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Results
The project obteined core samples to verify rock quality prior to the commencement of tunnel drilling. The project required several new technologies and techniques to enable the collection of the core samples. The combined use of surface and subsea coiled tubing injectors operated from a vessel in combination had not been attempted and therefore was an area of concern, which was addressed during the operation design phase. Project planning included the theoretical analysis of the fatigue effects on the coiled tubing between the surface and the subsea injectors, requiring the development of a secondary injector control panel and several modifications to the vessel systems. The project resulted in a successful drilling and coring operation without incident or environmental spill following many months of planning, job design and use of a highly skilled team during the operation.
- Europe > Norway (0.29)
- North America > United States > Texas (0.28)
- Well Drilling > Drilling Operations > Coring, fishing (1.00)
- Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)
- Production and Well Operations > Well Intervention (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems (1.00)
Abstract This paper describes both the challenges and development of a novel solution involving 3.5-in. diameter coiled tubing (CT) for deepwater pipeline commissioning applications. The work scope required that the complete solution be capable of multiple deployments and recovery operations using a single string of 3.5-in. CT from a floating support vessel. The project began with a detailed analysis of the existing available equipment and tools to determine their suitability and limitations for this application. Factors in this analysis included the limited vessel space available for surface equipment, crane capacity, and the suitability of equipment for working outboard on a vessel. This led to the planning, designing, and sourcing of suitable CT equipment. Trials were performed onshore to optimize the rigup, stackup, vessel layout, and assemblies handling. The combination of pre-operation planning and trials led to confidence in the new tools, work methods, and risk assessments. Because the purpose of the deployment work was to complete the commissioning work on several different marine pipelines and risers, the equipment and work methods had to be easily transferred between vessels. This paper presents and discusses the range of technologies that were developed and successfully applied for the first time globally to complete the project. These include the first fully sealable subsea quick-disconnect for CT, the first pump-through modular clump weight, and the first real-time, high-cycle fatigue (HCF) monitoring system to aid in CT pipe management. The deployment and recovery operations involved a wide range of challenges and led to the development of specific tools and methods for using large-diameter CT equipment. In addition to discussing the design and development of the solution, this paper presents the results and lessons learned from successfully using the large-diameter CT downline solution for deepwater pipeline commissioning applications.
Abstract Coil Tubing technology grew as an off-shoot of the military needs during World War II. One such need was the requirement to spool continuous lengths of flexible pipeline across the English Channel, and the other post WWII need was to spool out long lengths of communication antenna from submerged submarines. These early advancements laid the ground work for other industries to capitalize on. It didn't take long for oilfield engineers to figure out the advantages of a continous tubing string for drilling and for working over wells. The need to ‘inject’ coil into a well bore under pressure has resulted in numerous designs, but they all have the basic components of the Injector Head with Guide Arch, Stripper, and a Quad BOP Stack. As with all oilfield tubulars, the eventuality of having the pipe stuck due to unforeseen circumstances created a satellite industry in removing such stuck tubulars. Many downhole fishing tools have been borrowed from their larger threaded cousins, i.e. tubing, drillpipe and casing strings. This paper briefly reviews the current techniques of extracting stuck coil tubing strings using downhole intervention, and presents a 12 year old process of surface intervention only, using Surface Resonant Vibratory Energy. Rig up procedures and case histories of this surface technique will be presented along with some engineering theory of the underlying acoustic principles of pipe extraction.
Abstract This paper demonstrates how innovative data acquisition, phased planning and world class placement of filler material in a short circuit lead to a successful water shut-off restoring 477 m/day (3,000 BOPD). Hess operates the South Arne Field located offshore Denmark. Two flank horizontal wells, a producer and a water injector, started short-circuiting water via an abandoned sidetrack. High pressure (517 barg) water from the injector flowed directly into the producer (172 barg) killing the oil production. The wells’ horizontal length is 3 km and is completed with a cemented liner. The liners are subdivided into 17 zones with production/injection tubing, iso-packers and sliding sleeve doors. Each zone has been stimulated with acid fractures. The vital part of the data acquisition was multiple tracer tests from different zones at different production and injection ratios, which increased the tracer recovery from 15% to 100%. In addition, tracer data revealed transit time, sidetrack volume and number of paths; all crucial information for a successful water shut-off. A gel mimic test was performed to account for differences in rheology. Pressure and temperature logging tools in the wells provided the pressure and temperature gradient along the sidetrack, which was crucial data for placement of the temperature sensitive filler material. The decision was to approach the challenge in three phases; firstly, data acquisition; secondly, interpretation of data, filler material laboratory tests, design of job; thirdly, implementation of the water shut-off. This proved to be advantageous as it allowed time for appropriate adjustment and planning of the complex setup. The 19 m (120 barrels) of filler material was mixed on the platform and pumped into the injection well tubing while producing from the production well at controlled condition with one optimal sliding sleeve door open in each well and an optimal production/injection ratio The temperature of the filler material increased as it travelled to its final destination in the sidetrack leaving a 450 m (1475 ft) solid isolation plug. One year after the water shut-off, oil production has increased from 0 to 477 m/day (3,000 BOPD) saving an expensive and challenging re-drill. This project underlines the importance of spending time and money, upfront, on innovative acquisition and planning to increase a project's chance of success.
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5604/29 > South Arne Field (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/5 > Greater Ekofisk Field > Tor Field > Tor Formation (0.94)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/5 > Greater Ekofisk Field > Tor Field > Ekofisk Formation (0.94)
- (8 more...)
- Well Drilling > Drilling Operations (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Tracer test analysis (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.88)
Abstract Coiled tubing (CT) injectors have been used in well intervention (WI) service for many years. As the WI business becomes more challenging, it requires the use of larger tubing. Using larger tubing results in managing tubing strings and operating equipment in a different manner. Tubing strings have become larger in size and yield strengths of the material have increased. Larger and stronger tubing subjects the equipment to greater stresses. The tubing also has more residual bending forces than the smaller, more traditional strings used in the past. The increased residual forces can affect the performance on the injector, adversely affecting the gripper beam pressure in particular. This paper discusses the results of residual bending forces and their effects on the CT injector. It compares computed values to actual values from experimental test data. The findings could change the effective gripper beam pressure. Introduction CT is attractive because it allows rapid deployment of tubing compared to drilling rigs. Rapid deployment can reduce cost, leading to increased profits. Several types of applications can be deployed using CT, including pipe cleaning, perforating, cementing, fracturing, and acidizing (Cobb and Zublin; Courville and Anderson; Connell and Engdorf; Koshak; Durey and Degner). One of the main components of the CT system is the injector. It injects tubing into the wellbore or pulls tubing out of the wellbore. It controls the tubing during the job, including during pumping services. The injector should be able to handle the pipe loading and fluid weight. If the injector cannot control the tubing, it can slip and fall into the wellbore. When the tubing slips, the gripping blocks typically cause significant damage. If too much pressure is used by the injector to secure the tubing, the tubing can be crushed. Damaging the tubing is a significant cost to the operations of well intervention. Increased well depth and pressure necessitates increased pipe sizes and other tubing properties. This stronger tubing is more rigid. Larger, higher-strength tubing is much more difficult to manage than smaller, lower-strength tubing. The residual forces generated by the larger tubing are larger than those of smaller tubing sizes. This can impact the performance of the injector. In very critical applications, the amount of force applied to the tubing can affect the success of a job. Residual Forces Residual forces in the tubing are based on the tubing properties, tubing size, and natural curvature of the tubing. After tubing is bent, it has a natural curvature, or steady state. This curvature is the basis for calculating the residual forces. Fig. 1 shows the residual forces based on the different tubing sizes and bend radii. Tubing size is a significant factor in residual bending forces. After the residual force is established, it can be directly related to gripper-beam pressure based on the gripper-beam hydraulic cylinder size and quantity. The gripping force (gripper pressure) should counter the forces generated from the tubing's residual bend. This necessitates that additional gripper pressure be calculated with the slip pressure. The results presented in Fig. 1 are the forces required to straighten a section of CT, with a residual bend, calculated from the simply supported beam equations (Eqs. 1, 2, and 3). An illustration of a simply supported beam is shown in Fig. 2. The deflection required to straighten the tubing was calculated from the reel diameter and length of the gripper blocks, as illustrated in Fig. 3. The maximum deflection, ymax, for a simply supported beam is shown in Eq. 1, where P, L, E and I are the force, beam length, Young's modulus, and moment of inertia, respectively. The Young's modulus for steel, E = 30 Mpsi, was used for all calculations. Solving for the force or load, P, in Eq. 1 yields the equation shown in Eq. 2. The length of the gripper block determines the length, L, of the simple support beam. The calculation for the moment of inertia for an annulus is shown in Eq. 3, where OD and Wall are the outside diameter and the wall thickness, respectively.
Abstract A case history of an attempted CT intervention in 43' of water through a wellhead leaning at a 45 degree angle is presented. A major concern for this intervention was the integrity of the intervention stack between the leaning wellhead and the CT injector located on a lift boat. The stack design, testing and stack performance during the job execution are presented. Introduction Hurricane Katrina damaged many wells in the Gulf of Mexico. One well in 43 ft of water in the West Cameron field was left with the wellhead leaning at 57 degrees. The operator wants to P&A this well. An unsuccessful attempt was made to pull the wellhead upright. A CT intervention was attempted to P&A the well, with the CT unit located on a lift boat. Support structures were built to hold the CT injector at a 45 degree angle and to support the intervention stack between the wellhead and the lift boat. There was significant concern that the intervention stack between the wellhead and the lift boat would be safe. Extensive stack modeling was performed during the job planning and equipment selection process. A dynamic finite element stack modeling package (Smalley 2005) was used to perform this analysis. The API 6AF bending limits were added to this analysis software because these flange bending limits became the most limiting aspect of the job. Based upon this analysis, the planned stack support structure was greatly simplified, reducing the installation time and cost. A force and moment gauge (Newman 2004) was placed in the stack to measure the forces and bending moments. This gauge was useful in obtaining proper stack alignment, reducing bending in the stack. The gauge was then used to monitor the stack during the attempted P&A intervention. Initial Well Situation Figure 1 shows a survey of the well from the mud line up and Figure 2 shows a picture of the wellhead above the water. The first concern was whether the outer 36", inner casings and the 2 3/8" tubing were kinked below the mud line. If they were, it would be impossible to plug and abandon (P&A) the well with a CT intervention. An engineering analysis had been performed to calculate the deformed shape of the well below the mud line and the ovality of the well tubular based on this deformed shape. Figure 3 shows the deformed shape from this study. The smallest radius of curvature was calculated to be 14' at between 25' and 30' below the mud line. The amount of ovality in the 2 3/8" tubing was determined to be negligible. Thus, a CT P&A intervention was deemed feasible. Previously an unsuccessful attempt had been made to pull the wellhead upright. It was decided that the CT intervention had to be performed at the current angle of the well. A support pylon was driven beside the wellhead to prevent further wellhead movement. The wellhead was lifted somewhat and attached to this pylon at an angle of about 45 degrees.
- North America > United States > Texas (0.90)
- North America > United States > Louisiana (0.54)
Abstract Offshore well intervention with coiled tubing (CT) in the Niger Delta has traditionally been rig-based. Experience has shown this type of activity to have high cost implication both cash wise as well as in time. With the current focus on development of offshore marginal fields, it has become imperative to perform well intervention operations at a more reduced cost to the operator. Non-rig based interventions can provide an economic advantage. However, inadequate facilities on existing offshore platforms and jackets present additional challenges. Furthermore, performing well intervention from a supply vessel is definitely not a mean task. Despite the complexity of this type of activity, the cost savings for not mobilizing a rig usually makes small intervention work that would increase oil production attractive to operators from the standpoint of ROI, vis-à-vis comparing the cost of the total intervention to the projected production gains. To the smaller operators and marginal field developers, this opens up a world of opportunities. This paper explores these opportunities and discusses how they are being exploited to yield optimum benefit for the marginal producer. The success of carrying out various types of well intervention work on four wells (two dual completions and two single completions) is showcased as case histories. Introduction Drilling activities offshore Nigeria dates back over forty years, with quite a lot of offshore platforms erected in that period. In recent times the focus has shifted to Deep water, with increased investment by major producing companies, some of them have formed new offshore divisions to handle these deep water leases. These companies have prospected; some have made large oil and gas discoveries, and are currently in the process of developing these offshore fields in the Niger delta. Due to the shift of focus of the Majors to these new large offshore fields that require obviously a lot more investment, and also due to Nigerian Government regulations that require that on the expiration of an Oil Prospecting Licence (OPL) the fields must revert back to Nigerian National Petroleum Corporation (NNPC) for another bidding round, these older fields (the ones considered less viable by the majors) have been returned to NNPC and subsequently reallocated after a bidding round to indigenous oil companies and the Government-owned subsidiaries. These companies find themselves inheriting wells that are marginal producers with old facilities that not of modern design. Generally these offshore platforms are in water depths ranging from 30 ft to 250 ft. Most of the facilities are four legged platforms with limited deck space, while others are caissons i.e. a single circular beam piled into the sea bed sealed at the top and filled with compressed air to keep water and mud out at depth. Typical configurations for some of these platforms which have 3 decks are: a boat landing deck at 6 ft above the sea level, wellhead deck at 24 ft above sea level, and the helicopter deck at 60 ft etc (Fig. 1). The common challenges for intervention in such installations include:Inadequate deck space. Inadequate crane capacity - In the reviewed case histories the platforms involved did not have cranes. The producing wells are draining mature reservoirs. Combined with the difficutly of access, they are can be candidates for an extensive amount of intervention work such as matrix acidizing, water control, scale removal, and sand consolidation to maintain an economic production rate. Due to the scarcity and high cost of jack up rigs to carry out the various remedial interventions, there are obvious advantages of utilizing barge mounted CT as the means of providing solutions.
- Africa > Nigeria (1.00)
- North America > United States > Texas > Harris County > Houston (0.28)
- Government > Regional Government > Africa Government > Nigeria Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract The Nelson field is located 120kms offshore from Aberdeen in the Central North Sea. It is an important asset for Shell UK in the North Sea. This paper highlights the important steps that Shell UK is taking towards reducing its oil to sea discharge and meet compliance with OSPAR regulations. The heavily corroded state of the Nelson water injectors posed a major challenge towards successfully recovering the slot and executing a workover, which would allow produced water to be re-injected into the reservoir instead of being discharged to the sea. This paper details the work scope, the plans and execution of the workover. It highlights the challenges that were faced by the team to deliver a well capable of produced water and seawater injection. The paper details the final results obtained from the successful campaign on the Nelson platform. Introduction Field Background: The Nelson Field (Block 22/11) is located approximately 120km east of Aberdeen in the Central Graben of the North Sea UKCS. The reservoir interval is the Paleocene Forties sandstone and comprises turbidite sandstones deposited in a proximal mid-fan part of a large basin-floor sub-marine fan system. With a current daily oil production of around 40,000 bopd, the Nelson Field has been and remains an important asset for Shell UK Ltd. There were four seawater injectors on the periphery of the Nelson field. Together they had injected over 235 MM bbls of seawater (Figure 1). Nelson PWRI Project: The Nelson asset needed to reduce the quantity of oil discharged to sea by 18% (compared against the oil discharge to sea in 2000) to meet the 2006 OSPAR requirements. The base forecast showed a gap between forecast oil to sea tonnage and the OSPAR regulations. Produced Water Re-Injection (PWRI) was selected as the solution to meet OSPAR commitments. The plan was to install new produced water injection facilities on the platform and workover the existing seawater injectors to allow injection of the bulk of the produced water under reservoir fracturing conditions. The combined modifications would give the system a capacity of injecting 170,000 bbls/d. A number of producers and injectors were identified as donor wells for the project. Bearing other key considerations in mind (like subsurface value, well integrity issues), the existing seawater injectors were judged to be the most suitable candidates for conversion into produced water injectors. Annular leaks had been detected in all four seawater injectors. Water injection continued under short-term dispensation until Dec 2004, when it was shut down to preserve production casing integrity. The PWRI project was also seen as an apt technical solution to restore well integrity in these injectors. In order to establish a baseline well condition status, lead impression blocks (LIB) were run into the water injectors. The LIB results were inconclusive and a down hole camera (Omega Camera Services) was run in hole. The pictures confirmed that there was substantial damage to the production tubing and expectedly to the production casing (figure 2). Multiple Challenges The integrity and lifecycle operability of the production casing was the primary concern. Given the amount of damage to the completion tubing, it would not be unexpected to find the production casing in a similar state. It was difficult to judge whether a "simple" workover would suffice or would this necessitate a full slot recovery operation to drill a new water injector. An accurate measurement of the casing wall thickness was required to answer this question. A USIT (Ultra Sonic Imaging Tool) or a Calliper log would have helped, but that could only be possible after retrieval of the production tubing.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.55)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/7 > Nelson Field > Forties Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/6a > Nelson Field > Forties Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/12a > Nelson Field > Forties Formation (0.99)
- (2 more...)