small, vertically and laterally isolated reservoirs. Evaluation of the productivity of many hydrocarbon intervals allows the estimation of the local distribution of reservoir productivity in various regions of the basin.

Reservoir productivity estimates from production testing are more reliable than that from wireline flow testing and from core analysis, however the disproportionate costs associated with production testing, related to rig time and surface test equipment rental, discourages liberal use of this method. Production testing also carries safety and environmental risks, particularly from flaring. A flow test method that minimizes test duration, and eliminates the need for surface test equipment, is highly desired.
Development of Method for Measuring Susceptibility of Steel Plate to Lamellar Tearing
Authors: Wold Gunnar , Kristoffersen Thrøbjorn
Published: October 2008

1. Introduction

During the construction of steel structures problems sometimes arise due to a cracking phenomenon that has been termed lamellar tearing". A case in point is the construction of drilling rigs and other offshore platforms where problems of this kind is known to occur quite frequently.

Lamellar tearing is a type of weld defect that may occur in a steel plate when it is subjected to appreciable strains in the short transverse direction (z-direction) due to shrinkage of the weld deposit. Since it is essential that the strains are predominantly in the z-direction, the defect is most often found in welded joints where the fusion boundary is roughly parallel to the surface of the plate. Typical examples of such welds are shown schematically in Fig. 1.

The appearance of lamellar tears occurred in illustrated in Figs. 2 and 3.

It is well established now that the main variables in lamellar tearing are:The mechanical properties in the z-direction of the plate,The design of the structure, in particular the joints, andThe welding parameters.

It is the intent of the present paper to deal only with the first and most important of these variables, namely the material properties.

The main factor in determining the z-direction properties of a steel plate is the non-metallic inclusions. Their effect, which is mainly to reduce the ductility in this direction, is caused by the inclusions being elongated and flattened in planes parallel to the plane of the plate, a feature which also gives rise to the stepped appearance of lamellar tears. A typical fracture surface of an opened lamellar tear is shown in Fig. 4.

Once lamellar tearing has occurred in a construction it is difficult to get rid of since removal of the crack by grinding or gouging and rewelding often results in new lamellar tears forming further into the material There pairwork is therefore complicated, time consuming and often very expensive. For these reasons there is a need for a testing method that will provide quantitative information about the susceptibility of steel plate to lamellar tearing. It has been the aim of the present work to develop such a method.

2. Test for assessing susceptibility to lamellar tearing.

In the literature a number of methods are described that have been suggested as a means for testing the susceptibility of steel plate to lamellar tearing. See for instance references (1), (2), (3), (4), (5), (6) and (7). Some of these methods are purely mechanical tests, others are weld-cracking tests that rely on welding strains to trigger off possible cracking, while others, again, are combinations of these methods.

In principle, however, all the methods have as a common objective the provision of information about the mechanical properties in the z-direction of the material being tested.
DST Design for Deepwater Wells with Potential Gas Hydrate Problems
Authors: Chen Shing-Ming , Gong William Xiaowei , Antle Geoff
Published: October 2008

The main objective of this paper is to present a proper DST design for deepwater gas wells with potential gas hydrate problems because of low seabed temperature.

Prior to discussing the DST procedures, the importance of selecting a proper mud for drilling and interval for testing are explained. Factors affecting gas hydrate formation are discussed. Then, requirements for gas hydrate prevention during DST are described. Actions required to prevent gas hydrate formation during DST startup, fluid sampling, well shut-in and restart are addressed. Finally, procedures for incorporating gas hydrate prevention in DST are outlined.

At the end of the paper, a gas well with hypothetical data is used to assist in illustrating the DST procedures.

Introduction

Hydrates are physical combinations of water and natural gas formed at pressures and temperatures considerably above the freezing point of water[1-5]. For deepwater gas wells, the risk for gas hydrate formation always exists due to the low seabed temperature and the coexistence of gas and water inside the wellbore.

Figure 1 shows one of the popularly used pressure-temperature-gas density correlations for gas hydrate predictions[2,6]. As it can be seen from this figure, the generally low temperature of less than 50 0F in the deepwater seabed, together with the normal gas well operating pressure of several hundreds to thousands of psi, will result in wellbore temperatures below the gas hydrate temperature curve.

DST and Gas Hydrate

Although a deepwater gas well may be operated at certain flow conditions to take advantage of the warm fluid coming out from the reservoir, the need for DST to shut in the well for pressure buildup tests or produce the well at low rates for fluid sampling often cool the fluid inside the wellbore to the extent that gas hydrate will form. For the deepwater DST, it has been well recognized that hydrate prevention is needed for flow assurance in order to complete the test[7-11].
Recent Developments in Deep Sea Electrical Resistivity Probings - Its Application to The Sedimentary Study of the Red Sea Hot Brines
Authors: Kermabon Andre J.
Published: October 2008

INTRODUCTION

Previous studies have been made of the mass physical properties and the electrical resistivity of marine sediments. A third degree polynomial curve was found to, be the best fit for data relating porosity and the formation factor, which is the ratio of the bulk resistivity of marine sediments to the resistivity of interstitial water. An electrical resistivity probe has already been successfully used to obtain in-situ profiles of resistivity vs depth.

A new instrument is now described where a similar principle is used for the study of the lithology of the Red Sea hot brines. In order to increase the definition of the measurements, the new probe is provided with a focused resistivity measuring device, that is less affected by borehole effects. This new probe is devised to operate in an environmental temperature of 700C and a salinity of 35 percent of salt content in water as well as in the interstitial water of the sediments.

PREVIOUS DEVELOPMENTS IN THIS FIELD

General

Archie,1 Rust (1952), Atkins2 and Kermabon4 successful correlated some physical parameters of reservoir rocks in sedimentary strata with their electrical resistivity. The sandstones investigated had porosities ranging from 10 to 40 percent and were saturated with brine of known salinity. The following simple relation was defined.

(Mathematical equation available in full paper)

where Re is the resistivity of the sand when all the pores are filled with brine, Rw the resistivity of the brine, and F a formation resistivity factor. F appeared to be a function of the type and character of the formation, and varied among other properties with the porosity of the reservoir rock. A reasonably accurate relationship was found between the porosity and density. Thus, knowing the porosity of the sand in question, a fair estimate of the value of F may be given by the empirical relationship,

(Mathematical equation available in full paper)

where n is the porosity fraction of the sand. The value of m was found to range between 1.and 2.

Correlation Between Porosity and the Electrical Properties of Some Deep Sea Sediments

Correlation Between Porosity and the Electrical Properties of Some Deep Sea Sediments Cores were taken from the Tyrrhenian abyssal plain, and the mass physical properties of these cores were correlated with the' electrical formation factor.

The sampler used was a wide-diameter sphincter corer and a special analysis bench (Fig. 1) was developed the following measurements were taken:porosity,wet (bulle) density andelectrical resistivity (formation factor).

The well known linear relationship between porosity and wet (bulk) density was controlled (Fig. 2). From the results of 10 cores, the following regression was found:

d = 2.60 - 0.0158n

where d is wet density and n is porosity. By plotting the formation factor vs porosity, derived from2,500 measurements made on cores collected in the Tyrrhenian Sea, several regression curves were obtained.
Reservoir Characterisation Through Joint Interpretation of EM, Seismic, and Well Log Data
Authors: MacGregor Lucy , Harris Peter , Walls Joel D.
Published: October 2008

Improved reservoir reservoir management and production optimisation demands require accurate characterisation of reservoir properties and their changes through time. Advances in geophysical data acquisition and interpretation have led to significant improvements in the remote imaging of earth structure and properties. However, when only a single data type is considered, ambiguities in the interpretation can remain. Here we will concentrate on three contrasting methods: surface seismic, marine controlled source electromagnetic (CSEM) and well-log data.

It is clear that a careful combination of all three data types can supply information that is not available, or is unreliable from any one data type alone. By integrating complementary sources of information and exploiting the strengths of each, estimates of rock and fluid properties such as gas saturation and porosity can be obtained with greater confidence than from any one data type alone. We illustrate this using an example based on the Luva discovery in the Norwegian sea.

Introduction

There are a range of physical parameters we can use to investigate the earth and properties of fluids within it. Well logs provide a high resolution measurement of the properties of a reservoir and the surrounding strata, however properties can only be determined in a small area local to the well. Often a measurement of reservoir properties across the extent of a field are desirable for reservoir management or production optimization and for this we must turn to remote sensing methods. In the well logging industry both electric and acoustic properties are routinely collected and analysed to study lithology, reservoir properties and the properties of fluids within them: it would be almost unthinkable to collect one data type without collecting the other, since this would result in an incomplete dataset that left gaps in our understanding of the reservoir and surrounding strata.

Until recently the same logic has not been applied in geophysical surveying and data analysis. Seismic methods, sensitive to acoustic properties only, have been the primary tools used in exploration, reservoir appraisal and monitoring. These methods are extremely powerful. Seismic data are commonly used to provide images of the sub-surface, and develop high resolution geological models of structure and stratigraphy. Amplitude variation with offset (AVO) and inversion for acoustic and elastic impedance may also be used to constrain properties such as elastic moduli and density. However seismic data alone in many situations cannot give a complete picture of the reservoir.
Polyester Moorings - Is Insert Recovery & Testing The Best Way To Determine Rope Integrity?
Authors: Ayers Ray R. , O'Hear Nick
Published: October 2008

This technical paper addresses the value of regulatory requirements to recover and test 15-meter inserts from polyester mooring systems for production systems in the Gulf of Mexico. The authors have been working on a MMS-sponsored project to determining the Accuracy of Polyester Subrope Damage Detection by ROV Inspection, and Assessment of Remaining Rope Strength and Life.

Typical samples of subropes used to comprise 15-meter mooring rope inserts for polyester-based mooring systems have been exposed to the equivalent cyclic motions of 20 Hurricane Katrinas, and then the ropes were tested to failure. Results were compared to tests results from the same subropes not exposed to 20 Katrinas. There appears to be little if any rope decline in rope integrity, even if one Katrina-type hurricane scores a direct hit each and every year for the 20-year life of the mooring system.

Introduction

Background

In March 2007, the MMS contracted Stress Engineering Services, Inc. assisted by TTI, Ltd., to evaluate the accuracy and effectiveness of polyester subrope damage detection processes following hurricanes and other events (i.e., loop current) that exceed the 100-year design criteria for offshore structures. ROV inspections are used by the offshore industry to detect damage to polyester mooring systems and estimate remaining fatigue life if damage is found. This work addresses permanently moored floating production systems.

Approach

The fundamental question is: " What are the best ways to ensure the structural integrity of a polyester rope mooring system over the life of the project??? The specific objective for the MMS was to evaluate the accuracy of non-invasive damage-detection methods. Toward meeting this objective, the following issues were considered for polyester rope mooring systems:Structural mechanicsFactors that reduce structural integrityQualification for serviceCharacteristics of structural damageAssessment of current and new methods for determining fitness for serviceThe final report to the MMS (Reference 1) documents the complete set of findings from the work
DW RUPE: A New Deepwater Pipeline Repair Capability for the Gulf of Mexico and Other Deepwater Regions
Authors: Ayers Ray R. , Hoysan Steve , Rebello Armando , Gage Eric , Stark Mike
Published: October 2008

Described herein is a chronology for developing a deepwater pipeline repair system and cooperative ownership group for affecting emergency repairs of damaged pipelines. Using a Joint Industry Project (JIP) funding model, technology development started in 2004, and continued as Hurricanes Katrina and Rita hit in 2005, and resulted in the formation of DW RUPE - Pipelines Co-Ownership Group in May of 2007. Included in this paper is a description of the repair methods developed, and repair tools being procured and developed for affecting 10 to 24 inch ANSI pipeline repairs in 1,000 to 10,000 feet of water. A recently-developed spreadsheet-based pipe lifting analysis laptop computing tool is described for use in planning pipe lifting and cutting operations for a specific emergency pipeline repair operation in deep water.

Background on the Formation of DW RUPE

In 2004 Phase 1 of a JIP was formed to develop a low CAPEX emergency repair capability for pipelines and flowlines in water depths in the 1,000-10,000 ft range, in the US Gulf of Mexico. Stress Subsea, Inc. (SSI) performed a Failure Mode and Effects Analysis, conducted interviews with suppliers and operators and included input from the JIP Steering Committee.

Phase 1 JIP Conclusions

As a result from DW RUPE, Phase 1, the following conclusions were drawn for export pipelines:The probability of needing a deepwater repair is low, but the consequences resulting from pipeline damage are high. Because of this, the project agreed upon pursuing a low CAPEX repair solution, recognizing the need to minimize capital expenditures since the probabilities of occurrence are low.The most likely damage types are wet and dry buckles caused by anchor snags (the DW RUPE shallower water depth range is 1,000 ft., hence anchoring damage is still a consideration).Potential repair solutions for a low CAPEX pipeline repair and a low CAPEX flowline repair are different.Traditionally a leak clamp and a spool piece connector set are needed for each pipe size. The project pursued a new paradigm of adapting and employing full structural clamps in place of connectors. This allows two clamps to be used in a spool piece repair or one of the structural clamps to be used alone for a pinhole leak from a cracked weld. Two clamps serve the same function as two connectors and a clamp (Pipeline Repair), thus reducing the CAPEX investment for inventory.Cracked welds are the most likely cause for pinhole leaks. Full structural clamps are advised to arrest crack propagation (Pipeline Repair).
ACG Jackets Design and Fabrication
Authors: Ciezarek Richard , Cormack Archie , Penman Allan David , Mackie Richard , Tate Geoff
Published: October 2008

The ACG field is located in the Azerbaijan sector of the Caspian Sea approximately 130 km east of Baku, in water depths varying between 118m and 176m.

As part of the ACG Full Field Development (FFD) (see Figure 1), six barge launched jackets suitable for floatover topsides, plus associated drilling templates and foundation piles were designed and fabricated. Jacket loadout weights varied between 13,200 te and 16,700 te and the total pile weight, for all six structures, was approximately 44,000 te. Each jacket structure supports operating topsides weights of between 18,000 te and 24,000 te.

This paper explains the development of jacket design and fabrication capability in Baku. It also highlights the production line approach to the design and fabrication of the jackets and the challenges that were overcome to successfully deliver this part of the ACG FFD project in Azerbaijan.

The information will be of interest and value to those who face similar challenges in newly emerging energy markets and need to build up design or fabrication capability in other countries. It may also be helpful to those considering a production line approach to design and fabrication in order to optimise the delivery of major projects.

The detailed design for all six jackets was completed in London and Baku between September 2001 and September 2006; this was followed by post design support to both the fabricator and installation contractor. Key drivers for the size, weight and configuration of the jackets, templates and foundation piles are explained in this paper.

Construction of the jackets was executed in Baku between March 2002 and May 2007. The execution strategy for this work is explained with details of in-country upgrades of the fabrication yard, training of local personnel, fabrication schedules, specifications of steel, in-country rolling and erection roll up methods. The benefits of a production line of jackets are given in terms of procurement and logistics, re-use of construction and installation aids, lessons learned and the reduction in site queries, all leading to continuous improvement in productivity and schedule.
ACG Phase 3 Subsea Water Injection Scheme
Authors: Richmond Adrian , Barralet Peter
Published: October 2008

The third phase of the Azeri, Chirag, Gunashli (ACG) Project for Azerbaijan in the Caspian Sea develops the Deep Water Gunashli (DWG) area of the ACG reservoir, approximately 130km East of Baku. The DWG reservoir is highly pressure depleted due to extensive production from existing facilities adjacent to the reservoir. The provision of six pre-drilled subsea water injection wells optimises oil recovery over the field life. The subsea water injection scheme supports the production of 20% of the ACG Phase 3 reserves, for 10% of the total capital outlay.

In this paper, details are given of the facilities design, fabrication and installation and how delivery challenges to Azerbaijan have been overcome, including key lessons learned.

ACG Phase 3 topsides and jackets delivery adopted the same production line approach that was used in earlier phases, cloning the previous topsides and jackets. Subsea facilities had never been successfully utilised in the Caspian. The solution was to establish a production line based on extensive experience of subsea projects in the North Sea and utilising existing Company contracts with subsea vendors as the foundation. The use of established Company North Sea contracts for Phase 3 subsea builds on existing subsea market sector and technical experience, and allows future leverage with contractor performance and life of field support. The strategy that emerged has been successful and resulted in design and fabrication in Europe with transportation to Azerbaijan for installation.

To date the ACG Phase 3 subsea facilities have been successfully designed, fabricated and transported to Azerbaijan. Two of the three manifolds have been installed and the third manifold is planned to be installed in the first half of 2008. This is an industry first in the Caspian Sea, overcoming significant delivery and infrastructure constraints.

Introduction

ACG Phase 3 sanctioned scope included a subsea water injection scheme, the first planned subsea development in the Caspian. This subsea water injection scheme supports the production of approximately 200 MMstb. Due to pre-production of the target reservoirs to both the NW and SE of the DWG area by the previous developments at Shallow Water Gunashli and Chirag, approximately 1000 psi depletion will have occurred prior to first oil in 2008. Therefore early pressure support and recovery by water injection is critically important to achieve economic production rates and reserves recovery, and to limit producing gas/oil ratio to acceptable levels. The provision of pre-drilled subsea water injection wells enabled pressure support to commence immediately from first oil and allow drilling to initially focus on oil production.
How Subsea Processing Impacts Flow Assurance and Field Architecture in Ultra Deepwater
Authors: Saint-Marcoux Jean-Francois , Fontfreyde Thomas
Published: October 2008

Subsea processing covers different functions: flow boosting, gas-liquid separation, gas-oil-water (and sand) separation, and gas compression. These functions offer increasing opportunities along with increasing levels of complexity, and timeframe.

Subsea processing offers new possibilities for flow assurance and production practices. Accordingly, this will modify field architecture, as we know it. All components in the chain from subsea to surface will be affected: manifolds, flowlines, subsea templates, and risers. Noticeably, this will also affect the service and construction industry that will have to adapt to these new requirements.

The paper will describe the flow assurance options made available with flow boosting, gas-liquid, gas-oil-water separation and screen current flowlines and risers options to identify how they are likely to evolve to meet the requirements of subsea processing in ultra-deepwater.

Introduction

For oil producing fields, subsea processing can be classified primarily into flow boosting, gas-liquid separation, and gas-oil-water separation. Subsea compression is applicable primarily to gas producing fields, and at this juncture considered for relatively shallow water projects and not for deepwater or ultra-deepwater. This paper concentrates on ultra-deepwater and therefore subsea compression is not developed further, even though production of gas at elevated pressure can be beneficial as evidenced by Compressed Natural Gas (CNG) concepts.

This paper successively includes a review of oil production subsea processing, a typical ultra-deepwater case, and how the available technology of risers and flowlines covers the needs of these new features.

Subsea Processing

Oil production requires heavy topsides production equipment. This equipment includes the oil production trains, the associated gas compressors for gaslift and gas compression, the water injection system, power generation systems, storage, utilities, and living quarters. The combined weight of all these systems is quite large (typically 25 000T for a 200 000 BOPD FPU). The impact of subsea processing on the size of the topsides is limited and the benefit is not to be gained from a drastic reduction of topsides but from additional production.

Additional production can be achieved through two main technologies:Flow boosting: increase of pressure of the oil-and-gas wellfluid by a multiphase pumpSeparation of the gas from the liquid phase (water and oil) and pumping in liquid phase of the well fluid

A typical oil production train includes three separators in series. The pressure stages are optimized to meet the oil specification such as the Reid Vapor Pressure (RVP). A typical high pressure separator operates in the range of 500 psi (35 bar). As water depth increases, the benefit of subsea processing increases for a given tubing size (usually 5-1/2??).
The Offshore Petroleum Industry in Atlantic Canada - A Regional Overview
Authors: Barnes Paul
Published: October 2008

This paper will give an overview of current and planned future offshore exploration, development and production activity taking place off the east coast of Canada. It will also cover other items of interest occurring in that area including industry related research and development, recent changes in government policy and future growth potential of the industry. Information provided in this paper will be of interest to petroleum supply/service companies wishing to market their goods and services in this region of Canada as it will identify what producers are active in this area and possible future growth opportunities. In addition, the information provided on petroleum related research and development taking place and being applied in the region for offshore development and production would be of interest to a technical audience wishing to apply such research and development to other producing areas.

Introduction

Atlantic Canada is the eastern region of Canada that is comprised of four provinces - New Brunswick, Prince Edward Island, Nova Scotia and Newfoundland and Labrador. The Atlantic Canada offshore oil and gas industry refers to the oil and natural gas exploration, development and production industry off the east coast of Canada. At this time, all offshore petroleum industry activity is taking place offshore Nova Scotia and Newfoundland and Labrador. Fig. 1 shows the Newfoundland and Labrador and Nova Scotia offshore areas.
Functional Verification of the Worlds First Full Field Subsea Separation System - TIORA
Authors: Mogseth Gro
Published: October 2008

The dream of separating water from hydrocarbons on the sea floor is becoming a reality with StatoilHydro's Tordis IOR -Increased Oil Recovery - project in the North Sea. FMC Technologies has delivered the world's first full field subsea separation system, named TIORA, which was brought on-stream at the end of 2007. StatoilHydro expects to improve the Tordis field's recovery rate from 49 to 55 percent - an additional oil production of 35 million barrels.

To ensure success FMC Technologies has invested in a comprehensive test program, beyond the standard subsea functional and mechanical integration testing, to verify right functionality and minimum start-up time. Since the Tordis subsea separation system introduces new types of equipment and functionality in a subsea field development, FMC has performed extended functional testing to secure the technical integrity of the system.

The tests performed were categorized as follows:Technology QualificationsFactory Acceptance Tests (FAT)Extended Factory Acceptance Tests for sub-systems (EFAT)System Operation Test (SOT)System Integration Test (SIT)

These tests also included testing of the two main operational functions:Closed-loop control of the water injection and multiphase pumpsFunction and control of the de-sanding operations through an extended technology qualification

In the System Operation Test, the 2,3 MW water injection and multiphase pumps from Framo Engineering were connected to the FMC control system in order to run a complete functional test of the pump operation. Since separator level and pressure are important parameters in the pumps control algorithms, an online dynamic process simulator was connected to the real subsea instruments communicating through the FMC subsea control module. The control loops were then closed and the tests were performed as close to reality as possible.

For the extended robustness verification of the de-sanding operations, spare modules were combined with purpose-built equipment in a test rig simulating expected operating conditions. In addition to testing, the platform operators used the test facilities for familiarization with the operation of the equipment.

The lessons learned through the additional functional verification tests provided a significant contribution to a smooth and efficient start-up and operation of the subsea separation system, and also resulted in important feedback for use in the design of next-generation subsea processing systems.

A softer lesson learned is that tests need to be planned in an overall test road map to ensure that all tests provide a combined better knowledge of the system - without degrading the resulting overall system performance.
A New Flexible Pipe System Replaces Submarine Hoses In SBM
Authors: Heijst Willem J.
Published: October 2008

The application of single buoy mooring systems as offshore terminals for VLCC's is now generally accepted. Large diameter hoses - 2 or 3 strings parallel - are used to transfer the crude oil from the sea bottom pipeline manifold via the terminal to the tanker manifold, or vice versa.

When the submarine hoses are replaced by articulated piping (comprising a vertical pipe connected to the SBM and a horizontal pipe connected to the sea bed, both sections linked together and all connections being made by universal joints), the reliability of the terminal will be strongly improved if the components of this pipe system are properly designed.

The design criteria have been obtained from extensive model tests on single and double systems and through calculations, whilst the components of the flex pipe system are and have been tested on full-scale. Great care is given to fatigue strength to predict life-time of the system on site and maintenance procedures are studied and tested on full-scale to prevent any unexpected situations when installed.

INTRODUCTION

The single buoy mooring system, apart from acting as a crude oil terminal, is also employed for the transfer of other fluids, in particular petro-chemicals, bunker oil, gas and even iron ore slurries. Until now the underwater link between pipeline manifold and the SBM has been provided by flexible hoses.

This hose string must be relatively long in order that the buoy may ride easily and without restriction on the sea surface at high tides and at maximum expected wave heights. At low tide, the hose string should not bend beyond the safe bending radius, nor chafe along the anchor chine or along the bottom. Finding the right length of hose string and configurations to meet all these criteria presents a certain amount of difficulties.

Two basic configurations in use are the Lazy-S and the Chinese Lantern, both based on a delicate balance between the rigidity and an equilibrium obtained by counter-balancing the hose weight with either buoyancy tank or floats. Factors which disturb this balance are currents, waves, buoy motions and changes in the specific gravity of the fluids pumped through the hose. Static model tests are usually carried out to define the optimal lay-out, and in some difficult situations the dynamic behavior of the underwater hose lay-out has been tested in the NSMB model tank basins in Wageningen.

The design of an underwater hose lay-out for Several large diameter hoses in parallel for rough areas with strong tidal currents is extremely difficult since the radius of permissible bend is obviously large for such hoses and the deviation that can be tolerated from the neutral position is therefore small.

THE FLEXPIPE SYSTEM

In order to overcome the restrictive requirements for the application of an SBM using such hoses, the "Flexpipe" system has been developed. The system comprises a vertical pipe connected to the SBM, and a horizontal pipe connected to the sea bed pipeline manifold.
Alaskan Beaufort Sea Exploration and Production Islands - Civil Design and Construction
Authors: Lucas Jim , Masterson Dan M. , Hall Jerome D. , Perry Conrad Joseph
Published: October 2008

A civil engineering perspective is presented on the design and construction of exploration and production islands in the nearshore Alaskan Beaufort Sea. Pioneer Natural Resources' 2003 Thetis exploration ice islands and the subsequent 2006 Oooguruk production island in East Harrison Bay are highlighted. Engineering design issues are discussed including special techniques required for the severe ice, wave and permafrost environment. The effectiveness of using frozen gravel foundations, which must be designed for seabed settlement, gravel thaw-settlement and creep settlement, are discussed. Construction techniques and schedules have been developed to make use of the readily available ice and gravel. Monitoring performance is an important post-construction activity. Potential issues are identified with preventative and remedial solutions described.

Three offshore exploration wells were drilled using conventional land-based equipment from grounded ice platforms during the course of one winter. Subsequently, a gravel production island was built in the same area using material hauled from shore. Seabed settlement and the thaw instability of frozen gravel are uniquely addressed in the design and construction of the island.

An economical approach has been described for building temporary exploration structures and permanent production structures in shallow, protected nearshore waters of the Alaskan Beaufort Sea. The methods have applicability for accessing smaller offshore oil and gas fields in the Alaskan Beaufort Sea and in other cold regions of the world where similar marine conditions exist.