Brines are preferred to solids-laden fluids for completion operations due to their solids-free nature, which helps preserve formation permeability. Salt selection is mostly driven by the density that must be reached to match downhole pressure requirements. When density must be above 14.2 lbm/gal (1.7 s.g.), and crystallization must be prevented, previous options were limited to calcium bromide brines, zinc bromide brines and cesium formate. These brines have severe limitations: zinc brines can be harmful to oilfield personnel and the environment, cesium formate brines are cost-prohibitive and not readily available and calcium brines cannot meet deepwater crystallization requirements. A new brine technology has been developed, that is zinc-free and extends the density of conventional bromide brines beyond their theoretical limits. This new technology addresses the limitations listed above, while providing low True Crystallization Temperature (TCT) and Pressurized Crystallization Temperature (PCT) to perform in deepwater and cold weather applications. This paper summarizes the completion fluid properties, laboratory qualification and verification, and summarizes recent successful field applications of the new high-density zinc-free brine.

The Shearwater field is a deep, high-pressure, high-temperature (HPHT) reservoir located in the UK Central Graben of the North Sea. The current drilling campaign represents the first round of well re-entries into the field following a campaign of slot recoveries to facilitate sidetrack development opportunities. A high level of reservoir depletion (> 8000 psi) has resulted in significant changes to the drilling envelope that has added complexity to the drilling practices required to successfully exploit the remaining reserves. Managed Pressure Drilling (MPD) Technology was pursued as an enabling technology to navigate within some very narrow margins in the first well of the redevelopment campaign. MPD was implemented in conjunction with drill-in liner and wellbore strengthening technologies to successfully deliver this first well and prove the techniques required to prolong field life. To promote successful implementation of MPD in the target zone, the technology was employed in the previous hole section to gain experience with the equipment and procedures where pressure control was less critical. MPD was used to control bottom hole pressure to manage background gas and facilitate changes to equivalent mud weight. It was further used to minimise the effects of loss/gain mechanisms and enable drilling through a tight margin between pore and fracture pressure while reducing the risk of borehole instability and losses. The technology was also used to determine appropriate mud weights for tripping and provide trip margin to avoid swabbing while tripping. In addition, MPD was used to facilitate cementing in tight margins. This paper will highlight the multiple uses of MPD throughout the start-up of this current drilling campaign and key learnings enabling successful implementation of a new technology on the rig.

High-pressure high-temperature (HP/HT) reservoirs contain hydrocarbons at pressures and temperatures in excess of 10,000 psi (690 bar) and 300 °F (149 °C). The high pressure often requires the installation of a high-integrity pressure protection system (HIPPS) to facilitate a workable pipeline concept and to prevent over-pressurisation. Should the HIPPS fail to respond to an overpressure event, the pipeline may be exposed to pressures in excess of a code-allowable design. It is, therefore, important to fully understand the pipeline behaviour, especially the burst limit state, to ensure compliance with the pressure containment philosophy, i.e. “burst critical” or “no burst”, and the associated probabilities of pipeline failure due to bursting. Generally, a probabilistic analysis will be performed using existing models that predict the burst capacity of straight sections of pipe under the effect of internal overpressure. In reality, pipelines are subjected to additional loads over and above pure pressure loading; for example, thermal loading will induce compressive axial loads in the pipeline due to pipe-soil frictional resistance. Pipelines are also frequently subjected to bending loads due to a variety of causes; for example, freespans, trenching induced bending, or lateral buckles. To understand the burst behaviour of a pipeline, the effects of bending and themally induced axial compression in conjunction with internal overpressure must be understood. This work shows that finite element analysis (FEA) can accurately predict the occurrence of pipeline failure due to burst. The FEA is validated by subjecting models of a straight pipe to internal overpressure until burst occurs, and comparing the burst pressure and strains at burst to the predictions made by an analytical model. Subsequently, the FEA incorporates various magnitudes of bending (representative of the range of bending that may be induced by prop-type imperfections up to 0.5 m in height) before internal pressure is applied. Both displacement and load controlled bending are investigated, as well as cases that consider thermally induced axial compression. The burst behaviour of the pipe for the various cases is compared to confirm whether the analytical model is still valid in cases when bending and/or temperature are present. Thermal loading and displacement controlled bending are found to have negligible effect on burst capacity, because the axial compressive and bending loads are “shed” as the pipe becomes plastic and reduces in stiffness. However, it is observed that there is a significant change in burst capacity for load controlled bending, and hence the analytical model is no longer valid. This is because the applied moment is, by definition, maintained and unable to be shed; instead, the imperfection shape changes significantly to satisfy the loading condition as cross-section plasticity and the associated reduction in stiffness are experienced.

The paper addresses the use of steel chains in a lazy wave configured flexible riser system to provide an alternative flexible riser configuration for use in challenging environments including large vessel offsets and motions, and large ranges of riser internal fluid properties. While the compliant nature of flexible pipe provides excellent fatigue and strength resistance, flexible risers typically experience larger deflections when compared with rigid risers, which results in greater challenges managing interference issues with adjacent structures. Different lengths and variable masses of chain are installed at locations along the hog bend of the flexible riser configuration. The arrangement of the chain masses, length and positioning along the line are developed to primarily prevent contact with the seabed and the hull of the FPSO when a range of heavy and light internal fluids are considered. A number of weighted steel chain configurations are evaluated and presented through an analytical case study in order to demonstrate the benefits of this approach for a typical generic shallow water application FPSO system. Installation and hardware design aspects are additional requirements that may need to be addressed in further assessments. Through the in-place case study, comparisons are made between the performance of the flexible riser system with and without the weighted steel chains. Global finite element models are developed to simulate the performance of the different flexible riser configurations when subject to a range of loading scenarios covering large FPSO offsets, harsh environmental conditions and a range of riser internal fluid densities. Performance criteria of the flexible riser such as tensile loading, curvature and motion envelopes are presented to show the improvements derived though optimisation of the chains. It is also demonstrated that the chain section that extends along the seabed helps to reduce the transverse displacement and “lateral walking” thus reducing the risk of clashing with adjacent structures and changes in line lay azimuth under strong transverse current loading. The cost effectiveness of the chain weighted flexible is also compared to other solutions considering new and retro-fit applications. This work demonstrates that an improved and cost effective solution is developed to provide an acceptable flexible riser dynamic response for the range of operational fluid densities that may be experienced in its operational lifetime.

Abstract The standard workflows for predicting field performance in the oil and gas industry is not effective when dealing with highly deforming reservoirs. The definition of highly deforming reservoirs with high risk is not well defined, but these fields typically produce development surprises like casing deformations, drilling problems, well failures and in some cases reservoir performance prediction challenges. In cases like this, production from wells can cease although the upfront reservoir flow models have predicted many years of production and revenue. When the deformation is substantial enough, it will also result in surface subsidence that could impact surface facilities, platforms, pipelines and environmental sensitive areas. This paper presents a more robust workflow and toolkit for these challenging reservoirs than the traditional industry workflows used most often today. The workflow is expanding the traditional workflow to also include computational geomechanics as a critical part of the field performance prediction and management. The workflow and toolkit is illustrated by a field case, the Valhall field, where substantial cost savings already have been experienced from implementation of the workflow and toolkit. Introduction This paper is presenting a new workflow and toolkit that can be used to develop highly deforming reservoirs in a more cost effective manner. A field case is used to illustrate the economic impact from using the more robust computational geomechanics based workflow. The field case is one of the more extreme end members of highly deforming reservoirs, the Valhall chalk field in the Norwegian part of the North Sea. For more details on the field see Ali and Alcock (1994) and Barkved et. al (2003). The workflow has been developed for Valhall over a 10 year period and has already had substantial economic impact as will be illustrated in some of the examples later. There are a large numbers of publications addressing challenges related to highly deforming reservoirs. A very good overview paper is the one by Dusseault et. al, 1998 including many key references. The similarities in these field developments is the additional cost to recover the hydrocarbons over and above what one would plan for using standard reservoir characterization and performance workflows. The basic process behind these additional costs is related to reservoir deformations that are a bit more excessive than "normally" encountered. We will therefore start this paper by reviewing the basics involved in reservoir deformation. Figure 1 is illustrating a cross section of a reservoir at depth. The reservoir consists of porous sediments containing hydrocarbons in the pores. Above the reservoir there are overlaying sediments. The weight of these sediments is resting on the reservoir. This weight is often referred to as the overburden or the vertical total stress. As the hydrocarbons are produced the pore pressure is lowered and more of the overburden load carried by the pore pressure is transferred to the rock grains and causing deformations of these and reducing the pore volume. How much is dependent on deformation properties of the reservoir rock. If we assume uniaxial strain conditions (no lateral deformation in the reservoir), something that can be an oversimplification in some cases, one has the following relation for deformation in Figure 1:

Abstract Many forms of "beat-the-curve" incentive contracts are in use in the drilling industry to reduce cost and improve project performance. A successful variation involved drilling conventional deviated wells from pads in less than two-thirds of the budgeted time for a lump-sum fee. Modulators, included in the contract to account for nonproductive times (NPT), were subsequently used to adjust the lump-sum fee, depending on the party responsible for the NPT. Historically, the deviated hole sections were drilled with turbines and local tricone bits requiring multiple trips for bit changes, turbine bent-housing setting changes, and directional surveys. The new plan included the use of a telemetry system, positive displacement motors, and polycrystalline diamond compact (PDC) drill bits. One run per section was targeted, and results were achieved after a few wells by experimenting with several bottomhole assembly (BHA) configurations and PDC design combinations. The wells were drilled in 22 to 26 days instead of the originally planned 40 days. These results are attributable to a concerted effort by the operator, drilling contractor, and the service companies to identify and eliminate "invisible" NPT by applying fit-for-purpose technology and better planning. Several time-saving practices were also adopted. A main contributor to the success was that the local drilling contractor adopted the mind-set change for all the contractor rigs, including those not associated with the project. Cooperation developed the means to overcome the limitations of the drilling equipment belonging to the drilling contractor: first, an external audit identified critical areas needing immediate improvement, and then these areas were subsequently remedied jointly without creating a heavy financial burden on the drilling contractor. Introduction Historically in Russia, all boreholes were S-shaped until the introduction of horizontal drilling1 with western technology several years ago. The S-shaped wells were drilled from pads constructed in swampy fields that were actually frozen for 8 or 9 months of the year but were extremely soft other times. Owing to the nature of this environment, it was desirable to drill as many possible wells from the same pad to minimize location cost. In some cases, this meant drilling to large-displacement downhole targets up to 2 km from the pad location. Russian manufactured rigs have successfully been used to drill these wells in conjunction with Russian technology and equipment (turbines, telemetry system, aluminum drillpipe, and drill bits). However, inherent problems with the technology in use included the following: inability to rotate with aluminum drill pipe frequent bit trips owing to short bearing life frequent trips for bent-housing setting adjustment to correct inclination and azimuth old, time-consuming surveying method. These problems not only caused invisible lost time but also created tortuosity in the wellbore, making subsequent operations rather difficult and requiring extensive hole reaming where corrections were made. As a result, it was standard practice to make frequent reaming trips and a final checktrip with a nearly full-size stabilizer to increase the chance of running casing to the bottom. This phenomenon was in contrast to observations in analogous sections while drilling horizontal wells with pilot holes; therefore, the operator was approached to consider using similar western technology to reduce drilling times dramatically. It was hence the beginning of the targettime based performance contract. This paper describes the processes and methodologies applied which brought about the results.

Abstract The cementation of any casing string is an integral part of well construction. The main objective of primary cementing is to provide complete and permanent annular isolation from mechanical and chemical stresses during drilling and production stages of the life of the well. Through tubing rotary drilling (TTRD) technology presents its own challenges to cementing design. The management of the equivalent circulating density (ECD), typically at its highest levels during the final stages of the cement slurry displacement, is a critical parameter of the fluids design process. The use of bi-centre drilling bit design, which achieves a larger open hole size than the pass-through diameter, introduces centralization difficulties and add complexity to the removal of the drilling mud prior to cementing. The accepted cementation approach for TTRD wells is to formulate low rheological fluids such that, maximum advantage can be taken from the annular velocities for mud removal efficiency. By challenging the common design practices a design was proposed that combined low and high rheology fluid properties to achieve the objectives set out for the cementing operation of the 2 7/8 inch liner. Introduction Achieving complete and permanent annular isolation by the cement slurry is a challenge that is not particular to TTRD. The parameters that affect the quality of the cement bond with both the formation and the casing surfaces are well documented and can, in most cases be addressed by taking into account the specific objective for each operation. Whilst 100% bond index across non-reservoir / non-critical zones cannot be justified, the target reservoir zones required pressure competent isolation. The TTRD liner cementation for the J25 well was critical to the success of the project as failure to isolated the complex pressured multi-zone reservoir would create well production difficulties that would compromise the viability of the project. From the hydrodynamic discipline the success of a cementing operation is entirely dependant on completely removing the drilling mud from the section of the annulus elected for isolation. To this effect, a spacer fluid is pumped ahead of the cement slurry, to displace the drilling mud using one of two criteria: Displacement by the effects of the kinetic energy transferred to the fluid from the pumping rate Displacement by the inherited design properties such as density, friction pressures and minimum pressure gradient (MPG) of the fluid. In reality, due to the parameters set by the multi-discipline design requirements involved at the well construction stage, the centricity of the pipe in relation to the open hole is unlikely to be optimum over the entire length of the selected annulus. The fluid dynamics model, for a given cross section of the well, will be characterized by the velocity differential between the wide and the narrow annulus. The successful removal of the drilling mud depend largely on the level of understanding of this velocity profile and engineering practices used to develop the adequate fluid placement sequence.

Abstract Some recent experience is presented of the structural analysis of subsea completions subjected to bending loads. The paper looks at the stresses and internal loads induced near the mudline in the wellhead, conductor and casing and, in particular, the effect of cement shortfalls and different soil conditions are explored. The insight obtained to structural performance by this type of analysis is performance by this type of analysis is shown to be invaluable and can lead to the design of more efficient structures. As a result, safety can be improved. Introduction The move towards drilling wells in deeper water has resulted in a re-assessment of well completion structures and their design. Whereas reliance could be placed on a wealth of previous experience where installations lay within well-established water depth and well pressure limitations, this is no longer so as these bounds are being exceeded. Furthermore, it is now considered that reduced costs can be achieved and safety improved by a more thorough study of how the conductor, casing and template (if present) interact. For most locations, with standard wellhead configurations, stress limits will only be exceeded if the drilling rig mooring system fails. Operations should have ceased with the riser disconnected prior to the onset of weather conditions which could lead to critical conditions. However, in areas of known high currents, deep water, poor seabed conditions, or with non-standard wellhead design, unacceptable loads may occur. In these cases serious consideration should be given, at an early stage of well planning, to a rigorous analysis of the completion structure in order to identify critical conditions which may arise within the operating envelope of the drilling vessel and during its production life. production life. When it is considered that abandonment of a poorly designed well could cost several poorly designed well could cost several million pounds sterling, and perhaps much more should environmental pollution result, a detailed structural analysis could be financially well worthwhile and should be regarded as essential to successful design. This is now common practice with at least one operator. DESIGN OVERVIEW Environmental loads, transmitted through the drilling or production riser, have an impact on casing design only in the vicinity of the mudline to a depth of a few tens of metres, depending upon the attenuating effect of the soil. Above this level, the interaction of the casing and conductor is potentially very complex. At depth, the casing design is governed by formation geometry and pressure. Note that the objective of the type of analysis being discussed herein is to validate the design of the conductor and casing rather than of the wellhead and conductor housing. P. 185

Permission to copy is restricted to an abstract of not more than 300 words Permission to copy is restricted to an abstract of not more than 300 words Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper was presented. Publication elsewhere is usually granted upon request provided proper credit is made. Introduction This paper presents a discussion of methods by which typical North sea piled, steel production platforms may be examined to production platforms may be examined to establish their behaviour in the event of an accident sufficient to cause structural damage. Types of possible damage are presented in this paper. They might be caused by an explosion, paper. They might be caused by an explosion, by the dropping of large objects, the rupture of a gas riser causing a hydrocarbon jet fire (high intensity fire) or, in the case of an oil riser, a pool fire (lower intensity fire). Damage may occur to any of the primary components that comprise a production platform, namely the jacket, cellar deck (or platform, namely the jacket, cellar deck (or MSF), or modules. The broad findings from a study of atypical platform are presented together with a discussion of the salient results and conclusions. To analyse separate parts of a platform whether modules alone, jacket alone, or combinations of structures that comprise the platform, it is beneficial to carry out a platform, it is beneficial to carry out a nonlinear, progressive collapse analysis. Applied loads are increased from zero to some pre-determined level, and the behavior of the pre-determined level, and the behavior of the damaged structure monitored for each loading increment. Such an analysis would predict the initial failure of members and introduce one, two or three hinges per member as loads are increased. It would account for P - delta effects associated with large deflections and would fully account for load and moment redistribution as members form three-hinge mechanisms. The computer program USFOS, developed by SINTEF, the Foundation for Scientific and Industrial Research in Norway, has been used successfully by John Brown to examine the possible behaviour of damaged platforms. This possible behaviour of damaged platforms. This paper presents some of the work that has been paper presents some of the work that has been completed to date using this advanced nonlinear analysis tool. 2 HAZARDS WHICH COULD AFFECT THE STRUCTURE A major accident which endangers lives or causes severe damage to a structure or equipment is normally a result of inter-connected events. Explosive rupture of a pressure vessel, for example, will lead to fragments travelling at high speed which may penetrate pipes containing high pressure penetrate pipes containing high pressure flammable substances. In turn, a turbulent, intense fire may develop which will cause damage to equipment supports or a whole module structure. This may lead to sliding equipment and in toppling into the sea. The falling objects may damage the substructure or ESD valves. The main hazards which could affect the load bearing capacity of structures are (Figure 1): Fire in the superstructure area causing local and/or global failure of module frames, the deck or equipment supports. This would cause re-distribution of module stiffness and reaction forces and it may result in large objects sliding, toppling falling into the sea and damaging the substructure.

ABSTRACT This paper describes a dewatering operation on the Texaco Highlander Subsea Production Facility located in the North Sea approximately eight miles north-west of the Texaco Tartan platform. Difficulties in commissioning gas lift operations on remote subsea wells were attributed to hydrate formation and unsuccessful dewatering after pressure testing. The geometry and changing diameters of the gaslift line were complicating factors. A new application of foam technology was made and this paper describes the background to the task and gives a record of the practical operations undertaken. The job was successful and the various further applications of this type of technology are discussed. INTRODUCTION A subsea gaslift system had been installed in the autumn of 1985 connecting the Highlander subsea production facility in the UK sector of the North Sea to its parent Tartan platform. Hydrate blockages were occuring each time the start-up of gaslift was attempted and this indicated that the dewatering procedures previously adopted had been unsuccessful. This paper outlines the approach taken to solve the problem and introduces a new application of foam technology. It is also believed that this was one of the very first successful operations of a remote subsea gaslift system. The technique has proven to be very efficient from both viewpoints of cost and logistics. The technology outlined is the subject of a joint patent application and has wider potential uses which are briefly discussed in the concluding sections. THE HIGHLANDER SUBSEA PRODUCTION FACILITY The Highlander subsea development is located eight miles NW of the Tartan platform in the British sector of the North Sea (see figure 1).

Member, SPE-AIME IMCO Services Houston, Texas Abstract A new firmware module has been developed for a popular series of hand-held, programmable calculators. Use of the module can help to minimize programmable calculators. Use of the module can help to minimize the occurrence of kicks and blowouts, facilitate well-control training and certification, and assist well-planning activities. The module can be used by all levels of drilling personnel in routine and critical situations. It is programmed to handle calculations for surface/subsea BOP stacks, land/offshore locations, gas/saltwater kicks and straight/directional wells. The engineering programmes can be run in standard oilfield or SI metric units. The purpose of this paper is to describe both the operation and development of this module. Major emphasis is placed on the use of the module in well-control and drilling operations. Introduction Only a small percentage of the wells drilled today blow out. This is the result of over 80 years of equipment development, and improvements in engineering and training technology since the first blowout at Spindletop on 10 January 1901. The 80 years of technology are concentrated into a single firmware module for Texas Instruments' (TI's) Model 58, 58C and 59 programmable calculators.

Introduction Sea water injection to maintain reservoir pressure is currently practised in several North Sea reservoirs viz: Beryl, Forties, Montrose, Piper and Claymore. Injection wells may be completed wholly in an oil bearing zone (pattern flood case) or partly in an oil bearing or transition zone (peripheral flood case). In either case the rate of water injection is restricted by the presence of crude oil in the pores of the rock particularly in the region immediately around the well. This oil is immobile despite continued water injection. The injection rates can be raised, however, if the oil in this critical region is removed as the conductivity (permeability) of the formation will be increased. Very considerable increases in injection rates were reported by previous investigators who used micellar solutions (complex surfactant solutions) to stimulate wells by residual oil removal.