bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Liner Drilling Technology as a Solution to Hole Instability and Loss Intervals: A Case Study Offshore Indonesia
Authors: Jianhua Liao , Darmawan Andrias , Chao Zhao , Rosenberg Steve , Hillis Keith , Utama Budi 
Published: March 2009

Abstract
The Banuwati field offshore South East Sumatra, Indonesia presents major challenges to both drilling and liner running operations, because of the problematic Lower Baturaja limestone formation, which is a carbonate reef structure known for severe lost circulation conditions. The operator had previously experienced severe losses with wellbore stability issues while drilling this formation with the inability to set the 7-in. drilling liner at the planned depth in well A-3. The liner had to be pulled out of the hole leading to the eventual abandonment of the existing open hole section and resulted in the sidetracking of the well. Liner-while-drilling technology was identified as the most suitable solution for setting the planned 7-in. drilling liner through the loss interval because:
Documented lost circulation problems have been minimized or eliminated through the use of liner drilling technology possibly attributed to the "smear effect"1 phenomenon. The liner system selected provided for high torsional capability as well as the requirement for both a mechanical and a pressure event to release the setting tool, thus minimizing the chances of premature release. A drill shoe with a displaceable PDC cutting structure was used to drill the 8 1/2-in. hole section and subsequently displaced prior to cementing so as to allow drill out with a conventional drill bit and BHA.
This paper will discuss the implementation of liner drilling technology in the Banuwati field project. This technology was used to drill successfully through the known lost circulation zone with the 7-in. liner cemented in place allowing the operator to reach their completion objectives while realizing a savings of more than US$1 million.
Electrical Cranes and Winches for Improved Safety and Better Operational Performance for use in Extreme Weather Conditions
Authors: Austefjord Arne , Kverneland Hege 
Published: March 2009

Until recently, most drilling and production rigs have been designed for operation in temperate climatic zones, and within a typical temperature range of -20°C to +50°C. Increasing demand for petroleum products has moved oil exploration into more hostile and challenging areas like the Barents Sea, onshore in northern Siberian territories, and also in hot desert areas like Sahara and the Saudi Arabian desert. As a result, the hoisting and drilling equipment must be designed to operate reliable and safely also in extreme temperatures. This may be a problem, especially for hydraulically powered equipment which is highly temperature dependant, compromising both the working availability of the equipment, and the safety and accuracy of the machine when in operation.
A new electrical winch by use of permanent magnet motor (PM-motor) technology has been developed and implemented for use on hoisting appliances ranging from small man rider winches to large offshore cranes. This new technology uses an "inside-out" PM-motor integrated in the winch drum was first introduced to the offshore market four years ago in a Manrider winch application. This technology is now adapted to larger horsepower winches, increasing safety and operational performance for the crane. This PM-motor winch satisfies both the American Petroleum Institute (API) and the European Norm (EN) regulations for crane applications.
This paper will focus on the benefits using electrically powered cranes. The paper will especially focus on PM-motor technology, and the possibilities to optimize the design with respect to shape, size and performance. Extensive tests of the PM-motor itself, the crane winch and its control system and of the crane have been performed and will be discussed. The enhanced safety aspect for emergency lowering operations in offshore cranes for a PM-motor compared with AC-induction motor will also be discussed.

Definitions
AC-motor= Induction, squirrel cage motor controlled by means of a variable speed frequency drive
PM-motor= Permanent Magnet motor controlled by means of a variable speed frequency drive
New Washpipe Technology: Why Operators Should Care
Authors: Borland Brett , McCoy Steve , Mason Rick , O'Dwyer John , Ogg Jeremy 
Published: March 2009

This paper will outline the application of a breakthrough technology to address Top Drive washpipe durability in high temperature and high pressure (HPHT) wells. The introduction, application, and submission of a performance comparison to support the advancement/proliferation of this technology are presented from an operating company's perspective.

Problem
Since the introduction of Top Drive Systems in the late 1980's, a consistent limiting factor has been the durability of the washpipe seal mechanism, particularly in HPHT + high speed drilling applications. This durability issue has greatly affected the efficiency of the circulation system's integrity, and it has also decreased overall operating efficiencies. Washpipe failures occurring during critical operations, such as during well control situations, can increase risk to personnel and equipment.

Solution
National Oilwell Varco has introduced a technical solution that utilizes mechanical sealing technology developed outside the oil and gas industry. This technology has proven itself in joint-effort field trials by ConocoPhillips and Ensco in the North Sea. The challenge is to promote the use of the technology worldwide to solve the habitual washpipe durability problem.

Challenges to Implementation
Traditionally, new technology is difficult to implement in the oilfield. The intent of this paper is to help overcome typical barriers and help rush this solution out to positively impact the drilling fleet as quickly as possible.

Conclusions
A reliable sealing mechanism has been identified to address the washpipe durability issues, and field trials of this new product have yielded positive results. The typical barriers to product implementation were minimized by applying previous lessons-learned, with successes in operations, cost savings, and safety.
The Use of a Novel Rigid Setting Fluid for Well-Isolation and to Cure High-Rate Losses by Pumping Through the Bit in the Southern North Sea
Authors: Couper Chris , Robertson Bruce , MacArthur Donald , Scott Doogal 
Published: March 2009

Abstract
Several lost circulation materials (LCMs) are available to operators who wish to minimize downtime while combating lost circulation. In general, fine to medium-sized particulate-based materials mixed into the mud system are the first line of defense. When this fails, the common response is coarser LCM, which often cannot be pumped through downhole tools. Operators then might choose to pull out of hole (POOH) with the drilling bottomhole assembly (BHA) and run in with a cement stinger.
This paper discusses a practical, field-proven solution that eliminates time-consuming and potentially hazardous trips in and out of hole. This is done by using a right-angled set, temperature-activated fluid that, once set, exhibits similar characteristics to Portland cement. It can be confidently pumped through the BHA to combat all static or dynamic losses.
The cases discussed in this paper were located in the 43/19a Cavendish field in the southern North Sea, while drilling through Plattendolomit. Plattendolomit is a thin, complexly folded and rafted dolomite that is found within the Zechstein halites. This formation presents significant well-control challenges with the potential for high overpressures coupled with high-rate dynamic losses, particularly Quads 43 and 44. The novel fluid was used to cure dynamic losses of up to 400 bbl/hr. The fluid was also used to isolate the well to allow safe tripping to replace worn blowout preventer (BOP) components. As small changes in bottomhole pressure caused high-rate losses and gains, it was not possible to kill the well by conventional means. A plug was set inside the casing that isolated the kick/loss zones from the wellbore.
Because it was possible to drill out the isolation plug with a drilling shoe on the liner, considerable rig-time was saved.
Improving Wellbore Seal Integrity in CO2 Injection Wells
Authors: Benge Glen 
Published: March 2009

AbstractThe challenges associated with the construction of an injection well for carbon sequestration are cross disciplinary, but highly manageable. Site selection, reservoir identification and formation evaluation involve geological and reservoir specialists that perform detailed evaluations of the subterranean environment.[1-4]Materials selection identifies components that are designed to withstand the unique chemical and physical environments of these wells. Sealant selection is key to providing long term integrity of any well, with Portland cement being the material of choice for most oil field applications.Work on Carbon Sequestration in subterranean formations has renewed interest in investigating the long term effects of CO2 on Portland cements. Portland cement will react with the injected CO2, and while recent research indicates these conventional cements are not a concern, additional work is ongoing to improve the long term effectiveness of the wellbore sealant.Efforts have focused on enhancing the properties of Portland cement by reducing the permeability of the set cement, lowering the concentration of materials in the cement that react with CO2, or replacing the conventional Portland with specialty cements. Complementing technologies that have been used to further promote long term seals include the use of in-situ swell packers, and self healing cements.Additional work has been done in evaluation of the long term stress environment of the well. This work goes beyond the simple drilling and completion of the well to include input from long range reservoir and wellbore stress modeling through the full life cycle of the well. These stresses are evaluated to confirm the selected sealants can withstand the changing stress environment.This paper discusses various identified solutions to the challenges of selecting a proper wellbore sealant for a CO2 injection well. Additionally, the paper reviews the available sealant technologies, their application, and includes a discussion of stress modeling for these wells.
Probabilistic Well Time Estimation Revisited
Authors: Adams A. J. , Gibson C. , Smith R. 
Published: March 2009

AbstractProbabilistic estimation of well duration has been common practice for over a decade; many papers have been written on the subject, and commercial software is available for the purpose. Is the subject therefore mature? The authors suggest that this is not the case, and show that several essential aspects of both data characterisation and probabilistic analysis have been overlooked in previous contributions.A database of 104 central North Sea wells was independently re-analysed for non-productive time (NPT) from the original daily drilling reports. Mechanical extreme NPT events (those over 2.5 days) were only 4% by number, but contributed 51% of NPT by duration. It is shown that mechanical parent NPT, mechanical extreme NPT, open water WOW, and riser connected WOW are all statistically distinct, with very different occurrence frequencies and probability density functions (PDFs). These data vary widely by well type, installation type, and time of year.The paper gives tables of all required occurrence frequencies and PDF parameters, together with a full theoretical basis. Earlier workers did not publish this information, nor did they observe that the four NPT types above are statistically distinct. It is shown that trouble-free time plus mechanical parent NPT is log-normally distributed, whereas the other PDFs are Weibull. These PDF types are not currently available in commercial software, and the authors are working with a software provider to remedy this deficiency.Example results (PDFs of predicted duration) are given by well type, installation, and time of year. They are in good agreement with the historical database.
Improving the Reliability of Slip Joint Packer Systems
Authors: Upton Tom L. 
Published: March 2009

Abstract
The loss of drilling mud past the primary sealing element of marine riser slip (telescoping) joints has been a recurring source of releases [or discharges] within industry. This paper discusses work processes and equipment arrangements the operator has implemented to improve the sealing reliability of slip joint packer systems.
Slip joint packer designs have not changed significantly since they were first introduced for use on floating drilling rigs in the early 1960's. With non-aqueous drilling fluids (NADF) being used extensively in today's offshore drilling operations, leakage of drilling fluid past the slip joint packer is undesirable. In many cases, the loss of drilling fluid has been the result of either a failure of the packer element or failure of the pressure system used to energize the packer. Slip joint packers were originally designed for use with water-based mud systems and typically a minor amount of fluid seepage was relied upon to lubricate the packer. In order to provide complete containment of NADF, it has become common practice to apply higher closing pressure to the sealing element which has reduced lubricity and led to premature wear of the sealing element and occasional catastrophic failure of packer elements.
In order to contain NADF in the event of failure of the primary packer system, the operator now employs an independent backup pressure supply system that automatically energizes the lower (secondary) packer in the event of loss of pressure in the primary system. The lower packer is automatically energized when a predetermined pressure drop is detected in the primary system as a result of either loss of supply pressure or primary element wear damage.
The operator has also established a routine inspection and surveillance program intended to detect slip joint problems before they result in accidental NADF discharges.
Identification and Qualification of Shale Annular Barriers Using Wireline Logs During Plug and Abandonment Operations
Authors: Williams Stephen , Carlsen Truls , Constable Kevin , Guldahl Arne 
Published: March 2009

Abstract
It has long been recognised that during and after drilling through certain formations, the rock moves inward and begins to close off the well. Normally this phenomenon is considered undesirable since it can cause problems for drilling and casing running. It can however be put to good use as the mechanism to create an annular barrier behind casing.
In order to extend the life of a number of North Sea brown fields many well slots on production platforms and sub-sea templates are being re-used. This process involves permanent plug and abandonment of the old well track prior to sidetrack drilling into a fresh area of the reservoir. Norwegian Continental Shelf (NCS) regulatory requirements dictate that compliant procedures for well abandonment require the establishment of double barriers to avoid leakage from the reservoir. With a shortage of sufficient traditional cement barriers these wells often need costly remedial work in order to meet abandonment requirements.
Traditional sonic and ultrasonic azimuthal bond logging provides information on the material immediately behind the casing. Many such bond logs show solid material behind the casing far above the theoretical cement top. Clear correlation of this bonding pattern to shales, known to cause problems during drilling, indicates that the shale has sealed off the annular region and that it is the presence of such formation material that results in a good bond log response
Logging and pressure testing sealed off zones in a number of wells allowed the bond log response to be qualified for a certain formation without further pressure testing. In this manner logs can provide a clear answer of whether shale successfully seals off certain zones and consequently provides a natural annular barrier. This technique has been employed successfully on over 40 wells, proving non-destructively that high quality natural annular barriers had formed, resulting in elimination of complex remedial work and substantial cost savings.
Analysis of Complex Wellhead Load Events for Conductor and Surface Casing Strings
Authors: McSpadden Albert R. , Glover Simon 
Published: March 2009

Abstract
The analysis of mechanical and thermal-induced wellhead growth and resultant loads can be critical for tubular stress design and failure analysis of offshore platform wells. Standard simulation tools are typically used for this analysis. However, some common complex wellhead loading events are not explicitly accounted for in currently available software. Analysis of wellhead growth and loads from first principles is used to investigate these complex load events. Particular attention is given to conductor and surface casings and some non-intuitive results are discussed. A case study is presented to illustrate a range of field applications.
The analysis and related methodology apply to complex load events including: tension from conductor tension units (CTU's) or top-tension riser (TTR) systems, order of CTU overpull and landing of subsequent strings, lift-off of strings without lock-down, lift-off at mud-line hanger (MLH) systems and loss of pre-existing casing strings due to structural failure.
It is commonly recognized that standard single-string casing design which ignores wellhead movement is conservative for most casing strings. Similarly, it is understood that this single-string analysis is non-conservative for the outermost string. However, the extent and nature of non-conservatism as well as identification of all strings for which the standard analysis is truly non-conservative is not always understood. Also, the effect of sequencing CTU overpull and landing subsequent strings is also not always recognized.
The analysis methodology and case studies discussed in this work provide an explicit and intuitive approach to multistring wellhead movement and loads which can be implemented in spreadsheet calculations to model each step in the loading sequence on the wellhead. The nature of wellhead loads on the outermost conductor or surface string compared to inner strings is explained. The effect of CTU loads and the sequence of application are also explained. Certain types of wellhead load events, which are not accommodated using available commercial software tools, are modeled and analyzed. Even when numerically based software simulation tools do accommodate the load conditions considered, a closed-form analytical model based on first principles is still useful for understanding the nature of loads and also for first-order verification of numerical results.
Combining Proven Anti-Sag Technologies for HPHT North Sea Applications: Clay-Free Oil-Based Fluid and Synthetic, Sub-Micron Weight Material
Authors: Carbajal David , Burress Charlotte , Shumway Bill , Zhang Ying 
Published: March 2009

Abstract
North Sea wells drilled in high-pressure, high-temperature (HPHT) areas are known for presenting barite sag challenges. Fluid densities in the 17.5–18.0 lbm/gal range require a high percentage of barite, and 400°F temperatures can adversely impact the rheological properties needed for reliable suspension. Further, horizontal and extended reach drilling (ERD) wells can require specific hydraulic parameters for hole cleaning that may entail comparatively high pump rates which can contribute to excessive equivalent circulating densities (ECD).
Drilling fluid companies initially responded to these challenges by utilizing modified barite and alternative weighting agents. Micronized barite has been used to help lower ECD values for years. However, a non-barite manganese tetraoxide weighting agent has proven to provide equivalent anti-sag at a lower cost. The sub-micron sized material has a specific gravity (sg) of 4.8, which is higher than barite. Per Stokes' law, small particles settle more slowly so that sag resistance improves which is important during extended static periods like during extensive coring operations. Manganese tetraoxide is also acid-soluble. These parameters provide more operational flexibility.
The manganese tetraoxide weight material has now been tested successfully in a clay-free and economical paraffin/mineral oil-based fluid (OBF) for use in North Sea HPHT applications. The low-solids, clay-free system has a long history of reducing ECD and minimizing downhole losses while drilling, running casing and cementing. The 17.9 lbm/gal fluid weighted with manganese tetraoxide material exhibits effective hole cleaning properties at lower viscosities than conventional OBFs and shows no detectable sag tendency. Clay-free fluids also demonstrate excellent return permeability values in a wide range of well types.
This paper details the design and testing of the clay-free ERD system, including extreme HPHT static aging and sag testing and modifications to the emulsifier package. The economics of implementing the commercial system are also discussed.
Electric Wireline Milling—New Solutions for New Challenges
Authors: Joyce Robert H. 
Published: March 2009

Abstract
The concept of milling obstructions in wellbores, utilizing electric wireline as a means to deploy the service, was introduced in 2005. Since that time, oil and gas operators around the globe have used this well intervention technique efficiently and cost effectively. These wireline-conveyed technologies have performed well in both completion and workover programs by providing the means to drill out stuck isolation or safety valves, remove non-retrievable plugs and re-establish production by removing scale.
The additional cost of lost or deferred production is always unwanted. The deployment of a traditional rig or coiled tubing unit to help restore production comes with considerable cost owing to the equipment and personnel requirements to operate these heavy equipment platforms. Consequently, operators continually look to new techniques to minimize this burden. Milling on electric wireline, where applicable, is one such technique since it can be offered within a rig-less environment.
Experience has shown that each and every new milling challenge requires careful study of the problem along with extensive planning, testing and verification of the technique. Every downhole scenario provides a different characteristic to consider. As a result, many man-hours and research dollars are required to provide solutions for advanced milling projects.
This paper presents new applications for electric-wireline milling. First, a summary of the milling experience to date will be presented followed by the examination of some complex milling challenges through several unique case studies and verification tests. Value statements are also presented for each case study.