bluuebunny/crossref_metadata_2025_split huggingface dataset:
Well Control Considerations – Offshore Applications of Underbalanced Drilling Technology
Authors: Hannegan Don M. , Wanzer Glen 
Published: December 2007

Abstract
This paper focuses upon the well control aspects related to offshore applications of the tools and technology normally associated with underbalanced drilling systems (UBS). A discussion of the history of underbalanced drilling and the evolution of the specialized equipment required to practice the technology with a well established and commendable well control track record will help one recognize the potential benefits of offshore application. Whether onshore or offshore, a key component of UBS is a rotating diverter control head (RCH). As a key tool, the development of RCH's enabled the technology of onshore UBD and led the way towards encouraging the development of numerous other pieces of the UBS "tool chest". RCH's are fulfilling the same enabling role offshore, including leading the way towards numerous non-underbalanced drilling uses. Offshore applications of the tool include "onshore models" atop surface blowout prevention stacks (BOP's). Several "offshore variations" of the tool enable deepwater drilling (subsea BOP) with lightweight fluids, managed pressure drilling, dual gradient deepwater drilling, slim riser deepwater drilling with a surface BOP, and one subsea model facilitates controlling abnormally pressured aquifers and/or achieving zero discharge when riserless drilling top hole sections when establishing a subsea wellhead.
Barriers to achieving a true state of underbalance during an offshore well's drilling program include wellbore instability, dealing with produced hydrocarbons, and in some cases, regulatory restrictions. Offshore applications were the intent in using UBS was to drill ahead under a true state of underbalance now total around 100 wells. All but one has been drilled from rigs a surface BOP's. In deeper waters from floating rigs with subsea BOP's, the trend to drill underbalanced is expected to be more aggressive in the future given the large percentage of all known deepwater resources being economically undrillable otherwise.
In the nearer term, non-underbalanced drilling applications of the specialized equipment and technology associated with underbalanced drilling is much less of a step-change and avoids the aforementioned barriers to true underbalanced drilling offshore.
Therefore this discussion places emphasis upon the non-underbalanced drilling applications of the specialized equipment associated with underbalanced drilling and illustrates the well control considerations.
In the context of this paper, well control implications relate to the potential for surface events as well as underground blowouts.
Cuttings Transport with Foam in Horizontal & Highly-Inclined Wellbores
Authors: Ozbayoglu Evren M. , Miska Stefan Z. , Reed Troy , Takach Nicholas 
Published: December 2007

Abstract
Foams are of considerable interest for annular pressure management in many drilling applications. While foam rheology and hydraulics have been studied in the past, knowledge of cuttings transport with foam is very limited for vertical wells, and even less well understood for horizontal and inclined-well configurations. In this paper, cuttings transport with foam in horizontal and highly-inclined wells is analyzed.
Using the principles of mass and linear momentum conservation, a model consisting of three layers (motionless bed – observed in most experiments, moving foam-cuttings mixture and foam free of cuttings) is presented. The model includes seven independent equations and seven unknowns. A computer simulator was developed to solve simultaneously the system of equations for flow velocities, cuttings bed height, slip velocity, the in-situ concentration of flowing cuttings and pressure drop.
An extensive experimental program on cuttings transport was conducted using The University of Tulsa Drilling Research Projects' full-scale (8" by 4 ½") flow loop at 70° to 90° inclinations (from vertical). A broad range of annular velocities and cuttings injection rates was investigated using foam qualities of 70% to 90%. Results from the experiments are presented in the form of graphs showing the cuttings bed cross-sectional area and pressure losses vs. foam flow rate. In all experiments, the foam behaved as a pseudo-plastic fluid; foam qualities of 80% and 90% exhibited noticeable wall slip. At a given flow rate and rate of penetration, bed thickness increases with an increase in foam quality. There is little effect of inclination angles in the range of 70°–90°.
The experimental data were used to verify results from the simulator. The simulator is capable of estimating bed thickness and pressure drop with an error of less than 20% in most cases.
Reducing Development Cost in Forcados-Yokri Field with Application of Slim Well Technology
Authors: Erivwo O. E. , Okwa H. D. , Ideh M. A. , Aduba A. A. , Woodland D. C. 
Published: December 2007

Abstract
The plans for re-developing the mature Forcados-Yokri field in the shallow offshore area of the Niger Delta was conceptualized as an integrated project with a fixed and delegated budget for wells delivery. However, with the upbeat in global drilling activities, resulting from increase in oil price, rig rates for the jack up rig in use was increased by 100% and was set to jeopardize the project economics for the campaign. This implied the delivery of less wells than planned for the available budget, with the resultant effect on reserves developed in the field, and thus required something different to deliver step change reduction in well construction costs. Several innovations aimed at improving drilling performance such as cluster and batch drilling, conductor driving optimization e.t.c. were implemented in the face of a flattening learning curve as the drilling campaign progressed, the most significant being the adoption of slim well technology.
This paper presents the application of "slimline" wells in the Forcados Yokri Integrated Project (FYIP). It reviews the economic and technical justification for the phased implementation of the technology over the well clusters in the FYIP campaign beginning with a field trial (TXZK-4). It emphasizes on the planning, project management, concept selection, risk mitigation and critical engineering considerations applied to address the numerous concerns associated with a largely restricted contingency envelope from slimming down to a 7" surface casing and 4–1/2" completion liner in the horizontal section, the technical limit for telescoping well configurations.
The paper concludes with highlights from the execution phase – problems encountered, learning points and – and the resultant cost impact on the FYIP drilling campaign.
A Novel Approach to Access Trapped Reserves below Highly Depleted Reservoirs
Authors: Donaldson Sonja J. , van de Weijer Tony A. H. , Chesters Adrian P. , White Craig C. 
Published: December 2007

Abstract
In mature fields, hydrocarbons may become "trapped" below the main production zones. These overlying formations may be produced to a very low pressure, while the smaller trapped reserves may remain at virgin pressures or be slightly depleted. Drilling the depleted reservoirs requires a low mud weight to prevent losses and avoid either lower reservoir influx or shale collapse. Due to the often marginal size of the trapped reserves, reducing well costs is critical to project economics. One obvious solution is to deepen an existing producing well and commingle the production from the reservoirs, thus reducing cost when compared to a new dedicated well. Three novel technologies have been identified that, when combined, would allow wells to be deepened at low cost and without severe losses. These include through-tubing drilling, aphron-based drilling fluid, and real time ECD modelling.
This paper describes a project where these technologies were applied. Owing to the high-risk nature of the project and the need to protect existing production from the chosen well, in-depth planning and staged implementation of the new technologies were undertaken. A comprehensive risk management procedure was developed and careful testing and data gathering undertaken. The well was successfully executed within planned time. The authors will outline the theoretical and practical aspects of the technology selection criteria, risk management aspects, and how all these were combined to deliver a successful well.
Stacked Multilateral System for the Troll Olje Field – Development and Case History
Authors: Cuthbert Andy , Hegreberg Jofrid M. , Skoglund Elisabeth 
Published: December 2007

Abstract
In response to the need to drain more of the reservoir within the Troll Field, especially from low permeability mica-sands where production levels are low, the current dual lateral technology was advanced to include two lateral legs in addition to the mainbore by creating a stacked or trilateral system.
Based on a conventional multilateral ITBS™ (Isolated Tie-Back System), two 9 5/8-in. liner joints — incorporating pre-milled windows and pre-installed latch couplings — are installed a specific distance apart but aligned to the same orientation. After installation of the windows and subsequent installation of the mainbore screens, a whipstock is latched into the lower coupling and the lower window opened up to drill the first lateral leg. To complete this section of the well, the whipstock is retrieved, replaced by a deflector over which a flexible hanger with D-section legs is installed to create the junction. One leg is attached to the lateral screens whereas the other leg is connected to a seal stinger. The flexible hanger is oriented to enable the stinger to land in a seal stack in the deflector thereby creating the means of communication with the main bore. Drilling out and completion of the upper lateral is a duplication of the lower lateral with some exceptions.
This paper will discuss the factors leading to the development of the trilateral ITBS™, its installation and the impact on Troll Olje Field drainage.
The Twist and Shear of Helically Buckled Pipe
Authors: Mitchell Robert F. 
Published: December 2007

Abstract
The effect of torque on buckling was first recognized in the design of hollow propeller shafts for ships. If buckling could be caused by torque, then perhaps torque could be induced by helical buckling. This effect has not been extensively studied because the assumption has always been that the effect was too small to be of concern. This problem required an exact large-displacement solution to the helically buckled pipe, since conventional small displacement analysis has built-in the assumption that these effects are not important.
How significant are these effects? In Lubinski's paper on helical buckling, he works a sample problem of a squeeze cementing operation in 2–7/8" 6.5 ppf tubing. The induced torque due to helical buckling may exceed make-up torque (in the range of 600–2300 ft-lbs depending on grade) for large radial clearances, so induced torque in this problem may be high enough to break the connection!
This paper will give complete details for the torque and shear calculation in the appendix of this paper. The body of the paper will examine several typical tubing load situations to evaluate the effect of induced torque and shear on conventional design.
Performance Driven Drilling Tubular Technologies
Authors: Chandler R. Brett , Jellison Michael J. , Payne Michael L. , Shepard Jeff S. 
Published: December 2007

Abstract
New developments in drilling tubulars are rapidly evolving and represent enabling technologies for the industry's continued advancement of drilling deeper, longer reach wells more cost effectively. This paper presents key tubular technologies including metallurgical and manufacturing advancements that have enabled high strength, high toughness drill pipe. Application specific landing string designs that provide substantial advances versus conventional designs are presented and analyzed. Field performance of 5–7/8 in. drill pipe is also presented.
Subsea Accumulators – Are they a False Reliance?
Authors: Curtiss Jason P. , Buckley Margaret 
Published: December 2007

Abstract
In general, the offshore drilling industry has long accepted the concept that subsea accumulators are required for offshore BOP control systems in order to satisfy certain industry standards and regulations. However, the actual energy derived from subsea accumulators may fall short of the perceived benefits. Moreover, in some instances subsea accumulators may not be necessary, provided an appropriately sized rigid conduit line on the marine riser is utilized.
In the early days of offshore drilling, the industry relied solely on the energy stored in accumulators located subsea to, in part, speed the response times of the BOP. BOP control systems of this period typically utilized a one-inch inside diameter hose that transported hydraulic energy from the surface to the BOP stack functions subsea. The head loss due to friction from this relatively small hose over long distances was significant, resulting in BOP response times that were deemed too slow by the industry. As such, accumulators were mounted directly to the BOP stack to provide a shorter hydraulic conduit, thereby reducing head loss and response time. However, current research indicates that the benefit of these accumulators deteriorates rapidly with increasing water depths. Also, research suggests that utilizing a properly sized rigid conduit line to supply hydraulic energy to the BOP stack can provide acceptable control system response times without the use of subsea accumulators.
This paper analyzes the effects of water depth and other variables on the available energy in subsea accumulators. Also, it analyzes the available energy through BOP control system supply lines of various sizes. The paper concludes with recommendations on how to best maximize the required energy to operate subsea BOP stacks.
Results of the SPE Applied Technology Workshop ‘Off Well Site Decision Making’
Authors: Womer Keith , Kaminski Dean , Hansen Olav , Kirkman Matthew , Curry David 
Published: December 2007

Abstract
Communications technology has enabled drilling rigs to be connected in real time with off well site personnel. This powerful technology offers the opportunity for tremendous productivity and safety gains. However, if misapplied or abused, it could instead result in a disruption or breakdown of the rig's operational decision-making structure. The consequent loss of the sense of local ownership at the rig site could be disastrous in both a material and a human dimension.
This paper will present the results of an SPE Applied Technology Workshop held in April, 2002 designed to study these issues. At the workshop, real-world case studies and roundtable discussions were presented. Rather than just merely re-presenting the studies individually, this paper will also focus on presenting common themes arising from the studies, with references to specific cases as examples. Themes to be presented are: past history with this technology and lessons learned; the spectrum of off well site decision making implementations today – similarities, differences and critical success factors; people issues; the importance of data security and data standards; and the implications of this technology for health, safety and environmental issues.
Despite the diversity of the case studies, it is somewhat surprising that there were several common critical success factors identified by all participants to make the next generation of "off well site decision" implementations effective. The paper concludes by clearly identifying these factors and explaining why the overall outlook of the participants was decidedly optimistic.
Real Time Operations Centers; The People Aspects of Drilling Decision Making
Authors: Ursem Leendert-Jan , Williams Jevon H. , Pellerin Nicholas M. , Kaminski Dean H. 
Published: December 2007

Abstract
This paper will demonstrate how Shell and Halliburton-Sperry-Sun have implemented a world Class Real Time Operations Center (RTOC) using a holistic approach focused around people's needs while using the latest enabling technology. Although all the technology is available today to make the best decisions and to apply all the learning's of the past, the effectiveness of such a system is greatly linked to the behaviors of the people in the organization. Clearly addressing the people issues, is the largest step towards success for operational excellence, including safety. This paper will address five areas where people issues were taken into account.
Nakhchivan Drilling - Operational Success in a Challenging Environment
Authors: Jorden J. D. , Sandlin C. W. 
Published: December 2007

Abstract
Drilling in the Azerbaijan sector of Caspian Sea is very challenging and numerous drilling hazards must be overcome to successfully evaluate all exploration objectives. These challenges include numerous shallow hazards, complex pressure regimes, low fracture gradient, highly charged shallow water sands, reservoir sands that exhibit a pressure regression and the need to drill very deep to evaluate the geologic objectives.
A comprehensive well plan was developed to address these drilling challenges and hazards. The well plan had to address a rapidly increasing pore pressure relative to the fracture gradient and had to honor the resultant narrow drilling mud weight window. The plan called for setting 7 casing strings to allow drilling to the target depth. The plan also incorporated the first use of a "Big Bore" subsea wellhead system in the Caspian to accommodate these multiple casing strings.
The Nakhchivan #1 well was safely drilled to an Azerbaijan offshore depth record of 6746 m in 185 days. All exploration objectives were extensively evaluated and the well abandoned. Non-productive time was minimized though flawless execution of the well plan.
This paper will describe potential surface and subsurface hazards in the region, the well plan that was developed to mitigate these hazards and summarize the operations that led to the drilling successes.
Drilling Environmentally Friendly Satellite Field Wells in the Tundra of the Timan Pechora Region of Russia
Authors: Kukhtyak Zinovy , Perovsky Alexander , Sekerenova Svetlana 
Published: December 2007

Abstract
Polar Lights Company, a limited liability company formed by Conoco and Arkhangelskgeologia in January 1992 (later joined by "Rosneft"), stands out among petroleum ventures involving western companies in Russia today. Its Ardalin field development project in the Russian north, which produced first oil in August 1994, represents the single largest investment from the West in Russia's petroleum industry. The Polar Lights' license area is located in the Nenets Autonomous Area in the Timan Pechora region, about 125 kilometers south of the Barents Sea, above the Arctic Circle and west of the Ural Mountains.
Ardalin's complex consists of the main Ardalin field and 3 satellite fields. In 1997 the Company decided to commence satellite field development, utilizing an upgraded Russian drilling rig (Uralmash 3D-86) to meet the goal. The task was set forth to modularize the drilling rig such that the rig could be mobilized, the satellite well drilled and completed and the rig demobilized back to the Ardalin facility in one winter season, utilizing only ice pads with a minimum footprint and meeting all environmental requirements. By meeting this requirement (the elimination of gravel pads and their associated cost) the cost to mobilize and demobilize could be reduced and the environmental impact could be minimized such that following the spring thaw, the tundra's surface would be left undisturbed.
The modular, upgraded Russian drilling rig can be skidded from site to site (between the fields, up to 30 kilometers) and rigged up, the wells drilled and completed and the rig demobilized back to Ardalin in one winter season.
At the present time, the Polar Lights Company has drilled four satellite wells from ice pads in one winter season leaving the tundra's surface undisturbed and at a substatial cost benefit to the company.
Real-Time BHA Bending Information Reduces Risk when Drilling Hard Interbedded Formations
Authors: Hood J. , Hovden J. , Heisig G. , Ernesti K. D. , Knipper A. 
Published: December 2007

Abstract
Exploiting the Troll reservoir in the Norwegian North Sea requires horizontal drilling through relatively loose sandstone and local hard calcite-cemented zones. Depending on the orientation of the calcite interval, and the drilling parameters when entering or exiting the calcite interval, the bit can be forced aside to create a potentially severe local dogleg. High local doglegs introduce significant stresses into the drilling system that can rapidly accelerate fatigue of the BHA components and connections. Until recently, the driller could only identify local doglegs in the vertical plane when a rapid change of a near-bit inclination measurement was reported to the surface. No means were available for detecting azimuthal doglegs in the horizontal plane.
A new downhole dynamics tool, positioned above the rotary steerable system, is capable of measuring the bending moments in the BHA generated by side forces at the bit. If transmitted to the surface while drilling, the BHA bending information allows early detection and quantification of local doglegs independent of their orientation.
The paper explains the details of the bending moment measurement and the bending response of the BHA to local doglegs. Several field examples demonstrate the sensitivity of the measurement and the remedial actions initiated in response to the downhole BHA bending information. In one case drilling was stopped earlier than planned due to the detection of an extremely severe local dogleg, and a potentially catastrophic failure close to TD was avoided.
Application of Amphoteric Cellulose Ethers in Drilling Fluids
Authors: Warren Brent , van der Horst Peter , Stewart Wayne 
Published: December 2007

Abstract
Anionically charged cellulosic ethers have been used for many years in water-based drilling fluids. While the anionic charge imparts a benefit in the filter-cake properties of bentonite containing drilling fluids, this same charge deflocculates (thins) the viscosifying ability of this same bentonite. As a result, additional bentonite is often required in the drilling fluid to maintain an adequate rheological profile. Also, it is well known that cations are viscosity enhancers to bentonite drilling fluids by virtue of the flocculation effect of the cation. This has been used for many years in the potassium chloride (and similar salts) based drilling fluids.
Amphoteric Cellulose Ethers represent a new class of drilling fluid additives which combine an anionic and cationic charge onto the same cellulose backbone. The result is a drilling fluid additive having both desirable filter-cake enhancement and partial flocculation properties. Discussion will include the effects of degree of substitution for the anionic and cationic species, as well as the influence of molecular weight on the properties of the Amphoteric Cellulose Ethers.