bluuebunny/crossref_metadata_2025 huggingface dataset:
Ad-Equation between a Second Generation Semi and Drilling Extended Reach Well In Tunisia
Authors: Dupuis Dominique , Forasol Pride , Hancock Shaun
Published: March 2008

To develop its Miskar field offshore Tunisia, BG Tunisia made a call for tenders in 2005 during tight market conditions prevailing at the time.

After further study review of the MODU characteristics a second generation Semi Submersible from Pride International "Sea Explorer" was selected. This unit was designed in late 70's & did not have all necessary features and capacities to drill a High Temperature and extended reach well (range: TMD 6.740 m (22.200 ft) and TVD 3.400 m (11.150 ft)). Some minor modifications had to be made to the unit as well as some specific procedures in order to drill such wells in accordance with rigorous standard practices.

The paper will highlight: –The drilling constraints, hazards of such a well, not limited to the well architecture but also the geology where fractured zones imply a strict monitoring of mud weight and methodology to contain some rather shallow high pressure gas, high temperature 200°C (400°F).–The necessary adaptation made to the rig in order to meet the constraints: drill pipe selection to limit pressure losses, torque & drag. Implementation of a racking arrangement, mud cooling system, increase of mud tank capacity, cuttings treatment (no discharge to sea is allowed in the Mediterranean basin ), handling system for Subsea Xmas tree had to be revisited and upgraded.–Crew training and dedicated procedures especially in respect of Kick Control, and improved practices for drilling compensator to avoid exceeding its capacity while drilling.

This paper will present a brief well history, the drilling campaign results and highlights the lessons learnt.

Following the successful completion of the actual drilling campaign, this Paper concludes on the upgrade potential and capacity for a second generation semi to match the challenges of today's high profile wells. It also highlights the benefits of close-collaboration between operator and contractor.
Accelerated Training and Competency Program
Authors: Tinchon Philippe
Published: March 2008

One of the major challenges we face today is recruiting and retaining the workforce necessary to support the growth the entire oil and gas industry is experiencing. Compounding this challenge is the enhanced training and development required for new and less-experienced employees in light of the retiring generation, the increase of drilling activity and the arrival of more than 130 new offshore units

Pride International will address these challenges by accelerating the development of green hands and high potential employees, as well as maintaining and improving the level of personnel qualifications.

Pride has moved forward from a Training Management System to a Competency Management System, (Competency modeling and reporting process). This system deals with each skill on board including Safety, Drilling, Mechanics, Subsea, Electric, Marine, etc. Each employee is cycled through three groups of competencies: QHSE, operations and personal values – which include behavioral and soft skills.

Employees can be cycled through normal, Intensive training programs, such as our Rig Intensive Development Program and Management Training Program. These programs include not only theoretical and practical training (as well as certification), but also leadership attitudes, safety team spirit, team building, etc

The Core Competency program of the Competency Management System will be used for all employees, only the accelerated process will be used for the fast track employees.(National RIDP*, expatriate RIDP* & MTP*).

To support these accelerated development programs and ensure the high quality of position qualifications, Pride has focused on in-house training capabilities through its regional training centres in France, Angola, and Brazil.

In order to benchmark and assess the competencies of the personnel, a Quality Control System has been implemented. This system, SkillsXP*, will track qualified personnel for various assignments as well as specific competencies demonstrated by the individuals.

The paper outlines the Competency Management System and will include how the accelerated drilling program for new hires and National employees is implemented, what the goals are in respect to competencies and the time for employees to achieve the goals, the mechanism to benchmark, and ensure the QAQC of the Competency Management System. The paper will highlight the following aspects:
Results from Systematic Rotary-Steerable Testing with PDC Drill-Bits Depict the Optimal Balance between Stability, Steerability, and Borehole Quality
Authors: Jones Steve , Sugiura Junichi , Barton Steve
Published: March 2008

There is significant discussion concerning what type of Rotary Steerable System (RSS) provides the best-quality hole, and which key characteristics of the drill bit, along with a particular RSS, will produce the optimal balance between stability and steerability in directional wells. Although some evidence can be drawn from field performance with various tools and customized drill bits, these results can often be inconclusive due to the large variance in factors involved with commercial drilling.

This paper describes an extensive series of test wells drilled in a controlled and non-commercial environment, allowing single step changes in both the drill bit features and Rotary Steerable (RS) configurations. The testing is unique in that the specific RSS works in shop-configurable point-the-bit and push-the-bit modes. Between two distinct RSS operation modes, consistency in stiffness, weight, force applying capability, and control systems lead to a direct comparison of bit performance.

A unique sensor system, integrated into the specific RSS, provided real-time measurement of near-bit borehole caliper and near-bit stick-slip and vibration. This feature allowed real-time evaluation of bit and BHA stability and borehole quality. After each test run, memory data was retrieved and used for more detailed assessment of bit performance.

Drill bit tests were systematically structured in a controlled environment so that the relationship between gauge geometry and configuration could be examined without alteration of the cutting structure. As a result, comparison between stability, dogleg capability, torque and drag, and borehole quality was solely dependent upon gauge length and geometry. Further, the systematic testing led to the conclusion that a specific gauge design related to effective side cutting and gauge stabilization is crucial for optimized RS drilling in both point-the-bit and push-the-bit configurations.
Full Field Development of a Remote Oilfield in East Siberia with Four Rigs Simultaneously Delivers Field Record in Drilling
Authors: Drnec M. L.
Published: March 2008

This paper presents the start up of a full field development of a remote oilfield in East Siberia in 2007. Four rigs are drilling simultaneously on four pads delivering a field record in drilling. The Russian client drilled three vertical wells before 2007. The first and slowest directional well using an "old" Russian rig, was still drilled significantly faster compared to the above three wells. Two wells using a "modern" Western rig are the fastest wells drilled. These records were established without any lost time injuries or incidents. Zero failures of motors or gyros occurred despite the inability to service equipment during the first half of 2007.

Western directional drilling and MWD Crews operate on all rigs run by three different drilling contractors (one Russian, two Western). Synchronization with the crews results in reduction of BHA handling times on all four pads. Teamwork in general has been outstanding, especially with regard to difficult logistics due to the remoteness of the field. The challenge was that DD/MWD tools had all to be delivered on time before closing of the winter road – no land transport is possible once the ground is not frozen anymore. A specific standard operation procedure aligning operator, contractors and service companies has been developed to stream line efficiency and effectiveness of operations.

Innovation has been the key to the success of this first multi segment project in Russia. No maintenance of MWD tools was possible in the field until a base was complete using an inflatable tent (First in Russia). An in-field shop for MWD electronics and modulators was up and running by mid 2007. Advanced satellite communication has been setup for operations in each pad and the base using real time data channels to facilitate support from a Sakhalin based operations support center.
Horizontal Extended Reach Re-Entry Drilling of Sidetracks at Sakhalin Island Increases Oil Production from Mature Oil Fields
Authors: Drnec M. L. , Przhegalinsky I.
Published: March 2008

Re-entry drilling represents a significant part of the current and future drilling activities worldwide and particular in the Russian Federation. Enormous funds of old oil and gas wells drilled in the last century are un-active. Economical demand positions the sidetracking activities with a very promising future of the drilling activities. A Russian oil company, famous for successful development of challenging ERD projects at Sakhalin Island, has around 1000 of oil wells drilled between 1950 and 1980 with most of them currently idle.

This paper presents a study of the feasibility of drilling horizontal extended reach sidetracks to increase oil production from these mature oilfields. Its main objective is to evaluate technical and economical aspects associated with drilling horizontal reentries from already existing old oil well stocks. The objectives of the paper are: Evaluation of the economical attractiveness of such a project; Candidate selections; Drilling engineering design of the wells; Evaluation and selection of contractors for provision of appropriate re-entry equipment such as whip stocks, scrapers, mills, bi-centered bits, etc; Subsequent coordination between proposed and involved parties; Evaluation of the well placement approach implication.

With the successful development of the re-entry drilling project the following potential benefits are realized at this stage: Oil production increase through the old portfolio of wells revival; High quality technical project development; Low tier market development for the known to be a high tier market ground at Sakhalin island; Revenue sustention for known to be a cyclical and season dependent market.
Latest Developments and New Technology for Coiled-Tubing Sidetracking Applications
Authors: Garfield Garry , Mackenzie Gordon
Published: March 2008

The influence of improved technologies and the latest operational developments has lead to a significant impact in the arena of coiled tubing drilling operations. These influences are also making themselves known in the underbalanced coiled tubing drilling sector. Sidetracking operations have traditionally utilized a philosophy dominated by threaded tubular drilling conveyance methods; however, with the growth of coiled tubing drilling applications in recent years, coiled tubing deployed bottomhole assemblies for sidetracking a well are beginning to gain acceptance as a standard practice.

A major advantage of a coiled tubing deployed exit system is the ability to mill a window in the casing in a restricted wellbore environment. The whipstock can be deployed in a live-well condition without the necessity of removing the completion equipment thus eliminating the requirement for a workover rig and negating the need for kill weight fluids. The systems can be deployed on either electric wireline or coiled tubing making them ideally suited for restricted bore access and allowing the window to be milled below the completion.

The discussion will include a comprehensive overview utilizing a new whipstock system with the conveyance method of coiled tubing and electric wireline in order to create a casing window. The overview will also communicate general practices and tool selection criteria with the case histories representative of the placement of the whipstock with coiled tubing and the window milling being performed with coiled tubing workover motors. The case histories will detail two runs of the new exit system, the first in the North Sea and the second in the Middle East. Both case histories will show the economic benefits of utilizing live well intervention deployment methods for whipstock placement as well as the rig cost savings of utilizing coiled tubing deployed mills and motors for delivering a casing window.
Particulate-Based Loss-Prevention Material - The Secrets of Fracture Sealing Revealed!
Authors: Kaageson-Loe N. , Sanders M. W. , Growcock F. , Taugbøl K. , Horsrud P. , Singelstad A. V. , Omland T. H.
Published: March 2008

Owing to the narrow drilling margin that exists between the pore pressure and fracture pressure gradients, drilling in depleted reservoir, HPHT and deep water environments is universally recognized as being technically challenging.

A number of field techniques are available for mitigating against many of the drilling problems encountered. Included amongst these are specialized fluid engineering that involve use of chemical- and particulate-based treatments for minimizing or preventing losses. In many instances these techniques can be used to strengthen or stabilize the wellbore when drilling on or near the fracture gradient thereby potentially eliminating the need for intermediate casing strings.

This paper discusses particulate-based treatment design for sealing fractures. Substantial experience gained from innovative laboratory testing has highlighted the mechanisms and many factors that determine the effectiveness of the fracture seal. The particle size distribution relative to the fracture aperture, particle morphology, volumetric concentration, fluid rheology and fluid-loss-control influence whether the seal is established within the fracture or at the fracture mouth. Understanding this distinction is important with respect to selecting the optimum treatment and its application for given field conditions. Parameters critical for optimizing the treatment have been identified and are discussed in the context of laboratory and field experience.
Megathyst Units—Operational Optimization With Four Identical Drilling Rigs After Five Years of Operation
Authors: Bocabarteille G. , Dupuis D. , Araujo J.
Published: March 2008

The Megathyst class rig design is an evolution of the Amethyst class rig targeted for mid range deepwater applications in benign environment. Although most rig designs are duplicated many times they are seldom identical in rig equipment and rarely deployed in the same geographical areas to take advantage of the standardization. A total of 6 (six) Megathyst class rigs were originally planned specifically for deepwater operations in Brazil for Petrobras and development drilling operations. Because of market conditions at the time, only 4 (four) units were built and all are deployed in close proximity of each other in Brazil.

This paper describes the benefits of a rig design that was very much influenced by the client and tailored to the client's operational needs. It gives an overview of the unique rig design, specifications and characteristics that favour and are tailored to the clients long range development programs in the mid range deepwater areas. It covers a total of 19 rig years of operational experience and optimization towards operational excellence.
Remote Operations, the Future of Drilling: Directional Drilling Remote Control
Authors: Gorgone Ignacio , Gomez Juan , Uddenberg Gary
Published: March 2008

As demand for sophisticated drilling technologies has grown rapidly in recent years, the implementation of collaborative centers to improve real-time decision making has become an increasingly attractive option. Emerging technologies now enable real-time transmission of data and voice communications to and from the most remote locations, making it possible to receive and send intelligent commands and respond rapidly to changing circumstances while drilling is in progress. With the proper use of these technologies, it is now possible for a single team of expert personnel to monitor and control multiple complex directional drilling operations from a single remote office.

In the last few years, Schlumberger has created a growing number of collaborative centers to work closely with operators throughout the world. Currently, surface and logging data are transmitted to these centers in real time as part of the drilling optimization process, and real-time data has also been used for completion monitoring and control.

Coinciding with the development of the Operations Support Centers (OSC™) concept, drilling activity increased more quickly than experts could be developed in key areas of operation and support. In such a challenging business environment, the idea of having experts gathered in one room to advise jointly on several simultaneous rig operations has won wide acceptance with the companies which have tried it.

Operations centers, therefore, have become the chief venue for collaboration, data capture, sharing and training, in a way that better meets the needs of fast-growing operations. In particular, the OSC™ concept has made it possible in many cases to reduce crew and support requirements, a significant benefit in today's tightly budgeted operations.

This paper describes the challenges faced in implementing a further step in operations support center, the work process that allows one directional driller and one measurement-while-drilling engineer to control directional drilling operations at several rigs simultaneously, and details the necessary infrastructure, communication systems and operating results. It also provides an insight into the process through a recent project in northern Mexico.
Experimental Study and Modeling of Yield Power-Law Fluid Flow in Annuli with Drillpipe Rotation
Authors: Ahmed Ramadan , Miska Stefan
Published: March 2008

Helical flow of non-Newtonian fluids in concentric and eccentric annuli is of great interest in oil/gas well drilling. Experimental results and field measurements demonstrated that frictional pressure loss in the annulus can be affected substantially by the rotation of the drillpipe. Previous studies indicated that the influence of pipe rotation on annular friction pressure loss is affected by fluid properties, flow regime, annular diameter ratio and eccentricity.

This article presents results of in-depth experimental and theoretical investigations conducted on the flow of yield power law (Herschel Buckley) fluids in concentric and eccentric annuli with pipe rotation. The aim of this study is to develop a reliable hydraulic model that accounts for the effect of pipe rotation in annular pressure loss calculations.

Extensive flow experiments with polymer-based fluids were carried out using a newly developed testing facility. Four different annular geometries have been considered for the investigation. Five different formulations of test fluid were prepared by varying concentrations of Xanthan Gum (XG) and Polyanionic Cellulose (PAC) for each annular geometry. Accurate fluid characterization was made using the horizontal pipe sections and a rotational viscometer. In addition to the experimental work, theoretical analysis of helical flows in concentric annuli was carried out.

Experimental results indicate the strong presence of shear thinning and inertial effects when inner pipe rotates. In highly eccentric annuli, inertial effects dominate the phenomenon of shear thinning and result in increased pressure loss as the speed increases. Inertial effects can be generated due eccentricity and/or geometric irregularities of the annulus that substantially influence the velocity field as the pipe rotates. The experimental measurements and theoretical analysis presented in this investigation are very useful for hydraulic program optimization and well control, particularly for managed pressure drilling (MPD) operations.
Troll West Oilfield Development—How a Giant Gas Field Became the Largest Oil Field in the NCS through Innovative Field and Technology Development
Authors: Jones Richard Dyve , Saeverhagen Erland , Thorsen Arve K. , Gard Sveinung
Published: March 2008

The Troll West Oil Field has been, and still is, developed with more than 110 horizontal sub sea wells including 53 multi lateral wells (MLT). Several of the MLT wells have over time been designed and drilled with multiple open hole sidetracks to increase drainage area for each wellhead.

The Troll West Oil Field has been developed from the first test wells drilled in 1984 and 1986, with oil production on stream in 1994 and continuous development still ongoing. The commercial oil reserves on the field have gone from 0 in 1986 to more than 1,400 million barrels today1.

To be able to achieve this tremendous economical upside, the thin oil rim has been developed through sub sea development and extensive horizontal drilling enhancement. The latest development is through extensive use of multilateral drilling and wells containing up to 7 horizontal branches. The process of drilling the MLT wells and the benefit and risk evaluation for the MLT process is discussed and illustrated in this paper.

The additional drainage area gained from open hole sidetracks are delivering additional production to each well head. The unique method used for the open hole sidetracks has proved to be a low risk strategy and highly economical way to get access to additional reserves thus reducing the need for additional sub-sea templates on the field.

This paper shows how the field and technology development has evolved over the last two decades and plans going forward to continue strengthening the Troll West Oil Field production for another 15 years+ prior to the gas drainage. The upcoming technologies are incorporating both drilling and Logging-While-Drilling technologies to enhance the understanding of the mechanics behind the field development.
How Effective is Current Solids Control Equipment for Drilling Fluids Weighted with Micron-Sized Weight Material?
Authors: Massam Jarrod , Stocks Shannon , Oakley Doug , Bremner Colin
Published: March 2008

Centrifuges and shakers are the first defense when managing a drilling fluid against wellbore cuttings and solids contamination. The buildup of drill solids in a fluid can have a detrimental effect on its performance and properties. Much of the solids-control equipment in the field was designed with conventional API-grade weighted fluids in mind, but the increasing use of drilling fluids in the field weighted with micron sized particles has presented a challenge in the use of existing solids-control technologies to achieve effective solids removal.

With a decanting centrifuge, the particle size and density of API-grade barite is such that the centrifugal force tends to remove much of it from the fluid together with the undesired solids. Similarly, the wire mesh size for shaker screens is selected to be effective in removing the cuttings, but consequently, the coarser fraction of the weight material is removed. A significant reduction in weight material particle size has the potential to demonstrate a different behavior. This paper will present data obtained from both the field and from specifically designed yard tests conducted on micronized weighted drilling fluids.

The data discusses solids removal efficiency using different centrifuge designs as well as shaker screen performance, and demonstrates how these can be optimized for the preferential removal of undesirable contaminants and minimize removal of the desired weight material. The operating parameters of the centrifuge have been defined to provide the optimum solids removal efficiency.

Solids analysis, particle size and density results that provide definitive centrifuge parameters for processing fluid weighted with micron-sized material; the results are compared with those parameters obtained from a conventional API-barite weighted fluid showing that lower torque, higher throughputs and lower wear and tear on equipment can be achieved with micronized weighted fluids.
Analysis of Control Lines Strapped to Tubing
Authors: Mitchell Robert F , Ellis S. T. , Siappas G. , Colyer A.
Published: March 2008

Hydraulic control lines are commonly used to actuate surface controlled sub-surface safety valves, and new applications include choke operation and the control of more complex "smartwell" completions. In general, control lines are not subject to routine failures. However, the analysis of world wide completion failures indicates control lines to be a critical component of failure. In fact, control lines and associated components such as clamps and fittings, are not engineered with the same rigor as the rest of the well completion.

The first step in understanding control line failure is predicting the loads and stresses in a control line strapped to the tubing. Tubing movement causes loads in the control line through stretching and bending. To a lesser degree, the tubing is loaded by the control lines. To determine this interaction, a calculation is performed where the control line and the tubing are treated as a composite, with axial displacement constrained to be the same in both. This analysis provides the average stress state in the control line. Because the control line is fixed at only certain points along the tubing, the variation in stress from the average must be determined between clamps. This paper provides the technical details for both calculations.

Several example cases based on field data are presented that give insight into the potential problems that typical production scenarios create for control lines.
Investigation of Factors for Strengthening a Wellbore by Propping Fractures
Authors: Wang Hong (Max) , Soliman Mohamed Y. , Towler Brian F.
Published: March 2008

Wellbore strengthening or stress cage implementation has been recognized as an effective means of dealing with lost circulation during drilling operations. One of the mechanisms developed for strengthening a wellbore has been to prop induced and existing fractures with particulate lost circulation materials (LCM) to effectively increase hoop stress in the near wellbore region.

However, a good understanding of this mechanism is necessary in order to avoid a potentially flawed design and implementation process which could adversely affect job success in the field. One of the main issues is fracture stability under the strengthening conditions. This paper will describe those factors which are important in designing wellbore strengthening jobs and address the conditions necessary to ensure fracture stability, as determined through rock mechanics analysis.

The strengthening of a wellbore by propping fractures has been discussed in a previous investigation.1 In this paper, continuing the previous discussion, various parameters that affect the strengthening of the wellbore are addressed in detail. In-depth discussion of how each of those parameters affects the process of wellbore strengthening is presented. This study was accomplished using a boundary element numerical simulator to facilitate the analyses.
Shallow Hazards Planning in Nigeria Deepwater—Erha-7 Well
Authors: Garcia E. M. , Akers T. J. , Holster J.
Published: March 2008

The Erha-7 well is a deepwater exploration well that was ultimately drilled with a dynamically-positioned rig in 1,074 m water depth within Nigeria's Offshore Mining License (OML) 133 (formerly OPL-209).

During the early well planning process, the site investigation team identified numerous, extensive shallow hazards stacked in the area surrounding the Erha-7 geologic targets. These hazards were evaluated by the drill team, site investigation team, and the business unit to optimize the well location and minimize the risk of encountering shallow gas-charged sands.

The final well location allowed vertical drilling of the riserless conductor-hole interval and required directional drilling below the conductor to intersect vertically stacked geologic targets. Because of the close proximity to numerous shallow hazards and the limited seismic resolution, the final well location was still deemed to possess a moderate risk of encountering gas-charged shallow sands.

This paper discusses the shallow hazards planning involved with the Erha-7 deepwater well. It summarizes the limited industry experience regarding deepwater shallow gas flows and the associated safety considerations. The paper presents the modeling and evaluation of shallow gas flows and dynamic kills used to quantify the potential benefits of drilling a pilot hole, and discusses the sensitivities associated with performing an effective dynamic kill. Finally, a discussion of the dynamic kill plans developed to prevent and effectively mitigate a shallow gas flow.
Successful Drilling Management of Mass Transport Complexes (MTC's) in Deepwater Angola
Authors: Elieff B. A. , Page C. G. , Gupta V.
Published: March 2008

Esso Exploration Angola (Block 15) Limited (EEAL), along with concessionaire Sonangol and co-venturers ENI, BP, and Statoil, are developing several fields in Angola Block 15 (AB 15). Many of the extended reach AB 15 wells have experienced non-productive time (NPT) related to wellbore instability in intervals with shale referred to as Mass Transport Complexes (MTCs). This paper describes the changes made in well design and operational practices that allowed the operator to significantly reduce trouble costs associated with the MTCs.

In late 2006, EEAL, the operating team, and ExxonMobil Upstream Research Company began a campaign to reduce NPT related to wellbore instability, which accounted for 18% of AB 15 rig time in 2006. Numerous changes were made in well design and operational practices including modification of directional trajectories to reduce exposure to MTCs, improved management of wellbore pressure to maintain shale stability, and enhancement of hole cleaning practices in wellbores where significant enlargement could not be prevented. Real-time surveillance practices were also improved to ensure wellbore breakout was detected earlier and corrective measures taken quickly.

Because of the study and changes in practices, the NPT related to wellbore instability decreased from an average of 18.1% of rig time in 2006 to 3.4% in the first three quarters of 2007.
The Use of Multilateral Well Designs for Improved Recovery in Heavy Oil Reservoirs
Authors: Fipke Steven , Celli Adriano
Published: March 2008

There are now a variety of ways to achieve higher recovery factors from heavy oil reservoirs, but most of them involve the injection of thermal energy or chemicals to reduce the oil viscosity. While these techniques have been highly successful, they can also be very expensive when the steam generation and/or chemical injection costs are accumulated throughout the productive life of the field. A lower cost solution, one that has been very successful in the Faja Del Orinoco of Eastern Venezuela, is to use multi-branched wells (multilaterals) to increase reservoir exposure and achieve an arguably higher recovery factor. These multilateral wells have been shown to produce more oil over a longer period of time than conventional horizontal wells without any additional operating costs.

This paper will discuss the concept of using multilateral wells as an alternative to conventional Enhanced Oil Recovery (EOR) techniques in heavy oil reservoirs. It will argue that the oil recovery factor of a reservoir that is drilled with increased wellbore exposure can be comparable to thermal/chemical EOR under the right circumstances, and that the project will have a much lower operating cost. While steam injection has become the successful mainstay of most EOR projects, there are many drawbacks such as the costs of the steam generation and the emission of greenhouse gases. Multilateral wells can potentially offer an option to produce the same reservoir with lower costs while still recovering an increased percentage of the oil from the reservoir. This technique is especially applicable in inter-bedded or thin oil zones where steam injection would be costly and inefficient.

Extensive background information will be presented from the Orinoco belt in Venezuela, where multilateral wells have proven to be an economical approach to develop a very challenging "extra-heavy" oil reservoir.
Reexamination of PDC Bit Walk in Directional and Horizontal Wells
Authors: Chen S. , Collins G. J. , Thomas M. B.
Published: March 2008

This paper describes several mechanisms of PDC bit walk in directional wells drilled by steerable systems and how these mechanisms can be numerically modeled. The developed computer model calculates bit walk rate and walk force with consideration for bit gauge geometry, hole size, formation compressive strength, steering mechanism of the RSS, bit rotational speed, penetration rate and dogleg severity.

Application of the model in Alaskan horizontal wells has revealed that an oversized hole and the bit tilt motion are major causes of the bit walk. A matched bit/RSS system is then provided and the results are very successful: bit walk to the right is avoided and bit steerability is increased significantly.
Total BHA Reliability— An Improved Method to Measure Success
Authors: Brehme Jost , Travis John T. (Tim)
Published: March 2008

Mean Time Between Failure (MTBF) has been a traditional measure of equipment reliability. In the drilling industry, MTBFs of some downhole directional drilling tools are exceeding 1,000 hours, indicating downhole tools have become more reliable and suggesting that tool failures are an unlikely event.

In 2005, ExxonMobil Development Company – Drilling initiated a study on Rotary Steerable System (RSS) and Formation Evaluation (FE) tool failures. Analysis indicated that globally, every third Bottomhole Assembly (BHA) was pulled because of an equipment-related failure. These results did not match the MTBF numbers provided from the service sector.

Further analysis indicated that MTBF is a good metric for a manufacturer to classify the statistical reliability of individual components in a consistent operations environment. However, it is not a good metric for measuring reliability of an entire BHA that consists of many components. As BHAs become more complex, the MTBF of single components must increase in order to maintain existing reliability of the total system.

ExxonMobil is now tracking the RSS performance by run success. This approach favors a total system strategy where each BHA component is evaluated based on its ability to optimize the reliability of the entire BHA.

The four elements of this strategy are: Develop and maintain a reliable data base with defined global input to scale the problemImplement a vendor assessment program to verify that suppliers have a global systematic approach to train staff and maintain toolsAlign with suppliers about realistic load factors and operational envelopes for their toolsTrain users how to select and operate tools for a given application

The goal of the initiative is to have the best tools used in the correct application within drilling parameters that do not exceed the tool design. With this achieved, ExxonMobil expects to see a decrease in failures and reduction in cost not only to the organization but to the service providers as well.
A Novel Heat-Activated RSF to Treat Severe Cases of Lost Circulation: Case Histories from Mexico
Authors: Tirado Guillermo , Pliego Cesar Augusto , Rendon Ariel , Fowler Ian , Marin Jesus , Ramirez Hector Benito , Soriano Eduardo
Published: March 2008

Lost circulation during drilling operations is a costly problem that has plagued the oil and gas industry from its earliest beginnings. Drilling fluids are lost to the formation when the well is drilled overbalanced through high-permeability, fractured, or easily fractured formations. In many cases, total loss of circulation is experienced, and all drilling fluids are lost to the formation with zero returns to surface. This makes cementing casing strings and liners adequately into place difficult.

A range of commonly used conventional lost-circulation materials (LCMs) is available to combat lost circulation. These can be very effective in cases of low permeability or formations with small fractures where cement placement in the loss zone is relatively simple. However, in cases of severe or total lost circulation, the use of these conventional LCMs can often be ineffective. In such cases, attempts are made to stop the losses with the placement of dedicated lost-circulation treatments. These dedicated treatments include specialty cements, gel plugs, or even ordinary cement. However, severe cases of lost circulation continue to be a challenging problem.

This paper discusses field applications in a number of wells in the Burgos Basin of Mexico. A temperature-activated, rigid-setting fluid composition was developed specifically to address the most severe cases of lost circulation. In each of the wells presented, total lost circulation was encountered and treated successfully, allowing drilling operations to resume and the wells to be drilled to the designed depth. This paper details the specific chemical and mechanical characteristics and field performance of the rigid-setting fluid (RSF). It concludes that the combination of unique fluid properties and best practices in fluid placement procedures resulted in a very positive and successful development in the treatment of severe cases of lost circulation in sandstone formations.
Building and Testing a Battery-Operated Subsea Shut-Off System
Authors: Bamford A. S. , Mowat C. A. , Wickramaratne L. S. , Teixeira M. A.
Published: March 2008

A deepwater exploration drilling system has been designed (Leach and Bamford 2005) to deploy a slim, one trip riser from a mono-hull vessel using jetted-in conductor. To deploy the subsea shut-off system from a lightweight monohull vessel it must weigh less than 30 t.

Accumulators become inefficient with increasing water depth as their size and weight needed to store a given quantity of energy increases.

The need for a rapid and reliable method of disconnecting the riser lead to the development and testing of a battery powered shear ram system. Batteries also power the alternative annular cutting tool pipe severance method. This provides an even radial cut for full bore re-entry compared with the belled over profile of sheared pipe.

A prototype subsea pod was built consisting of military specification batteries connected to an electric motor and variable displacement hydraulic pump. By the direct supply of hydraulic fluid to and from the shear rams, high pressure Stack Plate Mounted (SPM) valves are removed from the control system. The resulting high power to weight ratio enabled the pod weight to be kept around 500 kg.

Successful and repeated shear tests were conducted on concentric 194 mm (7–5/8 in) and 140 mm (5–1/2 in) casings with a small battery set without recharge. The results are presented here.

The four pod subsea control system was developed with Triple Modular Redundancy (TMR) architecture. This provides a high degree of reliability and ensures that spurious signals to disconnect are ignored.

It was concluded that a reliable, battery powered subsea pod can operate over the design life of a 100 days well and be charged in-situ using a Remotely Operated Vehicle (ROV).
Cement Slurry Performance and Set Cement Properties vs. Microsilica Densification
Authors: Daou Fatma , Piot Bernard
Published: March 2008

Microsilica is the extremely fine noncrystalline silica obtained in electric furnaces as a byproduct in the manufacture of elemental silicon and ferrosilicon alloys. This waste material, also improperly called silica fume, is available in different grades of various handling characteristics. It has been used for years as cement admixture both in the oil field and in construction and civil engineering industries. Because of its extremely fine nature and high reactivity as a pozzolanic material, microsilica has been used to improve slurry stability and the mechanical properties of the hardened material.

This paper reviews typical uses of microsilica in oilfield cements. Particular attention is given to the influence of material grade, in terms of degree of densification, on slurry behavior and set cement properties. The physical properties of microsilica tested include specific gravity, loose and compacted bulk densities, and particle size distribution before and after being submitted to an ultrasonic treatment. Slurry behavior is evaluated in terms of rheology and stability.

The observation of set microsilica cement microstructure with a scanning electron microscope coupled with an energy dispersive spectrometer clarifies the question concerning the dispersability of densified microsilica in cement slurry. An unambiguous correlation between physical properties of microsilica, slurry performance, and set cement morphology is then established, leading the way to correctly specifying the quality of microsilica to be used in oilfield applications.

This work demonstrates that, contrary to common belief, not all grades of microsilica are equal, and that densified microsilica does not redisperse into small particles when mixed in a cement slurry. Therefore, densified grades, which are popular for their ease of handling, do not provide the performance required for adequate zonal isolation as is normally expected from microsilica slurry. In particular, densified material improves neither the slurry stability nor the set cement permeability and mechanical properties.
Zonal Isolation in Reservoir Containing CO2 and H2S
Authors: Moroni N. , Repetto C. , Ravi K.
Published: March 2008

Carbonate reservoirs are often characterized by high pressure and high content of H2S and CO2. For these reasons, drilling the reservoir is the most challenging activity of such fields and long-term zonal isolation across the reservoir section is one of the primary requirements.

In the example well considered for this study, the production liner is set at a depth of approximately 4,500 meters and the mud density is 16.2 lb/gal (1.95 g/cc). After a production liner is cemented, the well undergoes several operations such as fluid displacement, casing/liner pressure tests, stimulations, production, and injection; these operations create load on the cement sheath.

Carbonation of neat Portland cement systems in CO2 environments is well known in the industry. The carbonation is of significant concern if the CO2 can enter the cemented annulus. The surface area of the cement sheath that contacts CO2 should be minimized to help prevent carbonation. This can be achieved by reducing the permeability, preventing the formation of cracks and micro-annulus, and reducing the components in the cement sheath prone to attack from CO2.

To assure long-term sealing properties of the cement sheath during the life of the well, a cement formulation has been developed to be mechanically durable and chemically resistant to aggressive environments. The cement system discussed in this paper was designed to withstand the stresses imposed by changes of pressure regime during the well life by improving elasticity and thus helping prevent damage to the cement sheath. In addition, the potential for carbonation was limited by reducing the components in the slurry formulation that could react with CO2. Mechanical properties and resistance to CO2 environments of the cement system were tested in the laboratory.

The cement system was successfully evaluated in the yard test. Cement sheath analysis, slurry design and testing are discussed. The results presented in this work should help in the design and implementation of solutions to contain reservoir fluid and injected fluids, including in the presence of H2S and CO2.
Evaluating the True Cost of Losing a Bottomhole Assembly
Authors: Tollefsen E. , Weber A. , Crowell D. , Nagy Z.
Published: March 2008

Losing a bottom hole assembly (BHA) is one of the most costly unplanned drilling events that can occur for an operator. Time spent fishing for the lost assembly, the rig time wasted waiting on the mobilization of equipment and people, as well as the additional costs of whipstocks, cement, and directional tools significantly increase the cost of a well and often results in exceeding the approval for expenditure (AFE). The new well plan may also lead to any number of problems with tortuosity and torque-and-drag farther down the wellbore. Typically, these expenses are invoiced individually, obscuring the cumulative cost to reach the same true vertical depth (TVD) as the stuck assembly.

Often, one of the largest invoices the operator receives during a stuck BHA event is the replacement cost of the logging while drilling (LWD) technology. This large expense does much to disguise the other costs of sidetracking, leading many operators to consider the risk of losing a high technology LWD tool far greater than the benefits of running it in the hole.

As well difficulty increases and the risk of a stuck pipe event grows, operators become hesitant to run larger LWD tool strings in the hole. Unfortunately, this mentality creates a paradox. Many of the new LWD technologies including annular pressure while drilling, formation pressure while drilling, sonic while drilling and seismic while drilling are capable of significantly reducing the risk of a lost-in-hole (LIH) event. In the event this technology is LIH, the additional information to analyze and replan the new wellbore can prove to be invaluable.

This paper will analyze data and case studies in the Gulf of Mexico (GOM) to perform a risk analysis that includes the true cost of sidetracking a well, with and without additional LWD technology in the drill string providing key real-time measurements.
Requirements for a Full Drill through Subsea Wellhead and Tree System
Authors: Lewis Sterling , Suter Jay
Published: March 2008

This paper describes the requirements realized in the development of a full drill through subsea wellhead and tree specification. Drill through wellhead and tree systems provide an opportunity for capital and operating expense savings. Given a target development, definition of requirements determines potential savings, performance, and necessary contingencies.

Current industry practice considers both slim bore and drill through wellheads and trees. However, operational interfaces may not be fully apparent. The case considered is an 18¾-in. wellhead with a 13⅝-in. nominal hanger bore. The system interfaces a standard 21-in. outside diameter riser and an 18¾-in. horizontal subsea tree. The full drill through system is capable of drilling out and running a 10¾-in. casing and installation of the lower and upper completion with the subsea tree installed.

Primary design considerations include the casing program, sequence of operations, protection of seal bores, and primary and contingency operations. Seal surface protection is important for the reduced wellhead bore design. The reduced bore increases the exposure of casing hanger and running tool seal areas. Normally, primary operations take place through the tree; however, contingencies must consider operations without the tree installed. Thorough understanding of the requirements achieves an optimized drill through system.