Hutton TLP Marine Operations

Well completions for tension leg platforms require special consideration in key areas. Standard downhole equipment including subsurface safety valves can be used in a conventional manner from TLP's. Special designs, however, may be required for annular safety systems or sales risers.

The Auger Tension Leg Platform (TLP) is held on location with twelve steel tubular tendons mechanically latched in groups of three each to four individual foundation templates precisely positioned on the sea floor in record water depths. Each template is secured with four piles driven into the sea floor and mechanically swaged into the template guide sleeves. This paper overviews the major facets in the design, fabrication and installation of the foundation templates and piles that comprise the Auger TLP Foundation System. Design considerations discussed include structural detailing to suit fatigue, mechanical interface requirements, and tension pile effects. Although the template fabrication was conventional, dimensional control, weight/center of gravity control, and testing of mechanical system interfaces were essential to the success of the installation. Extensive installation engineering and planning were conducted, including the development of several purpose-built installation aids. An overview of the sequence of field operations to lower and accurately position each template, run and stab piles in each corner sleeve, drive piles to grade with an underwater hammer, and finally swage each pile into structural load carrying grooves in the template guide sleeves is presented. Contingency plans and procedures prepared to deal with precise position and level tolerances are discussed. The descriptions of the field operations highlight the methods that were used to adapt existing construction vessels and equipment to work effectively and reliably in the deepest water yet attempted for a TLP installation. INTRODUCTION Shell Offshore Inc. 's Auger Tension Leg Platform is located in the Gulf of Mexico in Garden Banks Block 426 at a nominal water depth of 2860 feet. Particulars of the four foundation templates and sixteen piles are as follows: Templates Dimensions 60 feet × 60 feet × 48 feet (L × Wx H) Weight (dry) 611 s. tons Piles Dimensions 72 inch 0.0. × 427 feet Weight (dry) 203 s. tons Contracts for the fabrication and installation of the templates and piles were awarded in March, 1992 to Aker-Gulf Marine of Ingleside, Texas, and HeereMac v.o.f. of Leiden, The Netherlands, respectively. Fabrication was completed late November, 1992, and installation completed late December, 1992. Design Three tendons per corner are attached to each independently placed foundation template. An isometric view of the template is shown in Figure 1. A view of the seafloor elliptical well pattern and the foundation templates during installation operations is shown in Figure 3. The template tendon receptacles are located such that the tendons hang vertically when the TLP hull is centrally located over the well pattern. Each foundation template transfers tendon loads to four 72-inch diameter, vertical piles driven to a penetration of 374 feet below the mudline. Load cases The load cases and design safety factors are shown in Table 1. The direction of load application was assumed from 0° to 360° in 22.5° increments.

Fabrication of Hutton tension leg platform (TLP) required the implementation of welding and materials engineering technology in a manner that had not been generally experienced in the offshore industry. This paper addresses several issues that were necessary to ensure the successful and sound fabrication of the Hutton TLP. These issues include project planning and organization, materials and fabrication specification, the primary causes of fabrication problems, defect tolerances, and fabrication problem prevention and resolution. INTRODUCTION The tension leg platform (TLP) is an evolutionary form of semi submersible, connected to piled foundation templates on the seabed by vertical mooring lines instead of the cautionary mooring used on drilling semi submersibles. The TLP's dynamic behavior is similar to that of an inverted multifilar pendulum where the TLP's excess buoyancy provides the restoring force, instead of gravity, to keep it on station. Lateral plane movements of surge, sway, and yaw are compliantly restrained, while vertical plane movements of heave, pitch, and roll are stiffly restrained. The TLP concept provides several advantages over other structural concepts in exploiting deep water reservoirs. These prospective advantages include accessibility and maintainability of well and riser systems because of the TLP minimal vertical motions, simplification of field abandonment, and reduction of the expensive and weather sensitive offshore work by completing fabrication, outfitting, and hookup of the structure and facilities inshore. The TLP also has the advantage that the structural costs are not greatly increased for deeper water. Several of these advantages have been demonstrated by the TLP which was installed in 1984 at the UK Hutton Field in the North Sea. General descriptions of the design features of the Hutton TLP have been presented in several descriptive papers.l–3 Since the Hutton TLP (Figure 1) represented the first application of this new platform concept, several engineering tasks, including fabrication, had to be carefully addressed. Although the fabrication of the Hutton TLP was accomplished using conventional technology, it was unique because it required an implementation of that technology in a manner that had not been generally experienced in the offshore industry. In addition to its larger size, integrated deck, and relative structural complexity, the Hutton TLP is different from semi submersibles in that it will stay on station for its entire life without the possibility of dry docking. The importance of fabrication quality control cannot be overestimated in respect to this significant factor. The relative structural complexity that exists in the Hutton TLP hull is illustrated in Figure 2. This degree of complexity, in addition to its many kilometers of welds, results in poor welder and inspector access. It presents a challenge to achieving the requisite quality control standard and cannot rationally be used to condone low quality levels (i.e., quality control must match the job requirements and not be applied at the same level for every job).

This study presents the technical feasibility of replacing a connector and flex-joint with a titanium stress joint and a collet connector as components of a tendon system for a Tension Leg Platform (TLP). A detailed analysis of this new tendon system is presented for 2,000 feet of water depth in the Gulf of Mexico. The main conclusion of this study is that this new approach is feasible and replaces effectively the flex-joint used in previous TLP tendon designs. The new system has no moving parts, long fatigue life and works even better for the deep water cases. INTRODUCTION Figure 1 shows the general layout of a TLP platform with a tendon system anchored to the foundation template. The purpose of this study is to demonstrate the technical feasibility of replacing the connnector and flex-joint used in conventional TIP tendon design, with a titanium stressjoint and collet connector tha thas a stinger. The titanium stress joint provides the required flexibility for the maximum angular offset at both ends of the tendon. The collet connector provides the latching capabilities of the tendon to the receptacle of the foundation template. A stress joint connection at the bottom or top receptacles induce high bending moments at both ends of the tendon due to the lateral motion of the TLP. The stinger increases significantly the strength of the connector to resist high bending moments. The new tendon system uses the stinger approach at both ends of the tendon. Hutton and Jolliet, the only two TLP platforms installed as of 1992, use a flex-joint at both ends of the tendon system. Hutton TIP uses at the bottom a Vicker's connector design with a collet locking system that engages the male stinger into the female receptacle located on the ocean floor. The Murdock flex-joint is built into the anchor housing. The fabrications of these joints use alternate layers of elastomer and partial spheres of stainless steel reinforcements to provide the required axial and angular spring area to accommodate a maximum angular offset of 16.6 degrees. The design of the tendon system for Snorre TLP follows very closely the design adopted for Hutton. Jolliet follows a different design with a different latching mechanism at the bottom. Figure 2 shows the approach used in Jolliet for the bottom connection. The fabrication of the receptacle for the bottom tendon connection uses a load ring forging that has a cone shaped rolled plate skirt. The load ring assembly is welded into a structural stiffener fabrication which makes up the foundation template. The shroud of the connector has a slot that allows the lateral engagement of the male back flange of the tendon. The load ring and skirt assembly match the outward orientation of the tendon receptacle slot. The flex-joint is a ring built into the bottom part of the tendon. Several layers of elastomer bearings and metal sheets define the flex-joint. The fabrication of thetop tendon connection receptacle also uses a load ring forging with a cone shaped rolled plate skirt.

The global floating offshore wind energy industry is rapidly maturing with several technologies having been installed at pilot and demonstration scales. As the industry progresses to full array-scale deployments, the optimization of marine activities related to installation, operation \& maintenance and decommissioning presents a significant opportunity for cost reduction. This paper reviews the various marine operations challenges towards the commercialisation of floating wind in the context of spar-type, semi-submersible and Tension Leg Platform (TLP) technologies. Knowledge gaps and research trends are identified along with a review of innovations at various stages of development which are intended to widen weather windows, reduce installation costs and improve the health and safety of floating wind related marine operations.

The global floating offshore wind energy industry is rapidly maturing with several technologies having been installed at pilot and demonstration scales. As the industry progresses to full array-scale deployments, the optimization of marine activities related to installation, operation \& maintenance and decommissioning presents a significant opportunity for cost reduction. This paper reviews the various marine operations challenges towards the commercialisation of floating wind in the context of spar-type, semi-submersible and Tension Leg Platform (TLP) technologies. Knowledge gaps and research trends are identified along with a review of innovations at various stages of development which are intended to widen weather windows, reduce installation costs and improve the health and safety of floating wind related marine operations.

A major pipeline company was tasked with decommissioning the Morpeth tension leg platform (TLP) in the Gulf of Mexico (GoM) and needed to abandon a 22-year-old, 8-in gas export steel catenary riser (SCR). The conventional approach to decommissioning an SCR is to mobilize a topside winch package, which sometimes requires the removal of platform equipment. The next step is to carry out structural engineering checks on the platform, determine the wire's various drop point routes through the platform, and provide the engineering analysis necessary to handshake the load from the winch to a heavy lift vessel for abandonment. This was the original plan for the Morpeth TLP SCR decommissioning program. Instead of employing this traditional approach to remove the riser using a topside winch package and heavy lift vessel, the pipeline owner requested an alternative method that had been used previously for an international operator. This novel method employed ROVs and divers to install a series of clamps to grip and secure the riser prior to cutting and used a Multiservice Vessel (MSV) to manage the disconnected riser for abandonment on the seafloor. The appeal of this integrated solution is that it does not interfere with the platform's topside operations or equipment layout and can provide potential cost savings. This methodology was used for the first time in the GoM to remove a riser to make space for a new one to be installed. For this installation, a clamp was designed by the operator to sit on the J-lay collar and to support the weight of the riser being removed. The project was modeled in OrcaFlex to determine safety requirements and the service company carried out the riser removal. Following adaptations to accommodate the differences presented by the Morpeth TLP SCR, a similar approach was used in the SCR decommissioning project, with the service company's engineering team designing a combination of a friction and through-pin box clamp, determining their placement, mapping out the role of divers, and defining the necessary vessel movements for each phase of the operation. Following an initial survey to determine the profile of the SCR, the service company created an OrcaFlex model and decommissioning plan that would allow the vessel to safely execute the program. The model allowed the team to incorporate safety factors to ensure that the load of the riser could be managed and that the riser could be handled without jeopardizing the safety of the vessel or creating riser clashing during the process of cutting and swinging the riser away from the TLP. It was determined that a winch wire could be cantilevered off the stern of the vessel to provide overhead access to the riser and clamp connection point. With the clamps properly connected, the riser was severed in a controlled manner by ROVs and then abandoned within the right-of-way (along the pre-approved area) of the pipeline prior to the ends being plugged and covered. In comparing the actual dynamic loads monitored during the operation with a line rider, it was confirmed that the model was within 5% of the expected loads, estimated at 54 metric tons. This paper explains how an unconventional method of SCR decommissioning allowed execution entirely from the MSV without impeding the operator's decommissioning schedule or conflicting with the work of other contractors on the platform to provide substantial cost savings. The solution also can be used to replace existing risers, whether the useful life of the platform exceeds the useful life of the riser and/or in the case where new field development requires a new tie-in. Other deepwater, vessel-based decommissioning solutions include the abandonment and/or recovery of flushed umbilicals and potentially the abandonment of flexible catenary risers. Following successful execution of the SCR decommissioning project, the pipeline company requested a FEED for using this integrated decommissioning solution for additional offshore assets. It was also requested that the clamp design be ROV installable. The study is for a three-year program to abandon five export SCRs on multiple TLPs in the GoM with loads upwards of 350 metric tons. The abandonment method to be employed for the upcoming SCR decommissioning program is the same as the one described in this paper, with execution from a single, standalone MSV.

SummaryConocoPhillips is developing the Magnolia field with a Tension Leg Platform (TLP) in 4,674 ft of water at Garden Banks (GB) block 783 in the Gulf of Mexico (GOM) (see Fig. 1). The field was discovered in 1999, and appraisal wells were drilled in 2000 and 2001. The well-construction strategy included drilling six additional development wells from a mobile offshore drilling unit (predrilling) before the installation of the TLP. Drilling the new wells consisted of two phases: batch-setting all six wells through 20-in. casing, followed by deepening the wells to a total depth (TD). The wells targeted multiple zones resulting in complex, designer directional wells with 50° to 60° maximum hole angles. This paper examines the application of drilling best practices used to deepen the wells to TD after batch-setting operations were complete (Eaton et al. 2005).To minimize drilling costs while deepening the wells to TD, project goals were to eliminate trouble time; minimize combined drilling, circulating and tripping time per interval; maximize simultaneous activities; and reduce the number of trips necessary to drill the well. The goal of achieving Best-in-Class performance requires detailed planning, documenting, and implementing of results and lessons learned; effective communications; equipment quality control; and implementation of a team environment with all the companies involved in the drilling program. The complex high-angle wells require employing extended reach best practices to balance on-bottom drilling performance with the ability to effectively clean the hole to enable trouble-free tripping of the bottomhole assembly (BHA), running of casing, and obtaining primary cement jobs.The best practices discussed in this paper include changes made to improve rotary steerable reliability; simultaneous drilling and under reaming BHA design (Eaton et al. 2001); hole cleaning; and torque and drag monitoring. The paper also discusses activities that reduced the number of required trips and activities conducted out of critical path, such as moving the subsea blowout preventor (BOP) from wellhead to wellhead with an innovative BHA, a BHA to run and retrieve wear bushings, subsea guidebase installation by way of a winch and remote operated vehicle (ROV), off-critical-path makeup of BHA components, and drillstring management.

Summary The Hutton field, discovered in 1973, is located in U.K. Block 211/28 about 275 miles [440 km] off the Shetland Islands in 485 ft [148 m] of water. The 1979 decision to proceed with field development was significant because the structure selected would become the world's first commercial tension-leg platform (TLP). This operational review covers the predrilling and completion of the first 10 wells from a semisubmersible drilling rig, their subsequent tieback to the TLP, and the startup activity from an integrated-deck philosophy with production operations from a platform with moving trees, flexible flowlines, and production riser tensioners.

This paper presents experimental techniques and resultant data from an ongoing programmed of large scale laboratory tests on marine risers in waves. The experiments are being carried out in the No. 3 tank of the National Maritime Institute in England which has a water depth of 25 ft (7.6 m). The range of models used represent full size risers of between 500-2000 ft (150-600 m) supported by semi submersible or tension leg platforms. The measurements made include the wave elevation, surface platform motions, riser top and bottom end tensions and a large number of displacements and bending stresses along the riser length in long crested regular and irregular waves. Both in line (to the waves) and transverse riser displacements and bending stresses are presented. Measured data for a scaled riser from (500 ft) 152 m water depth are presented and compared with two dimensional riser dynamics computations based on finite element techniques and on modal analysis. The measured data reveal a significant level of transverse riser dynamic displacements and bending stresses. These are shown to be consistent with the effects that would be produced by fluid loading due to vortex shedding along the riser length. Introduction The almost total absence of reliable prototype or experimental data on riser motions and stresses in waves is generally acknowledged to be a serious drawback for the credibility of the large number of marine riser computation methods that are currently available. There is a large body of small scale test data for the fluid loading on riser cross-sections (circular or otherwise) in planar oscillatory flow and small wave tanks. (References 1, 2, 3 for example). Such data can be criticized from the point of view of not simulating the full scale Reynolds number correctly or that the experiment does not adequately model the riser section in motion within fluid which is itself in motion due to wave action. In general, small scale tests make it difficult to simulate a long riser adequately with the correct "boundary conditions" at the surface vessel, sea bed and along the riser length. At the other extreme, there are some current proposals to acquire full scale data (4, 5) on risers operating in the ocean environment. Although, the acquisition of full scale data has the potential to provide the ultimate validation tool for riser analysis methods, there are a number of uncertainties regarding the manner in which the full scale raw data can be converted into a form suitable for comparison with riser analysis. The uncertainties are associated with the difficulties of acquiring sufficient current and wave data in a multi-directional sea to adequately describe the incident wave process. Even if sufficient data have been obtained for this to be done, the lack of reliable mathematical models to describe the consequent fluid loading on the riser and to interpret its motions makes it difficult to use the data in verifying or improving the techniques of marine riser analysis. England (6) gives some indication of these difficulties for full scale data.

Our customer elected to post-install suppression fairings for vortex-induced vibration (VIV) on the suspended gas export pipeline in Green Canyon Block 113 due to recent data acquired on the depth and magnitude of loop/eddy and cold core current profiles in the Gulf of Mexico. VIV suppression fairings minimize pipeline excitation during high current events, thereby preventing accelerated fatigue failure of pipeline components and minimizing current-related disruption on producing operations. VIV suppression hardware installed on the span was designed and fabricated by Shell Global Solutions (US) Inc. (Shell GSUS) and was in the form of short (6-foot) fairing sections. For hardware installation, our customer teamed with Shell GSUS to develop a method and associated tooling to allow the fairing assemblies to be installed. The method of installation included a deepwater construction vessel using a work-class ROV and heave compensation techniques. This method and equipment can be utilized without affecting flow line operations. This paper reviews the planning, procedures and results of a deepwater, horizontal pipeline span VIV suppression installation project. This paper will be presented by the author at Offshore Technology Conference 2004 in Houston, Texas. Case for Action Span Description. During an as-built pipeline survey of a deepwater offshore gas pipeline, a span of over 300 feet was discovered. The span is in the Green Canyon area of the Gulf of Mexico (Figure 1). The depth of the span at location is approximately -2300 fsw. The span length is over 300 feet long and at times over 10 feet above the sea floor. The Gulf of Mexico has recently verified currents that can potentially harm suspended pipelines in deepwater. Fig. 1 - Approximate Span Geographic Location(Available in full paper) To limit vortex-induced vibration (VIV) during deepwater current events, suppression hardware is required. Shell GSUS was tasked with installing the VIV suppression devices. Fairings were the specified device due to their low drag properties and low cost. VIV suppression fairings have in the past been installed on vertical pipeline steel catenary risers (SCR) and top tensioned risers (TTR) by Shell GSUS. This was our first attempt at a horizontal span retrofit. Installation Method Development VIV Suppression Device Decision. Previously Shell GSUS developed and patented VIV suppression fairings. Fairings were found to be superior to commonly used helical strakes due to their light-weight, low-cost and low-drag properties. VIV suppression fairings developed by Shell GSUS (Figure 2) weathervane to keep the vortex-interrupting fin on the downcurrent side of the tubular that they are attached to. Unlike helical strakes, VIV suppression fairings do not increase the diameter of a pipeline substantially. Most deepwater facilities utilize VIV suppression in some fashion. Shell Exploration and Production Company (SEPCo) chose VIV suppression fairings for their tension leg platform (TLP) production risers in the high-current Mississippi Canyon region of the Gulf of Mexico. The Ursa TLP production risers were installed with VIV suppression fairings attached. Mars TLP production risers were also installed with VIV suppression fairings as well as strakes in the splash zone, and additional VIV suppression devices have been installed since arriving on location, due to a deeper understanding of the current profile.

Two recent conversions of semisubmersible drilling units to floating production facilities were governed by a different set of design requirements and operator philosophies. This paper compares them and illustrates how fabrication philosophies were chosen to produce a cost-effective project for each. INTRODUCTION The current state of the offshore oil and gas production market includes a niche for a cost-effective means of developing and producing marginal deep-water fields. The range of water depths for these fields begins at the limit of commercial feasibility for flied platforms and extends to depths where station-keeping criteria makes relatively recent technological concepts, such as tension leg platforms, necessary. Additionally, many fields are being developed at the edge of mature shallow-water areas including the Gulf of Mexico. These areas have the existing export pipeline networks and infrastructure such that storage of production crude is not necessary. Conversion of existing emisubmersible drilling units to Floating Production Facilities (FPFs) has proven to be a viable means of filling this niche. The semisubmersible hull as employed by the offshore exploration industry has evolved over 30 years and is a proven concept for providing a stable work platform with minimum motions. FPF technology has been in use since he Argyll Field FPF was installed in the North Sea in the mid-1970's. Two recent examples of the conversion of semisubmersible Mobile Offshore Drilling Units (MODUS) to FPFs are the PETROBRAS XXIV, installed in the Albacora Field offshore Brazil in January 1993, and the ENSERCH GARDEN BANKS, currently undergoing conversion. Both semisubmersibles are second-generation designs. The PETROBRAS XXIV, formerly the PENROD 72, is owned and operated by Brasoil, part of the Brazilian national oil company, Petrobras. The ENSERCH GARDEN BANKS is owned by Enserch Exploration Partners, Ltd. (EPO or Enserch Exploration). The primary goal in a successfulFPF conversion is timely delivery of the unit to achieve the earliest possible production from the field. The strategy employed to accomplish the conversion of the unit is key to meeting this goal. There are several factors that must be considered when developing the conversion strategy. After a review of the modifications required to accomplish the conversion, these factors will be discussed as they relate to the two conversion projects presented herein. Although the story of the PENROD 72 conversion to an FPF is well known throughout the industry, in order to fully understand the capabilities of the PETROBRAS XXIV, the history of the PENROD 72 as an FPF must be reviewed. In 1985, operator Placid Oil Co. and rig owner Penrod Drilling teamed up to initiate the conversion of the PENROD 72 for the Green Canyon Block 29 field, located in 1,540 feet of water in the Gulf of Mexico. This was the first semisubmersible-based floating production system in the Gulf of Mexico, as well as the world's first deep-water FPF. The field development scenario included production from up to 24 high pressure wells from a subsea template. Well fluids were processed through a two-phase separator, and the gas dehydrated to pipeline quality. The dry gas and combined liquids were exported through, respectively, 12" and 8" diameter risers to a template on the sea floor.

During installation of polyester mooring lines for the Red Hawk cell spar in the Gulf of Mexico, one segment accidentally contacted the sea bed. Kerr-McGee Oil & Gas Corporation (Kerr-McGee) is the operator and Devon Energy Corporation (Devon) is a 50% partner in the facility. The operator and the regulatory agencies raised concerns regarding the effect of possible soil ingress on the durability and performance of the polyester rope. A two-phase test plan was established and conducted to demonstrate that Whitehill VETS 379 polyester rope retained 100% of the new rope break strength, modulus, and fatigue life after contact with the sea bed. Microscopic imaging and chemical analysis indicated that individual braided strand jackets on each sub-rope limited the particle size in contact with the strength member fiber. This actual case history clearly demonstrates that the strand jacket provided sufficient protection from the adverse effects caused by sea bed contact. The results of the two-phase test plan are intended to provide technical justification for relaxing current philosophies requiring line replacement when touchdown occurs. Introduction The Red Hawk Cell Spar is the first application of a cell spar as a host for oil production operations. The cell spar installed in Garden Banks 876/877 in the Gulf of Mexico. The Spar is located in approximately 5,300 ft of water with a chain-polyester-chain mooring system. More details of the overall project and mooring design criteria are detailed in Ref. /1/ and Ref. /2/. Soil ingress is an important factor in the use of polyester mooring lines. It has been observed that small particles allowed to imbed into the inner load bearing fibers of some synthetic ropes can reduce the mean break load (MBL) and fatigue life over time. This issue has prompted regulatory agencies in the Gulf of Mexico to require that polyester mooring lines never contact the sea bed. To prevent such an occurrence, mooring designers and installation contractors take this requirement into account when developing and installing the mooring system. To limit particle ingress, the polyester rope manufacturers developed a rope that consists of an outer jacket on the overall rope and individual jackets on each strand of each sub-rope. This impedes foreign particles from contacting the load bearing fibers. As part of the installation phase, the installation contractor utilized a two boat operation to maintain a clear distance above the sea bed, Ref. /3/. Despite all attempts to keep the polyester clear of the sea bed, during hook-up operations, one of the spar mooring lines briefly contacted the sea bed. ROV surveys of the mooring line did reveal faint traces of soil on the exterior jacket of the rope. Rather than immediately replace the section of polyester that had touched the sea bed, a proposal to perform a series of tests on soiled rope removed from service was accepted by the regulatory agencies. The purpose of these tests would be to prove that soil particles did not penetrate the double jacket polyester construction and full break strength and fatigue could be achieved for the twenty-year design life.

: Contents: Chemical oceanography and marine geochemistry: Kinetics and Physical Chemistry of Sea Water Surface Films; Primary Production and Distribution of Trace Elements; Carbonate Chemistry on Bahama Banks; Geochemistry of Sediments; Sedimentation and Stratigraphy: Paleotemperature; Foraminifera Studies; Coccolith Studies; Sedimentation; Morphology of the Sea Floor: Topography of the Straits of Florida; Ripple Marks in the Straits; Physical Oceanography: Investigations in the Florida Straits; General Circulation in the Ocean; Data Reduction; Oceanographic Instrumentation: A Doppler Current Meter; Instruments and Devices; Marine Operations.

This chapter reviews planning methods and practices. Significant work has been published and used for long periods on planning methods. Preplanning is essential due to the life safety factors that a crowd can develop in situ. Planning can be considered in two phases. Information and background planning essential to communicate facts and identify risk areas in crowd management and operational planning. This then provides resourcing and contingency planning once the operation is in place. Like military operations both phases are important, however in many crowd situations operational and contingency planning is given less scrutiny. This is because the plans are normally scrutinised by authorities, councils, government, venue or land owners and they are more comfortable with pre-information type plans that inform them of the context background and communication flows. How the crowds are managed by security contractors is not usually an area they are experienced in, hence less attention is paid to these areas. The aim of this chapter is to provide enough knowledge for all event stakeholders to review and discuss practical implementation issues in security deployment and control. Planning and preparation requires an increased focus for crowd management because the emerging behaviour from the collective requires more options to be considered and prepared for. As crowds can cause life safety issues and because agents and systems can interact to exaggerate interactions and responses quickly, preparation and contingency planning is vital. Crowd risk assessments have to be conducted to understand and communicate the magnitude of the problems that can occur. If the consequences of the crowd activity are significant to the risk appetite of the organiser then response methods and measures should be developed and implemented. An example of this would be preparing additional signage, barriers and guards to divert pedestrians away or around potential bottlenecks when the flow becomes too congested.