The use of hole opening tools in conjunction with Rotary Steerable Systems (RSS) has increased dramatically in the past few years. Although excellent performance has been delivered with the mainstream commercial tools, alternate options have been developed to enable an RSS to drill the pilot hole in conjunction with a string tool to open the hole in a single run.
The most popular current option involves a weight or hydraulic activated underreamer. However, fixed blade, multi-diameter reaming tools have recently been developed for use within Rotary Steerable (RS) assemblies:
Several distinct applications are documented where these fixed bladed solutions, in combination with both Push and Point RS tools, have proven extremely successful. This has provided greater flexibility with regard to tool selection and well planning options, delivering lower cost per foot in RS projects. Case studies are presented from the Far East, Norway, and the Gulf of Mexico.
Drill cuttings and other hydrocarbon contaminated wastes generated in offshore drilling operations have been processed
onshore for many years, in part to comply with the regulatory restrictions governing offshore disposal and in part to conform
to sound environmental practice. However the transporting ("skip & ship??) of large tonnages of hydrocarbon contaminated
cuttings from offshore installations to shore based processing facilities carries with it considerable environmental and safety
implications for the industry.
The concept of processing these hydrocarbon contaminated cuttings offshore and the recycling of both the recovered oil and
water back into the drilling fluid provides a unique solution to the inherent problems of "skip & ship??, both in the North Sea
and elsewhere. The development of this concept into a practical, field proven technology commenced in 2001 and was
satisfactorily concluded, following a series of offshore trials in the UK sector of the North Sea, in the latter part of 2002.
Since this time the application of this technology has gained wider use and greater acceptance by the industry, allowing for a
thorough evaluation of its application in resolving many of the more intransigent problems associated with drilling waste
management in offshore operations.
This paper reviews the work completed to date and how it might best be applied in the future. For the work completed, field
data will be provided on all aspects of the process and also evaluate the benefits, both in terms of the environment and safety,
on a project specific basis.
With regard to the future, the paper will look at ways in which offshore treatment may be better applied to optimize all of the
Heightened levels of industry activity have put an increased focus on all types of training, particularly in the critical area of well control. The development of competent personnel capable of recognizing, avoiding and mitigating well control situations requires industry-developed systems capable of establishing necessary training standards and quality assurance programs that monitor training provider performance, both essential elements for ensuring proper skills development through fit-for-purpose training.
The Well Control Accreditation Program (WellCAP) operated by the International Association of Drilling Contractors (IADC) is designed to provide the drilling industry the building blocks for a comprehensive "well control culture?? beginning at the floorhand level and continuing to the most seasoned drilling personnel.
Rig workers are introduced to the basics of well control equipment at the Introductory Level. Simulator exercises provide a higher level of practical knowledge at the Fundamental Level, recommended for Derrickmen, Assistant Drillers and Drillers. More complex simulator exercises and calculations are a component of the Supervisory Level, designed for drillers, toolpushers, superintendents and drilling foremen. WellCAP Plus is the latest addition to IADC's WellCAP system, which introduces a new learning model focus on highly experienced employees.
Since the program was first implemented in 1995, WellCAP's curriculum offerings have evolved steadily to keep abreast of industry needs.
Tarr, Brian Anstey (Shell Intl. E&P Inc.) | Schroeder, James Robert (Penn Virginia Oil & Gas Corp.) | Taklo, Tor (Shell Intl. E&P Co.) | Olijnik, Luiz Augusto (Cooper Cameron Corporation) | Shu, Hongbo (Shell Intl. E&P Inc.) | Hudson, Andy (Shell Philippines Explor. B.V.) | Greff, Richard (GlobalSantaFe Corp)
A surface BOP system with a seabed isolation device (SID) was successfully used to extend the water depth capability of the D.P. semi-submersible rig Stena Tay for exploration drilling activities in ultra-deep water to 2,887 m offshore Brazil and to 2,447 m offshore Egypt in 2003. This provided the necessary experience to take the next step towards reducing the cost of deepwater developments utilizing a surface BOP system deployed from an earlier generation, lower specification, deepwater rig.
This paper presents the configuration and specifications developed for the surface BOP drilling and subsea completion system to be deployed offshore Brazil in the first phase of the Parque das Conchas development (block BC-10) that encompasses several reservoirs in up to 2,100 m of water.
The rig selected for the project had to meet certain minimum requirements to safely deploy the planned surface BOP system, and these requirements led to the selection of the Arctic I, a moored rig capable of operating in 945 m of water using a conventional 18-3/4?? subsea BOP stack and marine riser system.
The new elements incorporated in the surface BOP system include:
Development drilling operations with this surface BOP system are now expected to commence in the first quarter of 2008.
Subsea well intervention has been around in the North Sea for many years as documented in papers such as Pollock (1990) but in the last five years there has been renewed interst due to a combination of high oil price and aging wells. This paper will look at the actual results achieved with production enhancement work done in subsea wells across the United Kingdom (UK) sector of the North Sea over a five year period 2002 to 2007. This time frame allows the results to be seen in the context of longer term field value. All the work included in the paper was done rig-less with a specialist subsea well intervention vessel. It covers a range of different oil producing fields operated by a number of different companies. The work done was through tubing and included zone isolation and re-perforation. No work was done in any gas fields. The paper will detail the production profiles of the wells both before and after the intervention work along with a discussion of the work done and an explanation of the factors that influenced the final result both good and bad. To facilitate an open discussion of the success and failures all data is presented anonymously. The high cost of subsea wells makes it essential to maximise the overall recovery per subsea well. This paper will detail actual results which may point the way forward.
A novel MPD setup has been tested and used at the Kvitebjørn field in the North Sea to make possible the drilling of 8.5" holes through reservoirs with heavily depleted zones. A central part of the concept has been to use an advanced dynamic flow and temperature model in combination with an automatic choke system to control open hole pressure very accurately.
The paper describes briefly the operations, and discusses challenges and experiences related to making these complex components work reliably together.
The system has proven its potential for minimal variations in pressure at a given open hole position, with accurate automatic pressure control in wells were margins are very small, smaller than frictional pressure losses added when circulating at drilling rate.
This paper focuses in particular on the use of an advanced transient model for automatic choke regulation. Other aspects of the operation are described in more detail elsewhere, see Refs. 1-3. Challenges exceeded expectations, but after a test period with many improvements based on trial and error inside cased hole, the 8 1/2" sections were drilled successfully with good pressure control.
Kikeh Field is located 120 km from Labuan in offshore Sabah Malaysia. The field, with 1330 m water depth, is the first deepwater development in Malaysia and consists of subsea and SPAR development wells.
The West Setia is a non-propelled Semi-Submersible Drilling Tender being used for SPAR development activities. The Drilling Tender utilizes six stability columns supported by a twin-hull configuration. However, the derrick and partial rig package still sits on the SPAR (or platform deck) to carry out drilling and completion operations.
The completion program covers not only standard scope of installation, i.e. lower, middle and upper completion, but also includes displacing fluid with nitrogen for riser dewatering and well clean up and testing. Several logging operations also were identified as tasks to be delivered during completion operations.
Considering the wide scope of completion work outlined in the program, a detailed work assessment was conducted focusing on areas where offline activities could be conducted safely and efficiently. As a result of the assessment, at least seven completion-related activities were identified.
During the first batch of SPAR completions which involved five wells, the result showed that the following activities were successfully completed offline, allowing the rig to be utilized for critical path operations:
This paper will describe in detail each of the operations involved, discuss rig capabilities and limits, and explain the challenges, safety considerations and lessons learned from the project as well as the time savings and value created from each of the activities.
Completions in deepwater sub sea applications are becoming increasingly more expensive and complex. This complexity is compounded by the challenges of installing intelligent completion equipment in deepwater environments. Reliable completions are a direct result of how well the pre-planning and procedures are implemented. The Industry is challenged to integrate multiple service provider equipment and procedures into a single intelligent completion system. Intelligent Well Completion System Integrity Tests (IWC SIT) are being utilized as a proactive means to mitigate risk. This is especially true in international operations where the logistics and planning have a greater degree of complication for completions. This paper is an overview of an IWC SIT conducted in March 2007 for a West Africa deep water field. The write up is a discussion of the planning, implementation, and learning captured for the operation. Highlighted in the paper is a series of subassemblies as run and retrieved from a land rig location. Actual down hole equipment was utilized. Service provider personnel employed for the operation were also the technicians expected to run the equipment on the deepwater rig. A formal report and video were developed to share lessons learned and best practices with the Project Team. The operation was considered successful due to the efforts of a number of service providers, partners, and operator company personnel. A strong commitment to safety, learning, and improving the operations was demonstrated by all involved.
The field being highlighted in this paper was discovered in 1998. Planning for drilling and development has been underway since this time. Chevron has installed a very limited number of intelligent systems to date. In the industry, there are estimated to be some 500 +- total systems installed by all operators worldwide. Technology advances are being incorporated into new systems for various types of IC equipment. Function testing and reliability of these systems often come under intense scrutiny. This paper is focused on the benefits of conducting an IWC SIT to mitigate installation risk, which is basically an effort to integrate service providers and improve installation efficiency.
Since the early 1940s casing centralization has been identified as being key to efficient mud removal and therefore to
successful primary cementing. Prior to a job it is common for field engineers to spend time optimizing casing centralization
using commercially available or proprietary software, in particular for highly deviated wells. However predicted casing
centralizations suffer several limitations due a number of possible assumptions. For example, the mechanical response of
centralizers is usually characterized in a single hole size, and different rules are used to extrapolate their behavior in different
hole sizes. Needless to say, there are not too many holes that are perfectly in gauge and therefore centralization calculations
in out-of-gauge sections can be questioned.
With the recent introduction of a new generation of cement evaluation tools making use of flexural waves propagating
vertically along casing and radiating into the annular space, it may be possible to measure the time of arrival of the
cement/formation interface echo and therefore to measure casing eccentering. Therefore, one can now compare the calculated
casing centralization to the one measured downhole.
The objective of this paper is to review some of the current limitations of casing centralizer calculations as they are being
performed in the field on a day to day basis. The analysis is supported by a comparison between measured and predicted
casing centralizations on a number of field cases. Examples showing the effects of the observed discrepancies on cement
placement using a displacement simulator are discussed. Recommendations to improve centralization predictions are
The influence of improved technologies and the latest operational developments has lead to a significant impact in the arena of coiled tubing drilling operations. These influences are also making themselves known in the underbalanced coiled tubing drilling sector. Sidetracking operations have traditionally utilized a philosophy dominated by threaded tubular drilling conveyance methods; however, with the growth of coiled tubing drilling applications in recent years, coiled tubing deployed bottomhole assemblies for sidetracking a well are beginning to gain acceptance as a standard practice.
A major advantage of a coiled tubing deployed exit system is the ability to mill a window in the casing in a restricted wellbore environment. The whipstock can be deployed in a live-well condition without the necessity of removing the completion equipment thus eliminating the requirement for a workover rig and negating the need for kill weight fluids. The systems can be deployed on either electric wireline or coiled tubing making them ideally suited for restricted bore access and allowing the window to be milled below the completion.
The discussion will include a comprehensive overview utilizing a new whipstock system with the conveyance method of coiled tubing and electric wireline in order to create a casing window. The overview will also communicate general practices and tool selection criteria with the case histories representative of the placement of the whipstock with coiled tubing and the window milling being performed with coiled tubing workover motors. The case histories will detail two runs of the new exit system, the first in the North Sea and the second in the Middle East. Both case histories will show the economic benefits of utilizing live well intervention deployment methods for whipstock placement as well as the rig cost savings of utilizing coiled tubing deployed mills and motors for delivering a casing window.