Releasable Mooring Systems ("RMS") have been in use for over 35 years in the offshore industry, with an original purpose of rapidly releasing lines to avoid weather events, such as ice floes, hurricanes, or cyclones. With the recent introduction to industry of fully redundant release tools with higher release load capabilities, the RMS concept is now being used in well planning efficiencies. The objective of the paper is to show the effectiveness of the latest enabling tool and RMS concept in reducing the time to unmoor, removing the requirement for an Anchor Handling Tow Supply (AHTS) vessel, and assisting Dynamically Positioned (DP)/Moored semisubmersibles in lowering their carbon footprint, operational costs and HSE exposure.

Drilling a nine km (Kilometers) extreme ERD (Extended Reach Drilling) well by a rig which was initially designed for six km and on a platform that did not provide any empty well slot posed a challenge to the Brage asset team. The well (A-36 A/B) was planned with an ambitious slot recovery operation removing all casing strings to surface to allow for a 24-inch sidetrack. Due to unexpected challenges during the slot recovery only a 19-m window between the 28-in conductor shoe (at 315-m MD) and the old 13 3/8-in casing stump was available. A very successful kick-off using a mud motor and Gyro-While-Drilling bottomhole assembly (BHA) was performed. An RSS (Rotary Steerable System) BHA was used to drill the rest of the section Both "push the bit" and "point the bit" RSS technologies were the key enablers in drilling long sections and helping to deploy casing strings. The well was successfully geosteered through two reservoirs, including a new reservoir landing strategy, adding valuable extra reservoir meters. The reservoir Mapping-While-Drilling and Magnetic Resonance-While-Drilling service helped to navigate in challenging reservoirs maximizing reservoir exposure. Advanced polyglycol Water-Based Mud system was utilized in 24-in section followed by advanced Oil-Based Mud (OBM), and Low Solids OBM systems enabled drilling this extreme ERD well. An upgraded Cuttings collection and transportation system meeting ERD requirements and offshore slop water treatment system also played key role in drilling optimization. Real-time monitoring of critical well construction operations was performed using specialized technologies. Optimized Viscous Reactive Pill (VRP) was successfully used for the first time in North Sea to provide cement plug base at deeper depths (7200-m MD) resulting in a successful kick-off using "point the bit" RSS systems. An ERD specialist subsidiary of the service company was involved in ERD design verification and training of offshore personnel. Outstanding equipment reliability of surface equipment and downhole tools enabled shoe-to shoe drilling of these sections. The OneTeam culture combined with the main service provider integrated solutions, and an open-minded and brave approach led to drilling longest well in this brownfield ever. It was completed 32-days ahead of plan with all objectives met. The deep lower screen completion was successfully deployed, and the well is producing as expected. This 9,023-m MD well is the longest Offshore well drilled by the Operator and 2nd longest drilled by the Operator ever.

North Sea lithologies are often complex creating a difficult environment to deliver effective zonal isolation with standard cementing practices. With ever-present weak, fractured, and unconsolidated formations, the practice of fully lifting heavier cement up the annular gap between the formation and the casing or liner often times compromises the formation and the cement integrity. Wellbore Stabilizing (WBS) technology has been shown capable of providing zonal isolation under these difficult conditions. A cementing spacer has been developed that incorporates WBS technology providing a simple way to deliver the technology in front of any cement job, without compromising the cement integrity or requiring any last-minute slurry design or redesign. By separating the placement of the WBS technology from the cement itself, the cement slurry can be designed with the sole focus being on the interval's zonal isolation requirements. On Askepott wells in the Norwegian part of the North Sea, the Nordland weak zone is encountered after drilling out the 30-inch shoe from the Oseberg Vest H template. Cement back to the seafloor is required when cementing the 20-in casing in these 26-in. holes. Prior to the introduction of the WBS technology, pressure had been observed on the D-annulus, hinting at a lack of sufficient cement circulation. With assistance from this new WBS spacer, pressure is no longer observed in the D-annulus indicating the cement is now being circulated back inside of the conductor string. The WBS spacer has also been used successfully ahead of cement across the production interval in wells where losses were typically expected, and again full returns were observed. Normally cement spacers are utilized to separate the drilling fluid from the cement as these two fluids are normally incompatible with each other and to help push the drilling fluid out of the well so the annulus may be completely filled with cement. If the drilling fluid is not successfully displaced from the annular space, the zonal isolation intended by the primary cement job is usually less than ideal. In addition to these standard functions in preparation for cementing operations, this specialized WBS spacer also can prevent loss of cement to the formation.

With the increase in decommissioning/abandonment work in the North Sea, a major operator had the objective to permanently abandon a well that had been temporarily suspended. There were several key challenges associated with this project: high pore pressure and temperature, a completion packer set in a target abandonment interval, and small cement plug volumes. These obstacles had to be overcome to complete the abandonment safely and efficiently. The primary barrier to the deepest potential flow zone, zone 1, was established by running flush slimline tubing through the 5-in. tubing and 9 7/8-in. production packer. The cement plug was then successfully placed below, across, and above the production packer. The cement plug was successfully tagged and inflow tested, creating a primary barrier against zone 1. This approach eliminated the need to remove the production packer prior to the abandonment plug being set, which saved the operator approximately 10 days of rig time. This paper outlines the detailed design preparations and presents the case history where these steps were implemented successfully.

A digitized workflow from pre-drill pore pressure modelling with Monte-Carlo approach, till update of pressure prognosis while drilling from e.g. sonic and/or resistivity data is described. The innovative approach will reduce the uncertainty in the mud-weight window ahead of the bit. For the 3D pressure modelling, a basin modelling software method is used, where the pressure compartments in the study area are defined by faults interpreted from seismic. Key input parameters like minimum horizontal stress, vertical stress and frictional coefficients for failure criteria are varied. The output is pressure profiles along the planned well path, with uncertainties. The work presented in this paper was carried out on a North Sea dataset. The results show that the uncertainty in the pore pressures will highly influence the uncertainty span in both the fracture gradient and the collapse gradient. Representing the mud-window in terms of a most likely collapse and fracturing curve, with on each side of both, limits the minimum and maximum pore pressure derived limits, makes for a more realistic prediction, stating the uncertainty in the result. While drilling, log-data will be automatically used to update the pressure and mud-weight prognosis ahead of bit. The digital updated prognosis can help the drilling crew in the decision-making during drilling campaigns.

Control mud level (CML) technology is a method to manipulate the mud level in the riser in order to control bottom hole pressure (BHP) and Equivalent Circulating Density (ECD). It is also a Dual Gradient Drilling (DGD) technology, designed for drilling post-BOP sections. The system uses a subsea pump installed on a modified riser joint (MRJ) to control mud level in the riser's annular space. CML eliminates the effect of ECD and enables drilling with a close-to-constant BHP. This may impact well design by allowing more optimal placement of casing points. By eliminating circulating friction, flow rate can be increased in the horizontal section and in unstable formations, to clean the wellbore from cuttings. CML is a valuable tool while drilling into formations with a high probability of losses, or the layers with a high risk of influx. This paper will show that a CML system detected kicks earlier than the rig crew and geo-service company sensors both in GOM and the North Sea. In addition, how quickly was the kick detected and the driller informed will also be examined. With the CML system, the sensitivity for kick detection was greatly improved as the effect of rig motion on surface volumes was eliminated. It is also explained how the CML system can help drilling in weak zones, and also drill deeper by adjusting the mud level in the riser by using a subsea pump module (SPM) which is connected to the riser to control BHP. The system is not a part of the well control equipment and the mud is still the primary well barrier. Successful managed pressure cementing (MPC) method is also covered in this paper. The system was used to manage downhole pressure for cementing operations to mitigate losses and ensure good cement integrity. With MPC offering precise control over the pressure, it is possible to keep the wellbore pressure profile inside the drilling pressure window during the cementing operation.

On an offshore jackup rig in the North Sea, an operator required specific drilling needs during tripping and the safe and efficient deployment of the completion string without killing the well. A solution other than a snubbing unit was required because of the length of the completion string, which included 12 swellable packers for 13 individual zones. The swellable packers were staged to prevent the heel and toe effect and to create a homogeneous production profile. Snubbing the pipe in and out of the hole presents serious Health, Safety and Environmental issues that typically lead to considerable non-productive time (NPT) due the inherent slow speed of operation associated. In addition, snubbing requires added personnel. To address these concerns and provide for a safer, less expensive and efficient method of tripping pipe, the operator chose to employ a Downhole Isolation Valve (DIV) solution that allowed for the process to be performed in a conventional manner under conditions of complete well control. As an alternative to a snubbing unit, the DIV system was used to isolate the slightly underbalanced well. The service team installed a tandem 7-in., 32-lb, 5K DIV system ( Fig. 1 ) on a temporary retrievable tieback casing string with premium left-hand thread connections. Specifically, a tandem DIV system was chosen as an added security measure, in the case that unforeseen circumstances required an additional unit. Figure 1 Upper and lower DIV system configuration. In this paper the author will examine and provide details of the DIV system and its' evolution. He will go on to describe how the North Sea's first ever successful deployment of a tandem downhole deployment valve (DIV) system created a reliable barrier that isolated the well formation pressure below the valve, thereby saving rig time, enhancing safety, and cutting drilling costs.

Liner hangers are designed to provide seal and anchoring capability for installation of casing. The expandable liner hanger has a uniform body with no moving parts that will expand into the parent casing and provide a permanent and reliable seal. Unfortunately, drilling a well can be problematic in certain situations, resulting in loss of a section or the entire wellbore. This leads to additional well construction costs from milling casing, running a sidetrack, or drilling a new section. Retrieving sections of the installed casing can reduce the cost but may require removal of the liner hanger. While milling conventional hanger systems has been performed before, there has been little experience with milling an expandable liner hanger. This paper discusses the first two cases in the North Sea where expandable liner hangers required milling because of drilling issues below the liners. The milling of the expandable hanger bodies provided several benefits when compared to the milling of conventional liner hanger systems. The benefits included reduced rig time and non-productive time (NPT), less well debris than when milling movable parts/slips, and no parent-casing slip damage. In the first case, during running of an expandable liner hanger, the hanger disconnected and was lost. A backup hanger was run, cemented, and set. Options for correcting the situation will be discussed in this paper along with why milling was considered the most feasible option. In the actual job, 10.5 feet of hanger were milled out in less time than anticipated. In the second case, a liner and expandable hanger were set in a long, extended mature reservoir. During drilling of the next section, the drill string became stuck, requiring a sidetrack. Milling of the expandable liner hanger system enabled the operator to pull the liner and perform the needed sidetrack.

Optimizing well control processes are critical in high-temperature/high-pressure (HPHT) drilling operations so they do not encounter high cost overruns and compromise safety. The key to success is recognizing and mitigating challenges and associated risks early to adequately optimize drilling operations. This leads to a more effective drilling operation with reduced risk, increased safety margins and increased probability of successfully achieving the well’s objectives. This case describes an integrated work process that has been implemented, incorporating pre-drill and real-time pore pressure prediction with proactive equivalent circulating density (ECD) management during well planning and drilling operations. This work process is especially important for optimizing drilling fluid properties to retain the drilling parameters within a safe operating mud window identified by real-time pore pressure and wellbore stability prediction. Operating in this safe window enables reduction in wellbore instability, formation damage, hole cleaning inefficiencies and poor drilling performance, resulting in improved safety margins, reduced risk, improved drilling performance and reduction in non-productive-time (NPT). Several recent examples from Suncor Energy Norge HPHT wells are presented to illustrate the success of utilizing this integrated approach, resulting in drilling HPHT wells with no formation pressure-related NPT. The process begins with identifying pressure-related challenges in the pre-drill planning phase, optimizing the drilling process by validating, defining and maintain the drilling parameters within the safe operational window through an integration of proactive real-time pore pressure prediction and ECD management using all available LWD measurements: acoustic, gamma, resistivity, density, formation pressure while drilling, imaging, ECD, and temperature. Analysis is performed on mud logging data such as gas, the drilling exponent, cuttings and borehole caving and surface drilling data. Finally, lessons learned are captured that will further improve drilling efficiency and best practices in upcoming drilling campaigns.

When Portland cement is exposed to high temperature environments it experiences "strength retrogression", which is characterized by the breakdown of the set cement matrix. This results in loss of zonal isolation and/or pipe support, impacting the operational life span of the wellbore and its eventual abandonment. To prevent this, it is standard industry practice to incorporate extra silica into the cement slurry. Silica flour or sand is usually dry-blended with the bulk cement at concentrations of 35-40% bwoc. However, this methodology carries health risks, complicates operations (especially off-shore) and introduces costs that could be avoided. With the North Sea being a mature drilling arena, it requires ever more complicated well bores to access remaining deposits and therefore operators are continually looking for more cost-effective methods of achieving this. Coupled with the desire to reduce the impact on the environment of our work, a new method for introducing silica to cement slurries was introduced. Since its arrival to the market in 2003, the use of a liquid strength retrogression prevention additive has steadily been gaining acceptance throughout the industry. This paper reviews the benefits of such a system, especially during exploration work and short rig hire contracts, and some of the issues encountered in bringing these gains to customers. Overcoming handling and shelf-life problems will lead to reduced costs and allow more operators to take advantage of this solution.

Abstract One of the biggest breakthroughs in drilling technology was the top drive first commercialised in the 1970's. The advent of the top drive brought vast time savings: through drillers being able to drill with 90ft. stands; elimination of connections and their impact on circulation and the wellbore; being able to rotate and circulate when tripping out giving the ability to get through tight spots, and much more. Since then, apart from changing from DC motors to AC motors the basic functional design has remained the same, that is, one or two large motors connected to a gearbox, driving a main shaft. A new type of top drive has now been developed with possibilities for significant drilling cost savings due to the improvements in reliability and easier maintenance. A major drilling contractor who had significant experience using top drives on their rig fleet conducted an analysis of where most of their rig downtime occurred. They found that 40% of all their top drive failures were related to gearbox issues (gears, bearings and seals). Another significant failure was with the motors, particularly on their smaller top drives in their land rig fleet. These types of failures had been expensive for the drilling contractor and the operator with significant frustration, lost drilling time and lost revenue. The problems were exacerbated by top drive manufacturers not having spare parts stocked and service technicians not being readily available. This lead to the drilling contractor taking the decision to help develop a revolutionary, new, direct drive top drive, with less parts, no gearbox and improved motor. These systems have now been field trialed extensively, for a number of years onshore and offshore with significant success by this drilling contractor and others in the USA, Middle East, Russia, North Africa and Australia. The drilling contractor is now half way through a program to replace all the top drives on it's complete fleet of existing and new build rigs (31 land rigs and 31 jack ups) and the first DNV certified 750 ton version has just recently been retrofitted on the Rowan Gorilla V jack up in the North Sea. The rig went on location and the top drive performed satisfactoriy with no downtime on the first well for Total and at the time this paper was being written the well was drilled to 11,368 ft. Introduction Since the early 80's the top drive has replaced older methods of drilling which used a kelly (a square or hexagonal steel member suspended from the swivel through the rotary table to enable turning of the drillstring). On a conventional top drive one or two large motors are coupled to a gearbox and turn a hollow main shaft (sometimes referred to as a drive stem). The main shaft connects via a series of in-line blow out preventer valves and a pipe-sub to the drillpipe. In drilling mode, mud is pumped through the shaft down the drillstring while the motor or motors turn the drive shaft via a gearbox. The top drive is also used while tripping, to make and break "stands" (typically 3 x 30 ft. lengths of joined drillpipe). One of the biggest benefits of using a top drive is this ability to drill with stands eliminating, typically two thirds of all connections. This saves time and reduces the chance of downhole problems. Other benefits of drilling with a top drive include: The possibility to back ream allowing full rotation and circulation while tripping and reduced stuck pipe incidents (according to R.C. Willis and D.N. Willis in their 1986 SPE paper 15465 entitled Successful High Angle Drilling in the Statfjord Field since top drive installation, which occurred due to poor hole conditions had dropped by 50%) Improved well control since stabbing is instant and the well can be shut-in at any position in the derrick Increased safety due to one back-up tong being required and fewer pipe connections

Abstract Abnormal surface torque and hook load values are symptoms of downhole drilling condition deterioration which can result in unexpected situations. Usually, friction tests are performed at regular intervals and rig personnel uses these measurements to monitor trend variations in order to detect possible risk of poor hole cleaning or increased borehole tortuousity. The quality of the detection can vary greatly in function of the work load and experience of the drilling staff. The availability of real-time measurements through data servers make it possible to automate and systemize the monitoring process and therefore trigger alarms before drilling problems really occurs. This paper presents a computer system used to systematically analyse real-time data in order to monitor downhole conditions. Such a system can utilize much more data than just the above mentioned friction tests, because mechanical, hydraulic and temperature models can calculate predicted hook load and surface torque in any drilling conditions. The numerical models are automatically calibrated (adjustment of drill-pipe linear weight, factors for mechanical and hydraulic friction and heat generation). The evolution of proper calibration factors is used to detect poor downhole conditions. Automatically generated messages are sent to key personnel who can evaluate the potential problems and take necessary actions. To validate this new methodology, the system has been run on recorded data from three wells on an oil field in the North Sea. A data filtering technique has been developed and applied to solve problems with noisy and erratic real-time signals. With correct input parameters, the system has clearly indicated unexpected measurements several hours before a pack-off problem occurred and therefore proven that the methodology could help in detecting the worsening of downhole drilling conditions. Availability of large amount of real-time data at the rig site or in onshore drilling centres does not necessarily facilitate the recognition of drilling problems. However, online interpretation systems, as the one described above, can systematically analyze the logged data to detect as early as possible the deterioration of hole conditions during drilling operations and corrective actions can be taken before any major problem has really occurred. Introduction Deterioration of downhole conditions during drilling operations can be detected using the hook load and surface torque measurements. Typically, poor hole cleaning, wellbore tortuousity (due to micro-doglegs or larger directional deviation from the planned well path), wellbore instability, formation extrusion, under-gauge hole or junk in hole will have impact on the measured surface torque and hook load. On one hand, poor hole cleaning can result in stuck pipe or indirectly to formation fracturing (due to the increase of downhole pressure in the annulus). On the other hand, increased torque/drag values can hinder reaching the final depth of the well, cause drill-string failure, or prevent from running in the casing/liner string or the tubing string. Therefore it is desirable to monitor those parameters to get an early warning of possible hole condition deterioration.

Abstract The Central North Sea (CNS) Cretaceous formations are notoriously difficult for performing directional drilling operations. Oriented drilling using bent housing steerable motors is troublesome and rate of penetration is unacceptably slow with rotary steerable systems. This has historically resulted in well trajectories being planned with minimal directional course changes through these sequences and, when directional course changes are absolutely required, oil based mud is often required to facilitate oriented drilling. With many assets in the Central North Sea reaching maturity, directional drilling course changes in the Cretaceous has increasingly become a necessity to access remaining targets. Talisman Energy (UK) Limited acquired several CNS mature assets in the period 1997 - 2005. A challenge faced by the operator was to improve directional drilling control and overall drilling performance through the CNS Cretaceous while simultaneously moving away from oil based mud requirements. A new generation rotary steerable system which integrates a performance drilling motor with a high speed rotary steerable tool was introduced to meet this challenge. By applying this new system coupled with the latest steerable drill bit technology, precise three dimensional trajectories are now being drilled at more than double the offset rates of penetration & water based mud can now be used more frequently. The results have been easier access to remaining reserves, a dramatic reduction in drilling time, lower environmental impact and overall reduced cost and risk. This paper describes the drilling conditions in the CNS and the new drilling technology applied. It also describes the challenges encountered applying new technology on cost sensitive mature assets, procedures put in place to minimise operational risk while introducing the new system and a comparison of performance now compared with that of offset wells. Introduction The UK Central North Sea (CNS) covers an area from block 14 in the North through block 31 in the South (Figure 1) and is an important area for North Sea hydrocarbon production. A number of fields discovered here in the 1970's, were quickly developed and commenced production in the late 1970's or early 1980's. Many are still producing but are past peak production. A challenges faced by the operators is to maintain economic recovery from these maturing assets. The primary source of production is from Jurassic sands with some fields producing from the Lower Cretaceous itself. To reach these producing zones, it is necessary to drill through the Cretaceous sequence of formations. The CNS Cretaceous formations are dominated by chalk and marl groups as illustrated in Figure 2. Since development drilling first commenced in the CNS back in the early 1970's, the CNS Cretaceous has been recognized as a significant drilling challenge, limiting both drilling performance and development drilling options. New wells normally drill the Cretaceous in 12 ¼″ hole size while re-entry wells frequently drill it in 8 ½″ size. Typical challenges encountered are: Unpredictable, widely varying and normally low rate of penetration (ROP) Troublesome oriented drilling with steerable motors or turbines Hole spiraling and ledging High friction factors High levels of drilling vibration Unpredictable but strong natural directional tendency.

Abstract The well 34/8-A-6 AHT2 was drilled from the Visund Field Floating Production and Drilling Unit (FPDU) in the North Sea, and set on production in October 2005. The well was drilled to 9082 m/29796 ft measured depth and has an Along Hole Depth (AHD) reach of 7593 m/24911 ft, which is a world record for Extended Reach Drilling (ERD) from a floating installation. The 34/8-A-6 AHT2 is also the longest Down hole Instrumentation and Control System (DIACS) installation worldwide, with the lower isolation packer set at 8560 m / 28084 ft measured depth. The well includes three hydraulically operated flow valves, which are used as down hole chokes to optimize the production from the separate zones in the reservoir. Subsea developments in combination with ERD wells can increase oil production and lower total development cost. The drilling progress was 108 m/day from seabed to total depth, according to the Rushmore drilling performance definition, and the payback time for this well was less than two months. Experiences gained on this well indicate that even longer wells can be drilled from subsea locations in the near future. Introduction The Visund field is located in block 34/8 in the North Sea 150 km west of Norway (Figure 1, 2, 3). The field was discovered in 1986 and production started in 1999. The Visund field is an oil & gas field, with a water depth of 335 m (1100 ft). The depth of the main reservoir is between 2900–3000 mTVD, with a maximum pore pressure of 434 bar. The field is 24 Km long and 4 Km wide. With this shape of the field, ERD wells drilled both to the North and to the South will increase drainage area and thereby the total recovery from the field. The Visund Floating Production and Drilling Unit (FPDU) is located centrally on the field. The Visund North satellites consist of two wells tied back to the FPDU with a 9 km long subsea pipeline. The well in this case history is a world record ERD well drilled from a floating installation. In the early pre-planning phase, the well was planned as a separate costly subsea development, drilled by a separate semi-submersible rig. A new technical and economical study showed that this well could be drilled more economically from the existing Visund FPDU, using existing subsea systems. The total depth of the well 34/8-A-6 AHT2 is 9082 m. The horizontal reach (slot to TD) is 7484 m and the along hole depth (AHD) reach is 7593 m, - a world record reach from a floating installation. (Figure 4, 5, 6) Low friction factors in relation to torque were experienced by the use of an optimum well profile. Good hole cleaning was obtained with the use of 180 RPM on the drillstring together with maximum allowable flow rate. The ERD well has a Down hole Instrumentation and Control System (DIACS) completion with tree separate zones, operated by three hydraulically controlled flow valves. This is the longest DIACS completion in the world, with the lower isolation packer set at 8560 m. The well is produced at a rate of 2500 Sm 3 /day (15700 bbl/day) with production from all zones. Production from the upper zone A would not have been possible without a controlled production from the other zones, hence adding value to the DIACS completion design Experiences from this well show that even longer wells can be drilled from subsea locations in the near future. Optimal pre-planning with use of all service companies involved in detail planning and risk identification workshops are a critical factors for success. In the operational phase the work in the subsurface team was optimised through using 3D visualisation tools. These 3D tools facilitated in getting a common understanding in the whole team, which was used to optimize the reservoir pay zone drilling of the well. Subsea developments in combination with ERD wells can increase oil production and lower total development cost, in comparison to costly additional subsea systems that need to be installed prior to drilling a new well.

Abstract Conventional drilling and completion fluids containing weighting solids or hydrocarbons or halide brines can create problems with hydraulics, well control, well integrity and well productivity in HPHT operations. The negative influence of conventional fluids on drilling and completion operations can be sufficiently serious to compromise safety and degrade the economics of challenging HPHT field developments. Formate brines have been developed specifically to provide improved drilling and completion fluids that are free of the troublesome components found in conventional fluids and therefore better suited to meet the needs of oil companies involved in difficult HPHT well constructions. Formate brines have been successfully used as reservoir drill-in, completion, workover and suspension fluids in more than 130 HPHT well construction operations over the past 10 years. These applications have included 100 cases in which high down-hole pressures have necessitated the use of cesium formate brines for well control purposes. Some 15 applications of cesium formate brines to date have been HPHT reservoir drill-in operations in high angle wells where operators considered that conventional fluids could create a safety risk and adversely effect project economics. We review the published information on the field performance of the cesium formate brines in HPHT applications, and conclude that the novel benefits of the technology that were first promised some 15 years ago during the early product development phase have now been fully validated. Introduction The objective of the drilling and completion process is to safely deliver high quality wells that are optimized in terms of providing shareholder value: Best well productivity at lowest drawdown Best well integrity and longest structural lifetime Lowest well construction cost Lowest environmental impact and liability exposure Best reservoir information capture The choice of drilling and completion fluid used in a well construction operation has a critical influence on the extent to which an operator can meet this objective. In particular the fluid's performance will play a significant part in determining whether or not an operator meets its key performance indicator targets in the following areas: Time to drill and complete Well control and safety incidents Well integrity Well lifetime and maintenance costs Well productivity index Waste management costs Logging capability and interpretation Environmental footprint and impact Exposure to liability (short- and long-term) The drilling fluid chosen for the upper well sections must offer a host of functionalities: Ability to maintain the integrity of weak rocks Ability to minimize fluid loss into permeable rocks Ability to provide stable well control Ability to efficiently transfer hydraulic power Ability to move cuttings to the surface Provide steel/steel and steel/rock lubricity Provide protection against all forms of corrosion Allow formation evaluation Pose little or no hazard to rig personnel Have little or no adverse effect on the environment Have little or no adverse effect on elastomers If the drilling fluid is to be used in reservoir sections without further intervention it must cause minimal change to the native permeability of the reservoir rock in the near wellbore area. The drilling fluid filtrate must also be compatible with other filtrates that might leak-off from subsequent cementing and completion operations. A completion fluid should have the same overall properties as a reservoir drilling-in fluid and, ideally, should be the same fluid minus any drilled solids.

Abstract In Shell Exploration & Production, swelling elastomers have been deployed in a variety of applications: as a means to establish zonal isolation in liner completions, as a production separation packer, and as an integral part of an expandable open hole clad. In these applications, the elastomers have been run in various open hole, casing, and tubing sizes. A total of around 60 deployments in Shell have been recorded, all of which were technically successful. Case examples of each of the three mentioned applications will be presented from Shell operations in the North Sea, the Middle East, and the Far East. Introduction In most areas where Shell operates, especially in the more mature oil field environments, there is a high focus on well cost reduction. Various technology applications have been identified to meet this business need and allow the operator to drill wells cheaper and smarter, making the most of existing infrastructure. One technology that is experiencing a rapid uptake is the application of swelling elastomer packers. These packers, which swell naturally when exposed to the appropriate swelling agent, have successfully been used as a replacement for traditional mechanical packers and cement. The business case for using swelling elastomer packers is different per application and can include time savings as well as direct tool cost savings. Shell implemented swelling elastomers in combination with the deployment of a Solid Expandable Tubular (SET) system called Open Hole Clad (OHC) in July 2002. First application of swelling packers for zonal isolation was in the South Furious field in Malaysia in June 2003. Since then, over 60 deployments have taken place in operations in Malaysia, Brunei, Nigeria, Gabon, Oman and the UK. Theory and Definitions A swelling elastomer packer, or swelling packer, is a rubber element vulcanised onto pipe. The main property of the rubber is that it swells significantly when exposed to either aromatic hydrocarbons or saline water through a process of absorption. An oil swellable packer is a swelling elastomer packer, which swells primarily through the absorption of hydrocarbons. This is a diffusion process. Typical operating temperatures for oil swellables are 80–130°C. A water swellable packer is a swelling elastomer packer, which swells through the absorption of (saline) water. This is an osmosis process. Typical operating temperatures for water swellables are 50–90°C. The three main design parameters of swelling packers are life-span, pressure rating, and swelling time. Because of the relatively recent development of swelling packers, our understanding of these parameters is still growing and a full theoretical treatment of the subject is beyond the scope of this paper. The main factors to consider in determining the three design parameters are temperature and the geometry of the pipe, packer and borehole. Pressure ratings have been tested up to 3500 psi, although higher ratings have been recorded in the industry. Swelling times in our operations range widely from 5 to 50 days. The case examples provided in this paper show three distinctly different uses of the swelling elastomer packer: the liner completion, the production isolation packer, and the expandable open hole clad. A liner completion is defined as a liner system with slots or perforations to allow access to the producing formation. The swelling packers are used in combination with blank liner joints to isolate oil bearing zones from water zones, where conventionally a cement column would be used. The production isolation packer is defined as a seal between a production tubing and a production liner in order to isolate the various perforated sections. Swelling packers are used to replace conventional hydraulically or mechanically set packers. An expandable open hole clad is defined as an expandable tubular used to seal off water bearing formations or water producing fractures in a barefoot well section. Swelling elastomers are used to provide the seal between formation and tubular.

Abstract Many companies operate on a global basis. Often a new idea or technology can make a step-change in the economics, or performance, in a particular province or field. That leaves the company with the enviable problem of understanding how and where it could impact its operations in other areas of the world. One area where bp has had such success is in the North Slope of Alaska, where TTD has made a dramatic impact on their infill-drilling programme. In fact, Alaska had developed two distinct TTD techniques, Coiled Tubing Drilling (CTD) and Through Tubing Rotary Drilling (TTRD). This paper discusses how we transferred the technology to the North Sea. The subject is tackled on three levels: Transfer of practical knowledge The tactical choice on the optimum technique Determination of the strategic value of the technology It illustrates what needs to be done to ensure a successful business outcome when trying to gain the benefits of a new technology, but in a different operating environment. To illustrate the issues, the paper will present performance information on both TTD techniques used in Alaska. It will talk about their differences, and why the application of CTD, in particular, has made such a significant impact. It will then discuss how the North Sea operating environment differs from the North Slope, how this influenced the choice of technology and the potential magnitude of the benefit that could be realised. By the end of the analysis, it became clear that the solution and strategy for the North Sea had to be different from that of Alaska. It also makes it apparent why CTD has struggled to make an impact in the North Sea. Introduction In 1997, due in part to the success of the CTD programme in Prudhoe Bay, there was significant interest in exporting TTD technology to the North Sea. An initial feasibility study had shown that the largest potential was probably within the Forties field. Whilst a number of other fields were also interested, it was decided that the best way to transfer the technology was to target the first implementation on Forties. Forties Background The Forties field was one of the first discovered in the North Sea, and one of the largest. First oil was delivered in 1975, with the maximum oil production rate of over 500 mbd being achieved in the period 1978 - 80. The development consists of four main field production platforms and one ESP satellite platform. The oil in place is estimated to be over 4,000 mmb, with reserves of approximately 2,500 mmb (60% recovery). To date over 90% of these reserves have been produced. In the late eighties, artificial lift facilities (gas lift) were installed on the four main field platforms. A continuous infill programme has continued since then until a temporary break was declared earlier this year (2002). The Challenge In 1997 the size of the remaining targets were diminishing. If the infill programme was to continue, it required a step change in the costs associated with new reservoir penetrations. The company had already successfully implemented TTD techniques (both CTD and TTRD) within the Prudhoe Bay field in Alaska. A feasibility study was therefore instigated to see if this technology could have an impact on the drilling costs in the Forties Field. The results were encouraging, and suggested that there was a significant prize to be gained by implementing TTD in Forties. It also suggested that whilst we could implement TTRD in the shorter term, there might be a larger prize if CTD capability could be introduced into the region. The decision was taken to implement an initial programme of four TTRD wells. This was to be done whilst the conventional infill programme continued, so to ensure that the correct focus was maintained, an additional resource was allocated to the Forties Drilling team to manage the implementation of the TTRD technology. I was asked to fulfil that role, and my first task was to spend 4 months in Alaska with the following remit: Learn about the practical aspects of TTRD Evaluate, in more detail, the potential of CTD The trip was invaluable in both regards.

Abstract Drilling depleted reservoirs is fraught with a host of technical and economic problems that often make it unprofitable to further develop some mature fields. Most of the problems center around uncontrollable losses and differential sticking. Frequently, less expensive drilling fluids will be used in a particular interval, even though it may have the propensity to damage the formation. The reasoning holds that such fluids will offset the high costs of losing more expensive muds to the formation. If operators turn to underbalanced drilling as an alternative, the extra time and equipment required for a safe operation can seriously degrade project economics in some applications. A specialized invasion-control drilling fluid has been developed to drill reservoirs prone to lost circulation. This fluid combines certain surfactants and polymers to create a system of micro-bubbles or aphrons that are encapsulated in a uniquely viscosified system. Aphron based systems are engineered drilling fluids that aid in well construction by controlling losses in depleted, high-permeability sands while stabilizing pressured shales or other formations. One of the more attractive features of an aphron-based system is that it does not require any of the extra equipment used in air or foam drilling. There are no compressors, high-pressure hoses or connections to add costs and safety concerns. The system uses conventional fluid-mixing equipment to form tough, flexible micro-bubbles. This paper describes the development and application of the specialized micro-bubbles-based drilling fluid for controlling downhole mud loss in a depleted reservoir in the North Sea. The key issues of this project were excessive overbalance drilling conditions (> 5,000 psi) leading to the risk of highly expensive lost circulation and open perforations in the upper producer, requiring temporary sealing during drilling. The well was successfully drilled to TD without any drilling fluid losses. The authors will detail the laboratory methods used to generate appropriate formulations, the operational procedures, and field application. Introduction The drilling problems associated with the depleted reservoirs intrinsic to many of the mature fields throughout the world often make further development uneconomical. The water-wet sands that typify many of these zones propagate seepage losses and differential sticking, both of which are extremely expensive to correct. Uncontrollable drilling fluid losses frequently are unavoidable in the often large fractures characteristic of these formations. Furthermore, pressured shales are often found interbedded with depleted sands, thus requiring stabilization of multiple pressured sequences with a single drilling fluid. Drilling such zones safely and inexpensively is very difficult with conventional rig equipment. Such problems have led some operators to forgo continued development of these promising, yet problematic, reservoirs. 1 Excessive overbalance pressure generated when using conventional drilling fluids is thought to be the primary cause of lost circulation and differential sticking when drilling these wells. The equipment required to manage aerated muds or drill underbalanced is often prohibitively expensive, and meeting safety requirements can be an exhaustive effort. Furthermore, these techniques may fail to provide the hydrostatic pressure necessary to safely stabilize normally pressured formations above the reservoir. Recently, a new drilling fluid technology based on aphrons - uniquely structured micro-bubbles — was employed to successfully drill a depleted reservoir in the North Sea. The use of aphron-based drilling fluids has proven to be a successful and cost-effective alternative to drilling underbalanced. Description of Aphron Structure An aphron comprises two fundamental elements 2 : A core that is commonly, but not always, spherical. Typically, the core is liquid or gaseous. A thin, aqueous, protective shell with an outer hydrophobic covering. The aqueous shell contains surfactant molecules positioned so that they produce an effective barrier against coalescence with adjacent aphrons.

Abstract A North Sea coring record was set by Conoco UK Ltd (CUKL) and service provider Baker Hughes INTEQ (BHI) on 20 January 2001. A 179-ft core was cut and recovered in 6" hole from the Rotliegendes formation in the Southern North Sea. In-depth operational planning, which included offset core viewing by a multi-discipline well team was undertaken in an effort to identify potential coring hazards. Physical testing of offset cores, rock strength data, and other relevant data sets were used to model the length of core that could be safely cut. The coring operation was executed with the selected coring assembly and 179 ft of high quality core was recovered. Subsequent testing and analysis was performed on the core, which satisfied all evaluation requirements of the sub surface team. CUKL and BHI have successfully applied these planning techniques on a number of other wells resulting in significant improvements in coring efficiency, recovery and core quality. Introduction The North Sea coring record was set on the Venus 49/21 - 8A well. Block 49/21 is located at the south-eastern margin of the Sole Pit Inversion Axis some 115 km east of the Norfolk coast in the United Kingdom (Figure 1). The surface location was selected to avoid a sandbank, which is a potential site of special scientific interest, consequently the well was moderately deviated at 16° to the west.

Abstract This paper presents the cementing case histories of six wells in two offshore high-pressure, high-temperature (HPHT) fields in the Central Graben area of the North Sea. Well depths averaged 6000 m true vertical depth (TVD), temperatures were greater than 200°C, the fracture/pore-pressure margin was small, and the bottomhole pressure exceeded 1,100 bar. The well deviation varied from near vertical to a maximum of 35°. These down hole conditions are the most extreme yet experienced in a field development in the North Sea. Because of the extreme HPHT conditions, all aspects of cementing operations had to be carefully evaluated. In addition, new and enhanced equipment, processes, and materials had to be developed. Even though the potential for gas influx of the cement was high, the cement slurry formulation and placement techniques for resisting gas migration were successfully designed through the use of materials with a low environmental impact. Because the formations were weak and unconsolidated, a special cement blend was used at the top of the well. The mixing equipment was modified to withstand the high-density fluids required for the liner section. For job success, both a well-defined top-of-cement (TOC) and good casing support had to be obtained without exceeding the allowable equivalent circulating density (ECD) limit. Therefore, effective mud displacement, correct slurry placement, and precise rheology measurement were required. No remedial HPHT cementing operations were necessary during these operations, which was an important objective. Remedial operations could have posed extreme risks and high associated costs. This paper describes how the cementing process was optimized for HPHT field development, thereby minimizing risk and costs. Considerable emphasis is placed on the production liner cement job, because it was the most critical string on the well. Improvements to equipment, slurry testing, placement, and bond logging procedures are also described. Introduction Five wells were drilled in the Franklin field, and one appraisal well was drilled in the Glenelg field. These wells were drilled in the Central Graben area of the North Sea ( Fig. 1 , Page 10). A typical cross-section of a well is shown in Fig. 2 (Page 10). Fig. 3 (Page 11) is a schematic of a typical well in the sixwell package. Table 1 (Page 8) presents pertinent well data. The open hole coverage of these liners was long, ranging from 660 to 1027 m. Another feature of the wells, along with the high temperatures, is the rapid increase in formation pressure through the thin transition zone. The setting of the 9 7/8-in. casing is critical to achieving enough leakoff for the well to be drilled to total depth (TD) with a 2.15-SG drilling fluid. Even when the casing point is chosen correctly, the narrow window between formation pressure and fracture gradient is extremely tight for the drilling fluid to operate within during the drilling of the 8 1/2-in. section ( Fig. 4 , Page 11).