bluuebunny/crossref_metadata_2025 huggingface dataset:
How Drillstring Rotation Affects Critical Buckling Load?
Authors: Menand S. , Sellami H. , Akowanou J. , Simon C. , Macresy L. , Isambourg P. , Dupuis D.
Published: March 2008

Buckling of tubulars inside wellbores has been the subject of many researches and articles in the past. However, these conservative theories have always followed the same assumptions: the wellbore has a perfect and unrealistic geometry (vertical, horizontal, deviated, curved), the friction and rotation effects are ignored, conditions relatively far from actual field conditions. How do tubulars buckle in actual field conditions, that is, in a naturally tortuous wellbore with friction and rotation ? Can we apply theories developed for perfect well conditions (no tortuosity, no friction, no rotation) to actual well conditions ?

For the first time, this paper presents how the drillstring rotation affects the critical buckling load in actual field conditions. These new results have been obtained from an advanced model dedicated to drillstring mechanics successfully validated with laboratory tests.

Firstly, this paper presents the new developments integrated in a recently advanced model for drillstring mechanics that enables to take into account the buckling phenomenon in any actual well trajectory. Indeed, some simultaneous torque-drag-buckling calculations are presented and allow to properly take into account the additional contact force generated in a post-buckling configuration, and as a consequence the additional torque at surface. Secondly, this paper shows the influence of friction and rotation on buckling loads for some practical and critical cases met in the drilling industry. These friction and rotation effects are demonstrated with an experimental set up that enables to confirm theoretical features. Lastly, this paper shows that using standard buckling criteria may lead to too conservative solutions, and that under specific circumstances, the drilling and completion engineer could safely operate in a buckling mode for a given time.

These new results presented in this paper should improve significantly well planning and operational procedures to drill and operate more and more complex wells.
Mitigating Risks From Waste Subsurface Injection Through Accurate Downhole Pressure Measurement, Analysis, and Fracture Monitoring
Authors: Shokanov T. A. , Fragachan F. E. , Feyereisen S. B. , Greener J. M.
Published: March 2008

Enhanced environmental awareness and controls for new offshore and onshore field developments has increased the requirement for effective management of cuttings and associated drilling waste. Subsurface injection of these wastes has proven to be an environmentally sound alternative for waste management.

This paper describes the results of injection monitoring and in-depth fracture diagnostics pressure analysis for injection assurance in a dedicated waste injection well located offshore in the southern Caspian Sea. The benefits and value generated from real-time downhole pressure measurements recorded during subsurface waste injection and decline periods provided an insight into waste domain monitoring and obligatory waste management quality assurance. Precise interpretation and thorough evaluation of non-standard pressure signatures registered during regular injections provided critical information to reveal sub-surface injection pressure anomalies, potential impact on injection assurance and effectively mitigate associated potential risks.

Early in the project, fracture re-orientation into the horizontal plane as a result of injection wells being located in a tectonically active environment and on the flank of a compressional anticline with higher horizontal stresses, resulted in additional challenges for the injection assurance. This prompted the immediate need for close and continuous pressure monitoring and analysis. Detailed analysis of the downhole and surface pressure response coupled with regular collaboration of the operational team and subsurface geo-mechanics experts has contributed to the successful delivery of a waste management program. It is via an integrated team that has made the challenges and success of this project feasible.

This paper also includes the risks identified throughout the injection project as well as lessons learned from the experience. Downhole pressure measurements coupled with real-time injection monitoring provided the quality assurance required to meet zero discharge objectives in a tectonically active offshore environmental with complex in-situ conditions.

To date, more than 200,000 bbl of drilling waste have been safely disposed of in this well using subsurface injection.
Remote HP/HT Wells in Egypt
Authors: Bruce Tom
Published: March 2008

BP drilled and tested successfully the well Raven 1 in 2004. In 2006 BP mobilised into Mediterranean Sea the 15 K moored semi Pride North America. The wells to drill are deep HPHT exploration wells, it is the First Big Bore wells introduced in Egypt. Extensive learnings from Gom and Shah Deniz were transferred over.

The result of well Raven 2 confirmed the gas resources and the success of the design and the execution of a Big Bore well.

The leanings are: successful application of stress cage principle, under reaming performance, ECD management, well control equipment and operations, expandable contingencies actually used, Equipment integrity standards.

Specialized Equipment was implemented: Rig HPHT Monitoring System dedicated to HP HT drilling operation which meet The Institute of Petroleum model code of Practice, Total Waste Management Alliance system as no rejection is allowed, successful contingency deployment of Expandable Liner hanger at a depth of 4870 m (15978ft), such technology is considered for additional hole sections.

Personnel training was a key issue and put through and continually re-trained for HP HT operations. Joint Operations manual was created and strictly adhered to. Bi weekly well control drills were performed.
Improving Hole Quality and Casing-Running Performance in Riserless Topholes—Deepwater Angola
Authors: Akers T. J.
Published: March 2008

The operator and co-venturers are developing several Angola Block 15 fields in water depths of up to 1400m. To date, 83 development wells and 33 exploration / appraisal wells have been drilled in the Block. Most have experienced hole quality issues in the riserless interval that manifests themselves as tight hole while tripping the BHA and abnormal/excessive drag running casing. In a few cases, casing could not be run to total depth (TD) and in one unfortunate case, the casing buckled in open water.

There has been uncertainty as to the root cause of the hole quality issues which have been attributable to various factors since drilling was initiated. A review of available literature revealed very little published information on riserless drilling and casing running practices. The operator undertook a study of its riserless drilling and casing running practices in order to look for trends that may suggest certain sources as the root cause and to allow a re-examination of long-accepted practices. The study, combined with some new perspectives on directional drilling mechanics, has identified potential root causes not previously considered. Changes to drilling practices have resulted in improved riserless hole quality and smoother casing running operations.
Surface BOP Operations from a Multi-Service Vessel
Authors: Johnston Colin
Published: March 2008

A vessel upgrade to enable completion operations with the goal of drilling operations is discussed. The upgrade being the application of surface BOP technology to enable a subsea construction and well intervention multi-service vessel to become a slimhole completions and ultimately a drilling vessel.

The Q4000 is a column stabilized semi-submersible unit currently applied to subsea construction and subsea well operations in the form of through tubing intervention and well decommissioning. Within the upgrade review presented, the existing vessel configuration is detailed with the current intervention riser system applied to subsea well operations. The specific upgrade requirements are detailed and their impact upon the existing vessel and its operation reviewed. The key point being that the surface BOP operations are an extension of existing high pressure riser based intervention operations of which more than 40 have been conducted from the Q4000.

The upgraded subsea components in the form of a subsea shut off device (SSOD) at the wellhead, and a surface blowout preventor (SBOP) below the vessel with a high pressure riser are described. Operationally the equipment and methods to control and monitor this equipment are detailed with the analytical aspect of completion operations in 2357 ft of water.

The overall application of the upgraded vessel to an existing well completion is described in detail. The requirements to accomplish the operation in terms of equipment deployment, downhole operations and the key differences between SBOP based completion with those of more common subsea BOP and marine riser based operations are presented.

With a view to expanding the scope of application, of both the vessel and the SBOP configuration, future applications are discussed with key issues raised that may impact future operations.
Successful Implementation of First Closed Loop, Multiservice Control System for Automated Pressure Management in a Shallow Gas Well Offshore Myanmar
Authors: Fredericks Paul , Reitsma Don , Runggai Tom , Hudson Neil , Zaeper Ralf , Backhaus Oliver , Hernandez Maximo
Published: March 2008

In plans to explore the shallow gas potential of the Nagar prospect offshore the southern coast of Myanmar, PETRONAS had to contend with a number of potentially high risk issues. The shallow nature of the hazardous prospect made kick detection speed and pressure control accuracy essential to avoid losing returns. Concerns about a weak casing shoe, a narrow drilling margin, the inability to control bottom hole pressure (BHP) while circulating out gas, and the short response time needed, demanded a solution before the shallow gas-bearing sands could be drilled safely from the available moored drill ship with its conventional subsea equipment.

From flow modeling it was estimated that within 3 minutes the system and procedures would have to detect and shut-in a gas influx, then commence circulating it out, all while controlling the BHP of a flowing, multiphase fluid within extremely narrow safe limits. It was concluded that the Nagar well could only be safely drilled with a pressure management system that could maintain BHP within +/− 15 psi while drilling and +/− 45 psi during connections and well control.

In an industry search, PETRONAS learned that no system existed with the functionality needed, but by electing to combine new and existing technologies from three separate providers they were the first to develop one that did.

This industry-first solution involved integrating elements of the technology developed for automated pressure control, pressure while drilling (PWD), and high speed, drill string telemetry. Modifications had to be made to a number of elements, including the pressure control and PWD systems, to obtain the necessary functionality. Given the safety critical nature of the drilling hazards, the modifications and system integration were first tested during simulated kicks with downhole nitrogen injection, before drilling out the casing shoe. During testing on the rig and subsequent drilling operations, the integrated system proved its ability to maintain a near constant BHP, with the accuracy and speed needed to safely and successfully drill the Nagar prospect.
Method to Eliminate Lost Returns and Build Integrity Continuously With High-Filtration-Rate Fluid
Authors: Dupriest Fred E. , Smith Marty V. , Zeilinger C. Sabine , Shoykhet I. Nissan
Published: March 2008

This paper describes a fluid system developed to build integrity continuously to prevent lost returns while drilling. The primary attributes of the fluid that enable this are high solids content and extremely high filtration rates, as reflected in API fluid loss tests. It is referred to here as a drill and stress fluid (DSF).

In field applications, DSF water-based systems appear to be effective over a wide range of conditions. Circulating pressures have been sustained that exceed integrity at the bit by 1.0 to 3.0 ppg without detectable losses in depleted formations with permeability ranging from 1 to 1,000 md and pay zones of 50 to 700 ft (165 to 2,300 m) in length. The mechanism through which the DSF is believed to arrest the growth of lost returns fractures and build near-wellbore stress is described. Generalized design criteria for a DSF system are presented and the assumed relationship between the design parameters and fluid performance is discussed.

The results of the application of DSF are presented for eight wells, including post treatment evaluation logs of the drilling-induced fractures created while building stress. Operational practices that facilitate the safe use of an extremely high fluid loss system with overbalance exceeding 2,000 psi are also discussed.
Use of New Hydrostatic Packer Concept to Manage Lost Returns, Well Control, and Cement Placement in Field Operations
Authors: Dupriest Fred E.
Published: March 2008

A hydrostatic packer consists of a column of light fluid pumped into the annulus or drillstring to cause the total hydrostatic head to be equal to or less than the integrity, which is a product of the fracture closure stress (FCS). This results in positive surface pressure, which allows accurate placement of cement, lost returns treatments, or other fluids in situations where they would otherwise be overdisplaced if a full column of drill-weight mud were used. Although hydrostatic packers are not a physical device, they are referred to as packers because they serve many of the same functions as retainers and squeeze tools and are used in similar operational situations.

The operator has utilized hydrostatic packers in one area for 15 years and globally for the last seven years. Despite the maturity of the practice it has not been adopted by the industry. The business value is large, but lack of understanding of fracture mechanics in the drilling industry raises a significant barrier. The use of hydrostatic packers requires that engineering, operations, and contractor personnel understand the fracture propagation mechanism through which major lost returns events occur, and particularly the role of fracture closure stress. The team must also develop field practices to mitigate specific risks associated with hydrostatic packers. This paper discusses these points as well as the operational issues that must be considered in certain unique situations.

Applications described include stabilizing the annulus following lost returns, controlling placement of lost circulation material (LCM) when pumping pills, controlling cement placement during squeeze operations, achieving high quality cement coverage behind liners with lost returns, and management of downward underground flow.

Hydrostatic packers have been used effectively in over 30 fields and have contributed greatly to the operator's high success rate in treating lost returns events (Dupriest 2005). Their use requires training and structured risk assessment, but they are simple in concept and have been effective in controlling fluid placement in all field applications to date.
Managed Pressure Drilling Success Continues on Auger TLP
Authors: Chustz Mark J. , Smith Larry D. , Dell Dwayne
Published: March 2008

Shell Exploration & Production Company continues to execute redevelopment slim hole sidetracks using Managed Pressure Drilling (MPD) on the Auger TLP in Deepwater Gulf of Mexico. Four sidetracks have been successfully drilled utilizing a Dynamic Annular Pressure Control (DAPC) system to eliminate lost circulation and borehole instability events.

Execution of MPD continues to improve, resulting in operational efficiency gains and allowing access to previously unattainable reservoir targets. Intervals previously considered impossible to drill due to depletion induced frac gradient reduction are being drilled and cased trouble free with MPD.

Recent MPD well designs have incorporated reduced static mud weights below pore pressure to manage the available drilling margin. Bottom hole pressure variation from the defined set point has been reduced and excursions outside of the target pressure window are being eliminated during subsequent MPD well operations.

Auger's field redevelopment history, well designs and Managed Pressure Drilling designs will be reviewed. Execution of MPD operations will be addressed in detail focusing on engineering and operational improvements throughout the four MPD sidetrack campaign.
Tight Clearance Operations—Running 5½-in. Liners in 57/8-in. Holes
Authors: Goertz Markus , Belohlavek Kai-Uwe
Published: March 2008

In North-German gas fields, occasionally 5½-in. liners have to be run in 5⅞-in. boreholes. This low-clearance application does not represent the standard. This paper describes the steps taken to successfully run and cement these liners in spite of the extremely tight clearances by means of two case studies.

One application is to run 5½-in., 32-lb/ft thick wall casing in 5⅞-in. holes to cover squeezing salt sections in order to provide long-term integrity of the well. The other application is to run regular wall 5½-in., 20-lb/ft casing to enable remedial sand control, which would not be possible with standard sized 5 or 4½-in. liners.

In both applications, these liners had to be run through 5⅞-in. drift casing into a directionally drilled 5⅞-in. openhole with actual dogleg severities (DLS) of up to 9°/100 ft. Often, the drilled sections contain hard and abrasive sandstone layers, which have to be drilled with diamond impregnated bits. Thus, underreaming is not economically viable.

To successfully run and cement the 5½-in. liners, the borehole has to be prepared properly by running extremely stiff reaming assemblies. The 5½-in. tubulars do have special flush connections (MUST or V&M-FJL). Experience has shown that a planned DLS of 6°/100ft is feasible. On regular wall 5½-in., centralization is achieved with Ceramic Carbon Fiber Stand-offs. The mud systems used ranged from low solid Formate mud (12.2 ppg with extremely low fluid loss and thin filter cake) to weighted water-based mud (16.4 ppg with high solid content). Additionally, to reduce friction, lubricants based on Glycol or Graphite were successfully applied. Finally, cement recipes have to be carefully adjusted to these mud systems.
Treatment of Nonaqueous-Fluid-Contaminated Drill Cuttings—Raising Environmental and Safety Standards
Authors: Kirkness Alister , Garrick Davie
Published: March 2008

Drill cuttings and other hydrocarbon contaminated wastes generated in offshore drilling operations have been processed onshore for many years, in part to comply with the regulatory restrictions governing offshore disposal and in part to conform to sound environmental practice. However the transporting ("skip & ship") of large tonnages of hydrocarbon contaminated cuttings from offshore installations to shore based processing facilities carries with it considerable environmental and safety implications for the industry.

The concept of processing these hydrocarbon contaminated cuttings offshore and the recycling of both the recovered oil and water back into the drilling fluid provides a unique solution to the inherent problems of "skip & ship", both in the North Sea and elsewhere. The development of this concept into a practical, field proven technology commenced in 2001 and was satisfactorily concluded, following a series of offshore trials in the UK sector of the North Sea, in the latter part of 2002. Since this time the application of this technology has gained wider use and greater acceptance by the industry, allowing for a thorough evaluation of its application in resolving many of the more intransigent problems associated with drilling waste management in offshore operations.

This paper reviews the work completed to date and how it might best be applied in the future. For the work completed, field data will be provided on all aspects of the process and also evaluate the benefits, both in terms of the environment and safety, on a project specific basis.

With regard to the future, the paper will look at ways in which offshore treatment may be better applied to optimize all of the advantages obtained.
MPD Operation Solved Drilling Challenges in a Severely Depleted HP/HT Reservoir
Authors: Bjørkevoll Knut S. , Molde Dag Ove , Rommetveit Rolv , Syltøy Svein
Published: March 2008

A novel MPD setup has been tested and used at the Kvitebjørn field in the North Sea to make possible the drilling of 8.5″ holes through reservoirs with heavily depleted zones. A central part of the concept has been to use an advanced dynamic flow and temperature model in combination with an automatic choke system to control open hole pressure very accurately.

The paper describes briefly the operations, and discusses challenges and experiences related to making these complex components work reliably together.

The system has proven its potential for minimal variations in pressure at a given open hole position, with accurate automatic pressure control in wells were margins are very small, smaller than frictional pressure losses added when circulating at drilling rate.

This paper focuses in particular on the use of an advanced transient model for automatic choke regulation. Other aspects of the operation are described in more detail elsewhere, see Refs. 1-3. Challenges exceeded expectations, but after a test period with many improvements based on trial and error inside cased hole, the 8 1/2″ sections were drilled successfully with good pressure control.
Cementless Multi-Zone Horizontal Completion Yields Three-Fold Increase
Authors: Maddox Brad , Wharton Molly , Hinkie Ron , Balcer Brent , Farabee Mark , Ely John
Published: March 2008

This case-history paper presents an account of the application of expandable (swelling) packers and a hydrajet perforating stimulation technique to perform a cementless completion and hydraulic stimulation in a 350° F, openhole horizontal well of 15,700 ft total vertical depth (TVD). Resulting production was more than three times that of an offset vertical well.

The first Wilcox Meek 2 well in the Brazos Bell Prospect Area was drilled and completed to test the effectiveness of horizontal well technology in tight-sand formations. This paper presents the cementless completion process and explores the effectiveness of horizontal-well technology in tight sands by comparing initial horizontal-well production rates to those of offset vertical wells.

The well, which was the first horizontal Wilcox in the area and probably the deepest horizontal well completion for a sandstone reservoir in South Texas, used a 5 ½-in. / 3 ½-in combination string as a production string. The 3 ½-in casing was run in the openhole horizontal lateral section and extended into the 75/8-in liner casing. It employed five swellable packers, strategically placed on the string to facilitate isolation for optimum stimulation results. An additional swellable packer, larger than the previous five, was run on the top of the 3 ½-in casing string and was placed inside the 75/8-in casing to help ensure complete isolation of the annulus. The swelling packers were activated over an 18-day period by hydrocarbons present in the oil-based mud (OBM) in the annulus.

Following packer activation, four fracture-stimulation operations were conducted in a non-cemented hole using a unique fracturing technique that incorporates hydrajet perforating with coiled tubing (CT). This technique allows for (1) multiple stimulation treatments to be performed in series without the CT being removed from the hole, (2) larger stimulation stages, and (3) maximum surface-area exposure to the fracture pressure without formation damage caused by cement.
Offshore Underbalanced Drilling—The Challenge at Surface
Authors: Gough Geoff , Graham Robert
Published: March 2008

This paper is a case study detailing the process followed and challenges encountered, at surface, when drilling oil wells underbalanced offshore in the Danish sector of the North Sea. UBD was identified as an enabling technology in the field to combat conventional drilling challenges due to variations in pressure profile along lengthy horizontal hole sections - the drilled wells comprised 6" horizontal sections in excess of 2000m. The drilling programme presented a significant examination of the surface handling equipment due to the anticipated inflow parameters. The surface system was required to de-energise and separate up to 25,000 bpd returned/produced oil, water and cuttings along with up to 30 MMscfd of gas; returning the water back to the rig for the well circulation system, cuttings into the annulus of an existing well and the routing of produced hydrocarbons to the existing production platform. The first well also utilised platform gas for annular gas injection to maintain the required circulating pressure profile. A rigorous process design procedure was followed to determine the optimum surface equipment configuration to handle the combination of drilling fluid, solids and well effluent that came to surface during underbalanced drilling operations as well as evaluating potential for hydrate formation, foam and emulsions. An alignment of procedures with the rig, production platform and service companies was implemented. In addition, a strategy was employed to facilitate recovery of oil and gas produced during underbalanced drilling operations to the platform process facilities. Challenges that presented themselves included large volumes of friction reducers in the circulating system, lower than expected surface temperatures, ultra fine cuttings production and integrating the platform's data acquisition and emergency shutdown systems.
Multi-Diameter String Tools Deliver Lower Cost-Per-Foot in Demanding Rotary Steerable Applications
Authors: Barton Steve , Jones Wayne , Young Rick , Rorvik Helge
Published: March 2008

The use of hole opening tools in conjunction with Rotary Steerable Systems (RSS) has increased dramatically in the past few years. Although excellent performance has been delivered with the mainstream commercial tools, alternate options have been developed to enable an RSS to drill the pilot hole in conjunction with a string tool to open the hole in a single run.

The most popular current option involves a weight or hydraulic activated underreamer. However, fixed blade, multi-diameter reaming tools have recently been developed for use within Rotary Steerable (RS) assemblies: An eccentric string reamer that will pass through a small pilot hole but then drill and produce a larger hole. This provides a significantly lower-cost hole opening option.A concentric string reamer that utilizes a tapered design incorporating a mid and main reamer section. This innovative design uses a mid-reamer that enlarges the pilot hole to an intermediate size and stabilizes the main reamer above it on its gauge pads. Because of its unique design, the mid reamer is able to stabilize the tool even if the pilot hole is of poor quality or is overgauge. This is particularly beneficial with RS tools in soft formations, leading to improved borehole quality and BHA stabilization. It also enables the use of smaller RS tools, thus providing greater directional potential. Additionally, a single RSS can be used to drill multiple hole size intervals, minimizing BHA changes, which in turn increases rig floor safety and lowers costs.

Several distinct applications are documented where these fixed bladed solutions, in combination with both Push and Point RS tools, have proven extremely successful. This has provided greater flexibility with regard to tool selection and well planning options, delivering lower cost per foot in RS projects. Case studies are presented from the Far East, Norway, and the Gulf of Mexico.
Information Technology Services for the Big Crew Change: An Indian IT Services Perspective
Authors: Lasrado Vineet , Pande Anil
Published: March 2008

This paper will discuss how and Exploration & Production Companies / National Oil Companies (NOCs) can leverage global Information technology services companies from India (or other talent surplus countries), to virtually expand the existing talent pool of the Industry. Exploration & Production industry trends, contrasts between the developed and developing markets such as India, capability of Indian IT services sector, and areas where IT services can make a contribution will be discussed. Based on the above factors, the potential of the IT services sector to build IT Solutions and create new talent for the industry will be analyzed.

Outsourcing of services to Oilfield Service Providers has been one of the strategies used to solve some of the people shortage problems in the industry. This has also allowed E&P companies to focus on their ‘core competency’ which is the exploration and production of oil and gas. A similar strategy which global Exploration & Production companies are tending to adopt in Information technology is IT Services Outsourcing. This helps the companies use their existing manpower, reduce costs, as also to let IT service companies do more of the ‘digital’ type work in E&P. Although IT outsourcing may have started purely based for cost reduction, IT outsourcing now has the strategic advantage of better access to talent and capabilities1. IT service providers can help in areas like Remote management of operations, basic collaborative operations, problem solving, leveraging associated Knowledge Management, and real time Data Management - which require a mix of Exploration & Production industry domain and IT experience. An increasing number of people with such experience would be required by the Industry with the increasing importance of IT function as a strategic part of business, and with the ‘Digitization’ of many functions.

The combination of a growing Exploration & Production Industry, Operators, NOCs as well as Vendors combined with the growth of the global software services sector and the availability of a large labour force in developing countries has the potential to contribute IT solutions and create an extended talent pool of professionals who can serve the global Exploration & Production industry and help solve the looming ‘crew change’ crisis.
Dual Activities without the Second Derrick— A Success Story
Authors: Webb Tamara , Selamat Kasim , Fletcher Billy
Published: March 2008

Kikeh Field is located 120 km from Labuan in offshore Sabah Malaysia. The field, with 1330 m water depth, is the first deepwater development in Malaysia and consists of subsea and SPAR development wells.

The West Setia is a non-propelled Semi-Submersible Drilling Tender being used for SPAR development activities. The Drilling Tender utilizes six stability columns supported by a twin-hull configuration. However, the derrick and partial rig package still sits on the SPAR (or platform deck) to carry out drilling and completion operations.

The completion program covers not only standard scope of installation, i.e. lower, middle and upper completion, but also includes displacing fluid with nitrogen for riser dewatering and well clean up and testing. Several logging operations also were identified as tasks to be delivered during completion operations.

Considering the wide scope of completion work outlined in the program, a detailed work assessment was conducted focusing on areas where offline activities could be conducted safely and efficiently. As a result of the assessment, at least seven completion-related activities were identified.

During the first batch of SPAR completions which involved five wells, the result showed that the following activities were successfully completed offline, allowing the rig to be utilized for critical path operations: Tubular make up and racking backTree installationRiser annulus dewateringSetting/testing Mudline Hanger Packer (MLHP)Installation of flowline jumper and umbilicalClean up and flow testing the wellCement and reservoir evaluation loggingProduction Riser Tensioner installation and commissioningCycling and opening Formation Isolation Valve (FIV)

This paper will describe in detail each of the operations involved, discuss rig capabilities and limits, and explain the challenges, safety considerations and lessons learned from the project as well as the time savings and value created from each of the activities.
The Blossoming of Talent through Facilitating Articulation and Pursuit of Choices
Authors: Sen Ashis
Published: March 2008

Need for Change

With increasing globalization, Inidan consumers enjoy choices like never before. Consequently, primacy of customer satisfaction is the new belief system of Inidan Organizations. The Changed belief system simultaneously demands and fules innovation; which in turn underlines the need for continous learing and development. After all innovation is not a caus, it is the result of organizational learning.

To learn, the learning objectives must be meaningful to the learner. He must find learning a personal need rather than the foisted need of the organization. For e.g. children learn the difficult skills of football despite challenges, because playing the gaem well as an objective, is dear to them. Rarely if ever, one bcomes a great foobballer since the school or state needs one.

Our managers discovered that constancy was giving way to rapid changes in the market place. Under conditions of rapid change, organizational climate needs to encourage innovation, risk taking and facilitate quick learning. To make this happen people need to challenge, culutural norms, established rules and procedures to ascertain their validity. Such acts need an enabling organizational climate fostered by successful leadership.

The Methodology

We are aware that work that is intrinsically rewarding to the individual generates the best. Kindling of intrinsic motivation by enabling and encouraging employees to visualize a desired future is leadership. We followed this process. Though, the process of involving people in crafting the organizational desired destiny was time intensive and arduous, the results in terms of employee engagement and leadership development has been invaluable, moving them from assigned work to self aspired challeges. Peoples’ movements forbid shorcuts.

Significant Results

Kindling intrinsic motivation by facilitating articulation and pursuit of choices enables us to attract, nurture and retain talent. Also, significant business results in terms of profits and market share have also been recorded.
New Cement Systems Developed for Sidetrack Drilling
Authors: Al-Yami A. S. , Nasr-El-Din H. A. , Jennings S. , Khafaji A. , Al-Humaidi A.
Published: March 2008

Directional drilling makes it possible to drill multilateral wells into different parts of a reservoir from a single wellbore. Many directional wells are drilled to reach reservoirs inaccessible from a point directly above because of surface obstacles or geologic obstruction. Wellbore sidetrack drilling operations with hard cement plugs have been used for years. Placing cement plug in the borehole and allowing the cement to develop high compressive strength perform sidetracking technique. The hardened cement plug when drilled deflects the bit away from the current borehole, starting another open hole section.

Conventional cement formulations for sidetrack kickoffs usually fail when the ROP (Rate of Penetration) for the cement plugs is much more than the ROP in the formation Sidetracking failures, in building up kickoff angles, results in operational delays and cost overrun. High sonic compressive strength cement system with slow ROP should be designed and developed specifically for side tracking operations.

A rate of penetration device was used to optimize cement formulations to determine the ROP through cement plugs. Different chemicals for building up sonic compressive strength were evaluated. Special types of cements were designed and evaluated for possible use for sidetrack kick-off plugs. The effect of inert particles on the sonic compressive strength and ROP were investigated. The cement slurry was cured for 24 hours in the Ultrasonic cell at bottom hole static temperatures of 260-290°F and a bottom hole pressure of 4,700 psi to represent gas well conditions and 200-250°F and 2,200 psi for oil wells. The outcome of this work was cement formulations with high potential (high sonic compressive strength and slow ROP) that can be used to drill horizontal and multilateral wells.
Reservoir Characterization and Structural Correlation Using Shear Seismic and Pressure Data Integration in Ravva Field: An Innovative Technique
Authors: Kumar Rajan , Ravichandran V. , Kelly Damian
Published: March 2008

Ravva oil and gas field is located offshore, eastern India, in the shallow waters of the Bay of Bengal. The field is operated by a Joint Venture of which Cairn India Ltd. is the Operator. The field has completed 15 years of production from Middle Miocene reservoir, with over 9 years on plateau production of 50,000 BOPD. The field has two oil blocks, designated as RA/D block and RE/F/B block. The latter is the smaller of the two: it accounts for nearly a quarter of Ravva STOIIP. Until an integrated reservoir modeling study was undertaken in 2004/05, the RE/F/B block was generally recognized as an area with poor understanding of structure and hydrodynamics. This lack of understanding was attributable to three main factors: a) attenuated seismic response in the central RF area due to the presence of gas at the shallower Late Miocene level b) complex compartmentalization with low net-to-gross and c) the Class II AVO response presented by hydrocarbon-charged Middle Miocene reservoir sands. To overcome these challenges, shear reflectivity (Rs) data, in conjunction with derivative rock property attributes and validated by dynamic pressure data, was used to develop a new geological model: the basis of an infill drilling campaign comprising of one producer and two injectors. The infill drilling campaign has now been carried out and the proposed wells have achieved their objectives.

This paper presents the novelty of the multi-disciplinary approach, in which shear information, inherent in the p-wave seismic gathers, was leveraged and integrated with reservoir pressures and other geotechnical data to make a representative model and realize a successful drilling campaign.
Very Low Water Saturations within the Sandstones of the Northern Barmer Basin, India
Authors: O'Sullivan T. , Zittel R. J. , Beliveau D. , Wheaton S. , Warner H. R. , Woodhouse R. , Ananthkrishnan B
Published: March 2008

The Mangala, Bhagyam and Aishwariya Fields were discovered in early 2004 in the northern Barmer Basin of Rajasthan, in northwestern India. The data acquired in the field wells (including almost two kilometers of core) enabled a precise estimation of field stock tank oil initially in place (STOIIP). This paper summarizes the techniques that allowed the estimate of STOIIP to be more precisely defined and to be revised upward by 12%, a substantial increase when dealing with a billion barrel field (Mangala Field). Initial evaluation of the log data indicated a sequence of clean, quartzose sandstones with porosity greater than 25%. High porosities together with resistivity in the oil column over 5,000ohm-m, suggested that water saturations (Sw) were ~15% or even less. Based on the initial data and conventional techniques, the initial STOIIP estimates were made for the three fields.

An extensive core analysis programme was begun in appraisal wells, with the objective of improved definition of the actual reservoir STOIIP's. Two appraisal wells were cored with synthetic oil based mud, and Dean-Stark Sw analyses were done. In addition to routine core analyses and the Dean-Stark Sw data, a sizeable set of other special core analyses is also available. This includes extensive capillary pressure data, laboratory NMR, and core electrical properties measurements.

The petrophysical dataset verifies the existence of Sw's that are typically less than 5%PV, and often near 1%PV, in a very high-permeability and high-porosity reservoir containing little clay. The reservoir contains a medium gravity, highly paraffinic oil, and is moderately oil-wet. The various laboratory datasets challenged some of the traditional assumptions concerning the use of Archie constants in such reservoirs for Sw calculations. The upward revision of STOIIP is significant, and can be principally attributed to the more accurate estimation of reservoir fluid saturations. As this work demonstrates that very low Sw values exist in the Barmer Basin, the Mangala, Bhagyam and Aishwariya fields can provide a model for the appropriate economic evaluation of similar reservoirs.

The laboratory results challenge some of the traditional thinking about the petrophysical properties of reservoirs such as these. It is indeed possible, that high quality reservoirs can have initial water saturations lower than 5% of pore volume on average, and with some zones less than 1%. Conventional log tools and analysis methods will not reveal these low levels without integration with core data and appropriately designed core analysis programmes. Also, and perhaps more importantly, this work clearly demonstrates the economic worth of extensive laboratory measurements and analyses on high-volume, high-value reservoirs such as those of the Mangala, Bhagyam and Aishwariya Fields.
Assisted History Matching as a useful tool: An example from Trinidad
Authors: Walker Greg J. , Kromah Molyama , Pham Hung , Adeyeye Deji , Winchester Arlene
Published: March 2008

The goal of all history matching for the reservoir models is to generate accurate predictions. There is also an assumption that a better history match should lead to a more accurate prediction, which can lead an asset team to concentrate on a single model.

The assisted history match techniques allow us to generate multiple models that satisfy the surveillance 1, and understand a range of outcomes for a set of models. What we need is to provide assurance that we are searching correctly for the range in outcomes, to understand the interaction between uncertainty, surveillance, and the business decision.

This paper describes an example for the Mahogany field in Trinidad, which is mainly gas with a thin oil rim. As the reservoir pressure is decreasing, there is a window of opportunity to drill an additional well.

The first task is to determine the correct value of a new gas well, to protect against water encroachment. The Mahogany field used BP's Top Down Reservoir Modeling (TDRM™) to test a hypothesis - is it possible to find models that match history, and have certain key features in the future? In this case we are specifically looking for a scenario with water at the existing gas well locations. Since the system is generating discrete models, we can then test which new gas well locations would mitigate the water.

We've also been able to use an idea from our Alaskan operations, and consider water injection with a dump flood. The appraisal of the water injection has been performed using computer assisted depletion planning tools (TDDP™ 2) to assess the best location and strategy for such a well.
Application of a Novel Open-Hole Horizontal Well Completion in Saudi Arabia
Authors: Al-Naimi K. M. , Lee B. O. , Bartko K. M. , Kelkar S. K. , Shaheen M. , Al-Jalal Z. , Johnston B.
Published: March 2008

Horizontal completion technology has progressed dramatically over the last six years, with the latest technical barriers being eclipsed with open-hole technology. These completions have allowed multiple zones to be fractured and the benefits of utilizing open-hole horizontal completion technology have been well documented. The efficiencies and benefits of utilizing open-hole completion with mechanical isolation, has lead to the operational benefits of multiple fracturing operations being pumped in one continuous operation equating to time savings, more efficient fractures, faster cleanup and less safety hazards. Conventional methods of cementing a liner in place, perforating, fracturing and repeating the process for the number of stages required can be very time consuming with added expense of removing the frac plugs with coiled tubing after the operations have been completed.

When drilling a horizontal well, there are two preferred completion options. First, the horizontal section can be completed open-hole or with slotted/preperforated liner. In these completions effective stimulation along the horizontal wellbore is almost impossible. The second completion system, cased/perforated liner, requires cementing the production liner and running multiple isolation systems to effectively treat different sections of the wellbore. Multiple coiled tubing trips and multiple rig-up and rig-down of the stimulation equipment is required. These multi-stage horizontal completions take weeks to complete at high costs and elevated risks. Ultimately, the high completion costs or the lack of production due to ineffective stimulation make many reservoirs uneconomical to exploit.

This paper will discuss the new completion designed specifically for open-hole fracturing of both sandstone and carbonate reservoirs. This innovative, field proven system greatly increases the effectiveness of fracturing operations by segmenting the lateral and producing mechanical isolation points in the wellbore using the high performance open-hole packers. The system allows precision placement of fracturing fluids to maximize post-fracture productivity of the well. The completion system is run as part of an uncemented liner and spaced out based on the required number of stages. Once in place the packers are hydraulically set and fracturing treatments are pumped in separate stages but as a single continuous operation. By eliminating cementing requirements, natural fractures are undamaged and easily stimulated during pumping operations.
From Foreigner Pedagogy to Intercultural Education: An Analysis of the German Responses to Diversity and its Impact on Schools and Students
Authors: Faas Daniel
Published: March 2008

Germany has been reluctant to adapt its education systems to the growing number of minority ethnic students, and politicians and policy makers have only recently officially acknowledged that Germany is an immigration country despite decades of mass immigration. This article first provides a socio-historical analysis of the German responses to migration-related cultural and religious diversity by tracing the development of educational policies from assimilationist notions of ‘foreigner pedagogy’ in the 1960s and 1970s to intercultural education, which slowly emerged in schools in the 1980s and 1990s. However, unlike European education, intercultural education still lacks official support in some German federal states. Drawing upon qualitative data collected in two Stuttgart secondary schools, the article then discusses the ways in which schools and students have mediated such macro-level policies. Goethe Gymnasium (a university-track school) promoted European values alongside multicultural values whereas Tannberg Hauptschule (a vocational-track school) was close to being Eurocentric and positioned minority ethnic students as the ‘Other’. The findings suggest that Germany still has some way to go to overcome cultural insensitivities, to increase minority ethnic representation amongst teachers and to promote both diversity and civic cohesion.