bluuebunny/crossref_metadata_2025_split huggingface dataset:
Tar Sands Drilling Waste Management: A Clean Solution
Authors: Nilsen C. , McCosh K. , Kapila M. 
Published: March 2008

Abstract
Tar sands are a combination of sand, clay, water and bitumen. In-situ techniques using steam and/or solvents are used to reduce the bitumen viscosity such that it can be recovered and refined into petroleum products. Steam-assisted gravity drainage (SAGD) is an increasingly common technique which involves drilling two horizontal wells into the tar sand deposits. Steam and hot water are injected into the upper well to reduce the viscosity of the bitumen, which will drain into the lower well where it can be pumped to the surface. The waste generated from drilling these wells is extracted from the drilling fluid by shakers and includes sand contaminated with bitumen and drilling fluid. Treatment of this waste stream is challenging and typically these sands are stored at the rig site or transported for disposal at centralized sites.
This paper presents novel technology for treatment of the tar sands drilling waste generated from SAGD and other tar sands drilling operations. The continuous treatment process is based on hot water addition, mixing and separation techniques to reduce the viscosity and specific gravity of the bitumen to separate it from the sand. Treatment of cuttings with light to heavy bitumen contamination and varying quantities of fine sand and clay particles has shown this treatment method to be a simple and effective means of producing clean sand and recovering the bitumen component. The energy used to heat the circulating water is recycled to minimize waste and maximize energy efficiency. The cleaned sand can be blended with natural soil and safely disposed in the environment. The recovered bitumen can be used as feedstock for further processing and refining.
With the total recoverable tar sand reserves in Canada and Venezuela estimated at 300 billion barrels, the market demand for this technology is potentially immense. Effective treatment of the tar sands cuttings will convert the waste into a valuable revenue stream in an environmentally responsible manner.
Torque and Drag Software Analysis for Deciding Well Construction and Remedial Action
Authors: Roychoudhuri Biplab , ramagopal Boddupalli 
Published: March 2008

Abstract
In assam in India sidetrack well was decided to do horizontally after side tracking in l profile and after 90horizontal section. Original well was S profile in casing above. Well was decided for construction it was observed after torque and drag analysis that s profile l profile and horizontal section creates more surface torque. Surface torque generation was more and well was not taken for horizontal well and was converted to high angle well.
In another case well was taken up for ultrashot radius and top section of casing was S profile and only vertical wells were taken for ultrashot wells .s profile and horizontal section it was measured from out put of software generates almost double the torque.
Torque generated prognosis is a indication of wells not to be taken for drilling and well configuration was changed many viable software is available. Friction and drag is dependent on many factors like mud type well angle well profile, type of assembly used. Software modeling of well provides accurate prediction of performance and feasibility of wells. Depending on software calculation new well construction can be designed and can be altered.
Above two case study outline prevented operator from doing horizontal well and ultrashot well. Similarly many output calculation can be done like failure in tension in compression and rotational in different set of drilling condition and preventive measure may be taken for unfavourable condition.

INTRODUCTION
Well design can predict in planning stage the surface torque, failing from tension, buckling from compression failing from rotational torque. A different well plan alternatively can be devised.S profile on the top of well and below L profile and to 90 landing point. Well path was generated and modeling was done using torque and drag soft ware, it was observed that static torque of horizontal well was much greater than the static torque in high angle well.
Considering well development and field development to achieve maximum production horizontal well is to be done but because of increase in risk and uncertainity and higher torque was in well planning stage was predicted. by software Well engineer can use this tool for successful drilling strategy. If the modeling insists that there is a critical problem then well engineer can alter the design acording to suitability of the well
SOLUTION - Torque and drag modeling is the solution of this problem. By input of various factors like directional plan, drill string data, cased hole data, open hole data it is possible to predict of lowering of tubulars and consequence and different drilling operation scenarios is achieved.
DRILLING SOFTWARE -Drilling software includes tubular data. Pipe OD/ID, pipe density, young modulus tensional yield, torsional yield, weight per ft tensile strength and torsional data is key input
Directional profile of the well is measured depth, inclination, azimuth.
Output calculation are done under different set of condition
Reducing Risk by Using a Unique Oil-Based Drilling Fluid for an Offshore Casing Directional Drilling Operation
Authors: James Reagan , Randeberg Øystein 
Published: March 2008

Abstract
The conventional drilling approach of employing a drillstring and bottomhole assembly with bit for drilling purposes and eventually running a casing string includes several tripping operations that leave the wellbore open for extended periods of time as an alternative to drilling-with-casing operations where the bottomhole assembly is attached to the casing. This eliminates additional drillstring tripping as drilling and running casing are performed simultaneously. This type of application reduces the number of string trips needed to complete a section, thus saving operational time and associated costs. As the diameter of a casing is larger than a drillstring, this method generally increases the Equivalent Circulating Density (ECD) as pressure losses increase owing to the reduction of the open hole and casing string annulus area. Casing directional drilling operations provide a much narrower drilling window with regards to restrictions in the annulus thus increasing the chances of reaching fracture pressure compared with conventional drillstring operations. To negate the resultant increase in ECD, the rheological profile of the drilling fluid must be designed appropriately.
This paper discusses a unique oil-based drilling fluid system weighted with treated micronized barite slurry (TMBS) that has more recently been developed and used successfully in the Eldfisk field of the Greater Ekofisk area, Norway. The drilling fluid system provides low viscosity and a relatively low flat rheology, reduced torque values, and superior sag stability, thus delivering a fluid of low ECD contribution, low-pressure peaks, very effective hydraulics performance and static stability. These exceptional fluid characteristics make the system an excellent solution for drilling sections where the difference between pore pressure and fracture pressure is narrow. This was particularly so in this case where the stability of the fluid from sag potential was crucial for the improved success of the drilling-with-casing operation. Any solids sag onto the latching tools or bottomhole assembly (BHA) with the casing could have caused interference.
The system had been used before for differing hole conditions including managed-pressure drilling and extended-reach wells, in high-temperature, high-pressure (HTHP) wells, and now with competence in a casing directional drilling operation.
Annular Pressure Loss Predictions for Various Stand-off Devices
Authors: Yao Dongping , Robello Samuel G. 
Published: March 2008

Abstract
During drilling and cementing operations, many stand-off devices, such as centralizers, stabilizers, reamers, turbulators, cutting bed impellers, and friction reduction devices are widely used. Some of these devices are designed to enhance the displacement efficiency during cementing operations, to increase hole cleaning efficiency, or to reduce torque and drag during drilling operations. The hydraulics program for the deep and especially ultra deep wells constitutes a significant portion of the well planning. Challenges associated with extreme depth and different types of downhole tools used in the drillstring translate to additional problems to the well design. Few studies have explored the pressure losses arising from these attached devices in the drillstring or casing string, and the pressure losses caused by them are assumed either negligible or ignored. The geometrical designs of these devices are relatively irregular and complicated, which is one of the major difficulties for pressure loss calculations. Non-Newtonian drilling fluids further complicate the problem. A study is necessary to determine the impacts of these devices on the pressure loss calculations and thereby the effects on downhole circulating density. These devices alter the flow stream and especially the angular bladed type cause the flow to swirl. This flow is complex, which underpins the effects of the pressure drop calculation across these devices. The paper describes a method and equations to calculate the pressure losses due to the stand-off devices.
Casing Drilling in the San Juan Basin to Eliminate Lost Returns in a Depleted Coal Formation
Authors: Robinson Shon D. , Bealessio Tom M. , Shafer Randall S. 
Published: March 2008

Abstract
A casing drilling pilot program was conducted in the San Juan basin to determine if lost returns could be eliminated in a depleted coal formation. The pilot program proved that casing drilling can mitigate lost returns drilling through the coal and can be made economic in a low cost environment.
The reduction in the amount of fluid lost should result in less damage to offset producing coal wells, resulting in higher ultimate recoveries. Development costs may also be reduced, by replacing directional wells drilled to avoid lost return zones, with lower cost vertical wells.
A total of six wells were drilled with non-retrievable casing drilling bits. Two wells were drilled using a casing drilling bit on drillpipe (DP). Based on the bit performance four other wells were drilled with casing. Three wells drilled through the coal and had losses that were eliminated with casing drilling. One well experienced a bit failure and did not drill into the coal.
The pilot program was completed with significant learnings. Losses were healed in the coal. A non-retrievable casing drilling system successfully drilled to the intermediate casing point without a trip. The bit design was changed significantly and resulted in 54% improvement in drill rate with instantaneous rates of penetration (ROP) similar to traditional polycrystalline diamond compact (PDC) bits.
The initial casing design was modified to decrease vibration, and eliminate fatigue after a failure was experienced. The casing drilling bit was successfully drilled out with an air hammer and hammer bit. Other tools and techniques applied during the pilot program included cement stage tools, foam cement, and aerated fluids to reduce the equivalent circulating density (ECD) and to improve ROP.
A Case History of Casing Directional Drilling in the Norwegian Sector of the North Sea
Authors: Bourassa Kevin , Husby Tove , Watts Rick , Oveson Dale , Warren Tommy , Bjoerneli Hans Magnus , Lesso Bill , Sunde Frode 
Published: March 2008

Abstract
In January 2007, ConocoPhillips completed what is believed to be the first well directionally drilled with casing using wireline retrievable bottom hole assemblies from an offshore installation. ConocoPhillips has considerable experience with this technology in reducing drilling days on predominately vertical land wells in South Texas. It was desired to determine if the same benefit could be realized in the offshore environment; where directional drilling is required. A candidate development well was identified in Norway on the ConocoPhillips operated Eldfisk Bravo platform that could benefit from advantages seen with Casing while Drilling. Two land based tests were conducted to confirm the ability to conduct casing directional drilling in wells similar to those expected in Norway. Simultaneously, a detailed plan for drilling the well in Norway was developed.
Two production casing strings (10 ¾-in. and 7 ¾-in.) were successfully drilled directionally through the overburden section on the Eldfisk well. The well had a complex 3-dimensional well path with inclination up to 60°. All running and retrievals of the BHAs was planned to be done with wireline and a purpose-built traction winch system rated to a working load of 40,000 lbs. Once the 7 ¾-in. production casing was cemented, the casing string was converted to a production liner with an expandable liner hanger and the upper section of 7 ¾-in. was retrieved. In all, 10,968 ft of the 13,600 ft well was directionally drilled with casing.
Development, Testing, and Field Deployment of a Hydraulically Expanded Solid Liner Hanger in a Casing Directionally Drilled Well in Norway
Authors: Bourassa Kevin , Husby Tove , Watts Rick , Hazel Paul , Nussbaum Chris , Wood Peter 
Published: March 2008

Abstract
When ConocoPhillips (COP) decided to conduct Casing Directional Drilling (CDD) operations from a platform in the Norwegian Sector of the North Sea, the well design required that the drilled in 7-3/4" production casing string be converted into a liner prior to completing the well. There was a challenge in identifying a liner hanger system that would be suitable for CDD operations; that did not require a running tool; would maintain a full internal diameter (ID) for running and retrieving bottom hole assemblies (BHA's) and would act as a barrier against gas migration over the service life of the well.
Expandable technology(1) was identified as a potential solution. Once a service provider was identified, a basis of design was established and testing began. The end result after eighteen (18) months of work was a successful field deployment of a 7-3/4" liner hanger that was drilled in from surface; successfully expanded into 10-3/4" casing; had a load capability of over 440,000 lbs (200 metric tons or MT) and a 5,000 psi (345 bar) gas tight seal qualified to ISO 14310:V0.
This paper will describe the development, testing and actual deployment that took place between December 2006 and January 2007.
Automated Real-Time Hookload and Torque Monitoring
Authors: Kucs Richard , Spörker Hermann F. , Thonhauser Gerhard , Zoellner Philipp 
Published: March 2008

Abstract
Today important parameters to enable a reduction of lost and hidden lost time during drilling, like hook loads for pulling and slacking off the drill string, and torque for drill string rotation, are still taken manually. Analysing torque trends during drilling and reaming is hardly done.
A key to reduce lost and hidden lost time by analysing drilling data is to automatically recognize ongoing operations in real time from this data. That allows the automatic identification and picking of pulling-up; slacking-off and rotating hook loads, as well as torque values without spending extra time or work force. Relevant parameters can be sampled and analysed automatically in real time from the rig sensor data stream without interfering drilling operations.
This automated process allows monitoring changing torque and drag trends for each stand of drill string moved during drilling, tripping, or reaming operations. To monitor trends in the torque and drag development in real time, parameters may be combined with simulated hook load and torque curves in a graphical way. Simulated values are imported from engineering applications. This allows the user to react immediately, not only after hand taken values are manually entered into a graph. The possibility to broadcast all the data to computers worldwide enables a great level of cooperation.
Instant measures against increasing torque and drag can be taken before reaching critical ranges on a stand per stand basis. Also excessive reaming and washing can be avoided as low torque and drag may be an indication for a good hole quality. This can save wellbore treatment time.
The paper presents the development of the system, its validation against live well data from recent 20,000ft wells in the Vienna basin and the planned application of the system on an extended reach field development project offshore New Zealand.
Installing 56 Surface Casing Strings in 40 Well Slots Successfully in Bohai Bay, China
Authors: Fu Frank , Actis Stephen C. , Strachan Kevin 
Published: March 2008

Abstract
ConocoPhillips is developing the Peng Lai field in Bohai Bay offshore China with six wellhead platforms (WHP) in 28 m (92 ft) of water. Phase I entailed one 24 slot WHP and a leased FPSO that has been in production since 2002. Phase II will have five 40 slot WHP's and a permanent FPSO. Phase II production began in 2007. The 24 inner slots of four of the Phase II WHP's will have 20″ drive pipe conductors and the 13 3/8″ surface casing will be installed by drilling with casing. The 16 outer slots, 8 on the north row and 8 on the south row, will have 36″ drive pipe conductors and provide dual bore 13 3/8″ surface casing strings in each slot. These holes will be directionally drilled at a slight angle to facilitate subsequent directional drilling. The 56 wells drilled from a 40 slot WHP reduces the size and cost of the platform while providing additional wells to meet the reservoir development plan.
A portion of the wells will be "pre-drilled" from a jack-up through the WHP jacket while the topsides are under construction. The 13 3/8″ surface casing strings, using both the drill with casing and dual bore methods, are installed during batch setting programs. The jack-up pre-drills wells below surface casing until the topsides installation begins, at which time the jack-up moves to the next platform and repeats the process. After the topsides are installed on the WHP, a self contained platform rig continues the drilling and completion program. The drilling program on the last WHP, to be installed in 2009, will be conducted exclusively from a platform rig, including the 13 3/8″ drill with casing program in all 40 slots.
This paper will describe the well construction program as part of the field development plan, the installation procedures, results of the surface casing installation programs and the drilling cost savings realized as a result of using drill with casing and dual bore conductor technologies.
Drillstring Solutions Improve the Torque-Drag Model
Authors: Mitchell Robert F 
Published: March 2008

Abstract
The only standard drillstring model in use today is the torque-drag model, and because of the simplicity and general availability of this model, it has been used extensively for planning and in the field. Field experience indicates that this model generally gives good results for many wells, but sometimes performs poorly.
In the standard torque-drag model, the drillstring shape is taken as the wellbore shape. Considering that surveys are taken within the drillstring, this is an excellent assumption. However, given that the most common method for determining the wellbore shape is the minimum curvature method, the wellbore shape is less than ideal, because the bending moment is not smooth at survey points. This defect is dealt with by neglecting bending moment, but as a result of this assumption some of the contact force will also be neglected.
If the wellbore shape is the drillstring shape, why not use analytic drillstring solutions to model the wellbore trajectory? Before these solutions can properly interpolate the survey data, they require some modification. This paper shows how this can be done in a simple and efficient way, so that little of the calculation speed of the conventional model is lost. With this new wellbore model, the simple torque-drag model becomes a full stiff-string formulation.
The paper gives a complete description of the wellbore trajectory calculation, including tests of circular, helical, and catenary trajectories to verify the accuracy of the formulation. Several example problems with different inclinations and wellbore curvatures are studied to compare the two torque-drag formulations. These studies give comparisons in execution time, drag forces, and torques for the two models, and for the new formulation, the magnitude of the bending moments.
Optimized Deepwater Cement Design for Record-Length Expandable Liner
Authors: Schultz Don , Pollard Greg , Fuller George , Langlinais Joey , Serio Michael , Bradley Jasen 
Published: March 2008

Abstract
During a sidetrack operation out of 9 7/8-in. casing on a deepwater well in Green Canyon Block 243, Gulf of Mexico, unexpected hole conditions were encountered that required the use of an additional casing string. The decision was made to run a 7 5/8 x 9 5/8-in. expandable liner in the 8 1/2 x 9 1/2-in. wellbore. The liner would expand to provide an inside diameter of 7.71 in., allowing space for a 7-in. production liner in the targeted interval.
The 6,867-ft liner (pre-expansion length) is currently the world record for the longest expandable liner set to date and presented several challenges for cement job design. The liner would be cemented conventionally before the expansion operation. Expansion time was calculated to be approximately 17 hours, allowing the fluid time for the primary lead cement, with a safety factor, to exceed 19 hours. The tail cement had to exhibit good compressive strength around the shoe track, and the operator specified top of cement (TOC) at 17,000 ft to protect a secondary pay zone. Slurry properties were simulated to meet fluid times required for the liner expansion. Standard API lab tests used for cement testing were modified to accommodate this lengthy operation.
The expandable liner was set at 20,605 ft measured depth (MD) and 19,930 ft true vertical depth (TVD) with a maximum hole angle of 36°. The liner was cemented successfully using an extended thickening-time lead slurry mixed at 15.7 lb/gal, followed by a 16.2-lb/gal tail slurry with a shorter pumping time to achieve good strength at the liner shoe.
After drilling out the liner, the operator obtained a 16.8-lb/gal equivalent (PPGE) formation integrity test (FIT) and resumed drilling to the target depth. The cement-evaluation log showed excellent bonding behind the expandable liner with TOC at 17,000 ft as planned. Operational details and cement design considerations are provided in the paper. Emphasis is placed on wellbore configuration, expandable installation procedures, and hole preparation, a full understanding of which is the beginning of a successful cement job.