bluuebunny/crossref_metadata_2025_split huggingface dataset:
Simulations Comparing Different Initial Responses to Kicks Taken During Managed Pressure Drilling
Authors: Das Asis K. , Smith John Rogers , Frink Philip J. 
Published: March 2008

Abstract
An industry-supported research project to investigate a practical basis for comprehensive well control procedures for managed pressure drilling (MPD) operations is in progress. This paper will describe the results of a simulation-based study comparing alternative initial responses to a range of kick scenarios. The primary responses considered were increasing casing pressure while continuing circulation, increasing the circulating rate without increasing casing pressure, and shutting in the well conventionally. These were investigated using a transient, multi-phase flow simulator. The purpose of the study was to provide a basis for determining the most effective initial response for controlling a kick taken during MPD.
The results have helped to identify several important considerations. One important consideration was expected: the ability to minimize casing pressure and therefore the risk of lost returns by continuing to circulate rather than shutting in. There are significant complications if lost returns occur. Loss of returns is difficult to detect in a shut in well if a float is used. With an initial response based on increasing casing pressure until flow out is equal to flow in, it can be difficult to determine whether formation influx has stopped or partial lost returns are offsetting the influx. In cases with narrow margins between pore and fracture pressure, small differences in the drillpipe pressure being held constant during circulation with lost returns can potentially cause results ranging from total lost returns to uncontrolled flow at the surface. The location of the loss zone relative to the kick zone is particularly important in influencing these results. The need for a practical method of identifying lost returns during the initial response is evident, especially when working in a narrow window between formation and fracture pressure gradients. Simulation results are used to exemplify these considerations.
A tentative result of this on-going study is that there may be no single best initial response to a kick taken during MPD. The best response may depend on well geometry, kick zone productivity, and likelihood of lost returns.
Quick Intervention: Going Lighter and Running Faster with Gastight Rotary Shouldered Connection!
Authors: Griffin R. C. , Plessis G. , Chin D. 
Published: March 2008

Abstract
This paper presents the development of an intervention riser that incorporates a modified second-generation rotary-shoulder connection (RSC). This double-shouldered connection features a high-pressure, gas-tight metal-to-metal radial seal, a secondary back-up resilient sealing barrier and additional modifications to cope with subsea conditions. The comprehensive effort to design, test and qualify the intervention riser for operation in offshore Australia is detailed. Results from extensive finite-element analysis, laboratory tests, manufacturing processes and field results are presented.
Subsea completions and the need for subsequent interventions have dramatically increased in number since the first subsea trees were installed in the 1960s. Intervention on subsea wells requires the deployment of intervention riser systems. Previously, bolted-flange drilling risers were used for most interventions. This resulted in limitations and in most cases was overkill. Drilling risers are heavy pieces of equipment that require special handling equipment as well as taking extensive time to be assembled and deployed. The increased deck load also requires larger workover vessels.
The process of this 15-month project was the design, testing, manufacture and deployment of the project-specific, performance validated, RSC intervention riser system. The riser was successfully placed in service and utilized in the Enfield oil and gas wells offshore Australia.
The use of a lighter, faster and more user-friendly intervention riser system based on RSC technology will reduce time and operational costs while meeting the intervention needs. The gas-tight, metal-to-metal seal RSC is robust, easily handled and incorporates familiar drill pipe handling and running equipment.
Novel Stabilizers for Casing Drilling Simplify BHA, Handling, and Cost
Authors: Limbert David , Langford Steve , Prideco Grant , Gammage John 
Published: March 2008

Abstract
A novel technique for building stabilizers and wear bands directly onto casing for drilling is replacing multiple machined integral stabilizers. This is achieved with spray metal technology and the resulting blades, ribs and bands are at least as wear resistant as steel. Multiple stabilizers can be built onto a single joint of Range 3 casing to create the desired BHA.
The spray metal process is commonly used in other industries for corrosion and erosion protection using relatively thin layers. The novelty of this new process is that the wear metal can be built up, typically, to thicknesses of ¾" (19 mm) and in any desired shape. This is a new use of the spray metal process for casing drilling because it has already proved successful in protecting drill pipe tube from wear in Extended Reach wells and in highly abrasive formations.
Laboratory and field test results indicate that the material is sufficiently robust to withstand normally anticipated downhole drilling forces and the open hole wear resistance testing indicates that it will deliver very satisfactory rotational and longitudinal resistance to abrasion. In one well drilled with casing the casing string was deliberately tripped at TD to inspect stabilizer integrity and to measure wear. Further laboratory work has been undertaken to compare the material's wear and frictional characteristics with plain tooljoint steel and some more commonly used wear resistant materials.
Casing drilling hundreds of wells per year will benefit significantly from the economies of scale which this new process offers. A single joint of Range 3 casing with the necessary stabilizers formed directly upon it is utilized instead of multiple short integral blade stabilizers (IBS) and casing pup joints. Rig time and HSE exposure is reduced through simplifying the BHA and its associated make up procedure. The spray metal stabilizers also provide operators with a significant cost reduction from traditional IBSs.
Design and Qualification of Critical Landing String Assemblies for Deepwater Wells
Authors: Cantrell Andre John , Beiriger Christine Noel , Hubbard Brad Lee , Everage DeWayne 
Published: March 2008

Abstract
Qualification of landing strings has become a major concern for oil industry operators as longer and heavier casing, tie-back or liner sections are required in deepwater and ultra-deepwater wells. Total buoyed weights are currently approaching two million pounds, making it imperative that every component in the landing string assembly is properly qualified.
Any process which qualifies a landing string assembly must be multi-faceted, consisting of both design verification and a subsequent "fit for purpose" inspection. Experience has proven this approach is absolutely necessary to confirm all design assumptions hold true. Over the past six years, a systematic, field-proven, and reliable qualification process has been developed which has allowed operators to successfully land assemblies with buoyed weights up to 1.6 million pounds in water depths from 2,850 feet to almost 9,000 feet on semi-submersible rigs and drillships.
This process addresses critical design considerations such as verification of specialty tool ratings, the effect of makeup torque on connection capacity, appropriate usage of existing slip crushing calculation methods, heave-induced dynamic loading, and minimizing the probability of plugs becoming lodged in the assembly. Inspection issues addressed include coverage and scheduling, traceability to ensure accurate material properties are used in all design calculations, full-length ultrasonic testing of the drill string, and proper inspection of components which are routinely inspected incorrectly.
This paper details the most relevant aspects of this field-proven process, and reviews the implementation of this process by an operator for use on a broad range of casing and liner landing operations. The paper provides a concise summary of the approach that will allow the reader to confidently design for ever heavier loads while preventing costly (yet avoidable) failures during landing operations.

Introduction
Qualification of any landing string assembly requires the following steps be taken for each component:The design of the component is verified to have sufficient capacity for the anticipated loads. This can be accomplished either via classical engineering analyses, load testing of design prototypes, or a properly conducted finite element analysis (FEA).Material properties must meet the specified minimums used in all design calculations. Of primary concern for a landing string component is yield strength, but ductility and impact toughness are also critical for components with stress concentrators.The component must be properly inspected to ensure that prior service has not rendered it unfit for use in the given landing operation, and that all critical dimensions match those used when the component's capacity was verified.When deployed, the tool must be properly assembled within the landing string assembly.
Surface BOP System for Subsea Development Offshore Brazil in 1,900 m of Water
Authors: Tarr B. A. , Taklo T. , Hudson A. , Olijnik L. A. , Shu H. , Greff R. 
Published: March 2008

Abstract
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: Site specific pre-laid polyester taut-leg mooring systemSlim-bore wellhead system (to land production casing hanger)Purpose built 16" OD high pressure riser system (to replace casing riser)Added pressure test hose line, strapped to riser (to pressure test tubing hanger & packer)Replaced lower shear ram in SID with fixed 7-5/8" pipe ram (to seal on ported slick joint)Added power and hydraulic lines in SID umbilical (to reduced ROV support needed)Vertical subsea tree, Tubing Head Spool and slim bore tubing hanger with hydraulic running tool
Development drilling operations with this surface BOP system are now expected to commence in the first quarter of 2008.
Dipole Radial Profiling and Geomechanics for Near Wellbore Alteration Detection to Improve Productivity in a Matured Field
Authors: Subbiah Surej , Wielemaker E , Joia P , Hopper L , Fernandez LI , Kongslien M , Edwards N 
Published: March 2008

Abstract
Cartojani is a mature oil field with depleted reservoir pressure, supported by an aquifer in the deeper Cretaceous horizon. The Cartojani structure is located in the central alignment of the Moesic Platform. It is a monocline with large dimensions and low layer inclinations. The main hydrocarbon accumulation is found in the Sarmatian formation (Base Cretaceous Paleorelif) at the depth of 1100 to 1150 m. Currently the main productive horizons are sands from the lower Sarmatian (Basal Sarmatian). The facies variation can be seen both vertically and horizontally on a well-to-well basis even though the wells are very closely spaced. Sands have different oil retainer capacity and flow from clean to dirtier sands. The lower most units comprise of unconsolidated sands that are thinly distributed. These unconsolidated sands are normally completed using cased hole gravel pack. In order to select optimal completions, it required both identification and estimation of the radial extent of the nearwellbore mechanical alteration that might cause near-wellbore permeability impairment. The near-wellbore alteration, characterized by radial profiling of formation shear, can be correlated with the skin effect and reservoir productivity index. Due to the nature of the formation, formation damage is expected to be one of the main challenges to counter the observed decreasing production. A new dimension has been added to sonic measurements, providing measurements in several dimensions: axial, radial, azimuthal. The radial measurements provide now the opportunity to determine whether the near wellbore experienced any alteration. The sonic data was processed to extract a very reliable compressional, shear and Stoneley. Dispersion analysis confirmed the presence of alteration to the formation. Dipole radial profiling then demonstrated that in fact a 5 inch altered zone was present in the unconsolidated sands. Using the sonic data, mechanical properties and stresses were calculated. The unconfined compressive strength (approximately 200 to 300 psi) values demonstrated that in fact it concerned very unconsolidated sand. Using the mechanical properties together with the possibilities for perforation design, detailed analysis was performed. The analysis showed that the traditional gun selection would not surpass the skin and that in fact if would require deep penetrating charges with big hole (to minimize sand production). A proper gun system was selected based on the analysis. To improve the wells productivity, deeper penetration and high shot density guns were selected as a perforating method, to pass the radial extent of near - well bore mechanical alteration. After perforation, the production test showed a 3-fold increment in production compared to the previous best producers in the field. The skin estimation based on the model compared very well to the measured values during production tests.
Evaluation and Optimization of Low-Density Cement: Laboratory Studies and Field Applications
Authors: Al-Yami A. S. , Nasr-El-Din H. A. , Al-Arfaj M. K. , Al-Saleh S. H. , Al-Humaidi A. S. , Al-Shuker N. A. 
Published: March 2008

Abstract
Cementing a string in one stage is a challenging task, especially in the presence of weak formations. Cement slurry losses during placement is highly possible if the equivalent circulating density (ECD) exceeds 82 pcf during placement. A conventional method to overcome this challenge is to use multi-stage cementing by setting the stage tool above the loss circulation zone. However, field data indicate that the tool can fail, thus causing serious delay and economic loss. In addition, stage tools are considered weak point and not good for long term seal. A second method for zonal isolation is to use low density cement. In this study, we considered cementing the intermediate and production casings in S-1 (sandstone) and S-2 (carbonate) shallow formations and BJD (dolomite) deep formation in a single stage using lower density cement based on hollow microspheres at 70 pcf. The shallow conditions simulated in the lab tests were 150 °F curing temperature, 2,400 psi conditioning pressure and 1,800 psi confining pressure for 3 months. The deep conditions were 260 °F curing temperature, 5,000 psi conditioning pressure and 3,000 psi confining pressure; also for 3 months.
Hollow microspheres cement was used in oil and gas wells without encountering any operational problems. However, the high cost of microspheres cement was a limitation for potential field applications. In this study, we present extensive lab work to optimize hollow microspheres low density cement (LDC) by elimination of micro fine cement from the blend. Experimental studies (shrinkage, compressive strength, porosity, gas and brine permeability, and chemical analysis cement) were conducted to determine the effect of this optimization on the properties of cement. The testing was performed in Saudi Aramco facilities to reduce the cost of hollow microspheres systems.
Data generated during three months supported the use of the optimized system to cement casings at the shallow conditions tested. The removal of micro fine cement did not reduce the compressive strength with an average of 2,013psi; neither shrinkage nor liquid permeability was observed during the three months of testing. The use of the optimized system will help to bring cement to surface in one stage. The optimized blend price is 40% less than conventional hollow microspheres low density cement.
This paper will discuss case histories that include job design, execution, and evaluation of the LDC. Field treatments were conducted without encountering any operational problems. The treatment was successful and maintained isolation for more than three years.
Design of an ASP Pilot for the Mangala Field: Laboratory Evaluations and Simulation Studies
Authors: Pandey Amitabh , Beliveau Dennis , Corbishley Douglas W. , Kumar M Suresh 
Published: March 2008

AbstractMangala is the largest discovered oil field in the Barmer Basin of Rajasthan, India having a STOIIP of over 1 billion barrels in multiple stacked fluvial clastic reservoirs. It contains medium gravity (20-28°API), waxy, viscous crude (9-17 cp) in high permeability (1-25 Darcy) clean sandstone reservoirs. Initial development plans for the field are based on waterflooding, with at least the initial volumes of water heated to minimize any issues with wax dropout in the reservoir. Owing to the relatively high oil viscosity and adverse mobility displacement for waterflooding, the desirability of implementing an appropriate EOR process was identified shortly after the field discovery. Screening studies identified aqueous-based chemical flooding processes as the most favorable for Mangala.Detailed laboratory studies have now identified the potential of alkaline-surfactant-polymer (ASP) processes in significantly improving the sweep and displacement efficiency. The laboratory studies involved screening and optimization of the ASP slug formulation based on IFT measurements, adsorption measurements, polymer rheological and thermal stability studies; followed by a series of linear and radial corefloods. Experiments indicate the ASP process is the most effective chemical EOR process for Mangala, with improvement in recovery efficiency above the waterflood recovery of over 30% STOIIP.Chemical EOR simulations with STARSTM have been used extensively to understand the process mechanisms via matching of the coreflood experiments. Simulation parameters tuned to the laboratory data were used to evaluate the process performance under field conditions. A closely spaced five-spot pilot with 100m well spacing has been designed to evaluate the process. The pilot consists of four injectors, the central producer, three saturation monitoring wells and two post-pilot core holes. An ASP pilot will be implemented in the field shortly after startup of the waterflood.
High-Speed Wired Drillstring Telemetry Network Delivers Increased Safety, Efficiency, Reliability and Productivity to the Drilling Industry
Authors: Hernandez M. , MacNeill D. , Reeves M. , Kirkwood A. , Lemke S. , Ruszka J. , Zaeper R. 
Published: March 2008

Abstract
High-speed wired drill strings enable two way wireline communications between drilling and evaluation service provider's bottom-hole-assemblies (BHA) and surface systems. Compared to even the most advanced mud pulse telemetry, this new capability allows reliable communication with Rotary Steerable Systems (RSS), Measurement While Drilling (MWD) systems and Logging While Drilling (LWD) systems at data rates tens of thousands of times faster than ever before.
This paper describes the system development and discusses in detail the advantages immediately attainable when complete, memory quality, drilling and evaluation data is provided instantaneously at surface while drilling. These advantages include:
increased safety by continuous downhole pressure, drill string dynamics and high rate drill string energy transmission data monitoring regardless of flow or rig state; increased efficiency by optimizing RSS and bit performance, reducing hidden NPT, and monitoring wellbore conditions while drilling; increase reliability by providing a redundant telemetry system and enabling the user to identify damaging drill string dynamics; maximized productivity from more accurate wellbore placement.
The paper will then further discuss how application of the system may further develop to maximize the value in accessing memory quality LWD data instantaneously via the wired pipe network while drilling.
Talent Retention in Multinational Coming to India: A Fresher's Perspective
Authors: Chatterjee Soubhik 
Published: March 2008

Abstract
Now that it has been accepted all over the world, that India is the current seat of world class talent, that is available in great numbers and at a fraction of the cost of that of western countries, major international oil companies are pouring in to hire young Indian engineering graduates. To be in the race, even the national oil companies are striving hard to make their offers more lucrative for the young and ambitious Indian graduate. The real problem, however, lies not in attracting talent but to retain them. Indian graduates, especially from top tier institutes such as the Indian Institutes of Technology or Regional Engineering colleges, have a proven record of being highly opportunistic and ambitious. As such, they always on a look for a more challenging, more lucrative and faster paced career. The companies hiring them should, therefore, ensure that, during the initial few years, they adopt specific strategies to retain this vast skill pool. The author, a fresh graduate and into a major oil company, analyses the situation from an insider's perspective and offers some solutions for the same.