bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Azimuthal Gamma at Bit Imaging Tool for Geosteering Thin Reservoirs
Authors: Pitcher J. , Schafer D. , Botterell P.
Published: March 2009

A new, azimuthally sensitive gamma-at-bit imaging tool has been designed for use in geosteering and to provide gamma measurements very close to the bit while drilling. It uses binned azimuthal measurements from four scintillation gamma ray detectors spaced at ninety degrees around the collar. Continuous image logs are recorded and telemetered to the main LWD string and ultimately in compressed form to the surface, whether the tool is sliding or rotating. When rotating, data can be recorded in quadrants, octants, or hexadecants. When sliding, quadrant data is recorded. Typically, quadrant data is compressed and sent to the surface in real time, although other data densities are possible. These features are lacking in traditional gamma tools.

This paper discusses the newly released gamma-at-bit imaging tool and its incorporation in an adjustable bent housing motor. Methodology and experiences are discussed for transmitting the data back to the main logging-while-drilling (LWD) string and to the surface. A field example is presented to demonstrate the geosteering capabilities of this system in a thin reservoir within a complex geological environment. The natural gamma ray image is also discussed as a valuable descriptor of the reservoir. The new geosteering tool exemplifies the success that can be achieved with a high-quality gamma ray image, close to the bit, to address the vital necessity for wellbores to enter a thin reservoir and to remain within it for an extended reach.
Quantitative Formation Damage Evaluation Using Dynamic/Static Drill-In Fluid Filtration Tests Data
Authors: Jin L.
Published: March 2009

Quantifying near well-bore formation damage by drilling and completion fluids at dynamic and static conditions is very important for a field development drilling and completion concept selection. This paper presents an evaluation methodology that combines results from dynamic/static filtration tests, returned permeability tests, and SEM tests on real cores with actual exposure time to fluids during drilling and completion into a well performance model to establish an invasion profile along the open hole section to quantify the impact on the productivity of the well.

A systematic laboratory test was conducted to evaluate the tolerance of a gas reservoir to damage by various mud systems. One water based system (WBM), two invert emulsion systems (OBM), a pure oil mud, a pure oil, and a pure oil emulsion were tested on real gas reservoir cores.

The water-based mud gave high return permeability, suggesting that filter cake lift-off alone is sufficient for the well clean up. This was supported by the good productivity from two appraisal wells that used a WBM. Test results showed that the OBM is more damaging due to the wettability change. This hypothesis is further strengthened as pure oil and pure old mud both provided good return permeability. SEM tests on the damaged cores indicate no particle invasion. Modeling results indicate that the well can tolerate the invasion by self-lifting off the mud cake. The WBM was therefore selected.

It is demonstrated that the methodology empowers the quantitative evaluation of near wellbore formation damage. As an example, the Changbei gas wells drilled with WBM can be self-cleaned-up that is confirmed by better than expected well performance.
Trials and Tribulations of a Long-Reach Well in the Deepwater GOM
Authors: Day Ron , Fisher Ramsey , Plutt Louise Jacobsen , Pardo Nesny , Jebutu Segun , Freitag Hans-Christian
Published: March 2009

Where the water-bottom topography is irregular, sub-sea infrastructure can often be placed in only a few locations above an offshore field. This can constrain access to reservoir targets, particularly when there are drilling challenges above the reservoir, like pressure ramps or layers with unstable lithologies. Given the size of this field, long stepouts are required. This paper presents the strategies implemented to successfully drill and access reservoirs in a large faulted anticline in the deepwater Gulf of Mexico (GOM).

The well in question faced three challenges. First, the well would be the longest stepout (~7,400 ft of lateral stepout over ~10,000 ft of vertical depth) drilled to date in the field. Second, the well would target a fault block in a portion of the field that was poorly constrained due to limited offset well control and a poorer-than-normal quality seismic image. Third, the well would face several wellbore integrity challenges in the form of two pressure ramps, an interval prone to borehole instability and one pressure regression.

Wellbore integrity management made use of real-time equivalent circulating density (ECD) and bulk-density to optimize drilling, monitor borehole stability and limit formation damage. After drilling to total depth (TD), log formation pressure and imagelog (dipmeter) data would confirm that the well had crossed an unexpected fault in the targeted reservoir section, which caused one of the target reservoirs to be absent. The team quickly reacted to the result, evaluated a recently acquired seismic dataset, updated the structural model, examined the options and successfully drilled a sidetrack.

Utilizing long step-out wells, though challenging, is the only viable alternative to access difficult-to-reach deepwater reservoir targets. Improved wellbore placement was achieved at reduced drilling risk based on real-time formation evaluation, informed decisions on optimal drilling parameters, and the continuous evolution of the reservoir model while drilling.
The Evolution of Rotary Steerable Practices to Drill Faster, Safer and Cheaper Deepwater Salt Sections in the Gulf of Mexico
Authors: Aburto Marco , Clyde Robert
Published: March 2009

The North American Gulf Coast offshore continental basin was formed following the breakup of the super continent Pangaea at the end of the Permian period and contains one of the largest known deposits of salt in the world. The salt encountered in this region is relatively soft, with negligible porosity, and may deform under temperature and pressure. Drilling salt in different regions requires different drilling practices and challenges. Because of the variable range of salt properties and because of salt's effect on nonproductive time, to date there has been no substitute for experience for successful salt drilling.

The petroleum industry is continually pushing to drill longer, faster, and safer sections; salt drilling is no exception to this philosophy. The dramatic advancements in salt drilling performance over the last decade—from the use of traditional drilling practices with rotary systems, mud motors, and possibly turbines—have been used to slightly improve penetration rates. The first Schlumberger push-the-bit rotary steerable salt drilling run in the USA Gulf of Mexico was executed in 2000. Since then more than 150 runs and almost half a million feet have been drilled in salt with this type of rotary steerable system.

This paper summarizes the analysis of the Schlumberger push-the-bit rotary steerable runs in the North American Gulf of Mexico. The analysis confirms the successful drilling assembly design and drilling techniques to yield optimum salt drilling performance toward a benchmark for today's salt drilling environment.
Signal Attenuation for Electromagnetic Telemetry Systems
Authors: Schnitger Jochen , Macpherson John
Published: March 2009

Electromagnetic (EM) systems are used for MWD telemetry during drilling. The deployment of EM telemetry systems is only successful when the signal does not vanish in noise. Knowing the attenuation profile with depth of an EM signal is a helpful guide for predicting successful deployment. This paper details several case studies on the different attenuation profiles in North America.

In the case studies the actual signal strength was measured by an EM surface system at the wellsite, with a field operator logging the measurement against depth. EM signal amplitude generally attenuates exponentially against depth, although this is highly dependent on mud and formation resistivities. While modeling provides information about the expected signal tendencies (for example, the effect of casing on signal amplitudes), EM transmission is heavily influenced by many factors, among them the presence of extremely resistive thin beds in the formation and the distribution of surface resistivity. These factors are hard to include in the simulations. The case studies included here illustrate the different relationships between actual measurements and depth.

By understanding the EM signal attenuation within a region it is possible to validate and calibrate EM transmission models, so that the successful deployment of EM telemetry systems can be predicted.
Implementation of Novel Tar Casing Drilling Tool in Deepwater Gulf of Mexico
Authors: Connor John , Djamil Arifun , Lambert Kevin , Graham Tom
Published: March 2009

In late 2007, while drilling Chevron's Big Foot #3 Appraisal well in the deepwater Gulf of Mexico, an extremely mobile tar zone was encountered subsalt at ~20,800 ft. Numerous unsuccessful attempts were made to conventionally drill thru the tar to deepen the well. The tar would have to be cased off in order to continue drilling.

Conventional casing methods were considered and it was determined that - due to the extreme tar mobility - the liner would have to be drilled thru the tar. Since extreme torque was encountered while drilling with a conventional drilling BHA, a novel approach to liner drilling was pursued.

A Service Provider had recently developed a tar liner drilling tool for another Operator which allowed the concurrent running of a 11-7/8" liner while drilling oversized hole below the liner shoe utilizing a bit, motor and concentric reamer with returns taken up the inside of the casing. This tar casing drilling tool had never previously been utilized in a wellbore.

This paper will present how Chevron worked in conjunction with the other Operator, and the Service Provider, to implement the tool on three successive attempts before finally successfully casing off the tar zone 55 days after first encountering it. Details of the application of the tool, lessons learned and future tar casing drilling tool enhancements will also be presented in the paper.
Improve Drilling Performance by Controlling Risk and Reducing Non-Productive Time in a Challenging High-Temperature, High-Pressure Well
Authors: Prebensen Ole Iacob , Vidvei Svennung , Nesheim Gunvald , James Reagan , Anda Trygve
Published: March 2009

To complete a very challenging high-temperature, high-pressure (HTHP) well in the North Sea, several engineering issues needed to be resolved before commencing drilling. One of the requirements of the well was to drill without replacing the existing drill pipe on location. Changing the drillpipe specification would result in extra tripping time and a high increase in cost. As the hydraulic window was narrow, maintaining the configuration of the drill pipe limited the equivalent circulating density (ECD). At the same time, the temperature regime was high; a specific oil-based drilling fluid (OBM) with treated micronized barite (TMB) was chosen as the only solution to resolve these challenges. In combination with this specific drilling fluid, the operator decided to utilize simulation software that enabled real-time hydraulic values to be displayed during the entire HTHP operation.

The drilling fluid with micronized barite provided several benefits compared to conventional OBMs. A more conventional drilling fluid meant a significantly higher viscosity to maintain the weight material in suspension, thereby increasing the circulating pressures and ECD. As the micronized barite viscosity profile is low, even at high densities, tripping speeds were dramatically increased as compared to offset wells. This includes tripping in and out with drilling assembly and during running of casing. Furthermore, the viscosity of such a fluid enables any flow checks to be completed much faster, thereby reducing time spent. Additional benefits such as zero barite sag, low maintenance of the system and the elimination of expected circulating time to condition the fluid after a 10-day long static period were all part of this successful well completion.
Drilling Fluid Design Prevents Lost Returns by Building Integrity Continuously While Drilling in East Texas
Authors: Vaczi Kenneth B. , Estes Brent L. , Ryan James T. , Linehan Shawna M. , Mota Miguel O.
Published: March 2009

The paper describes the application of a high solids, high filtration fluid with engineered particle sizes to prevent lost returns in the operator's Trawick field. The system (referred to here as a drill-and-stress fluid (DSF)) functions by immediately arresting the growth of lost returns fractures at the bit and building the fracture closure stress (FCS) to exceed the borehole pressure. This approach is allowing an 800-ft depleted zone with a history of severe losses to be drilled without resorting to multiple discrete lost returns treatments. Protective casing has also been eliminated.

As producing fields mature, depleted intervals are drilled to access remaining reserves. This increases well complexity and cost, and the impact on economics may limit ultimate recovery, particularly in fields with high stimulation costs or low production rates. The operator faces these challenges in its Trawick drilling operations in East Texas where destabilization of shallow, weak shale following losses, and repeated treatments in the pay zone have led to stuck pipe, significantly increasing well costs as the field has matured.

In recent years, a variety of particulate treatment systems have been developed to build stress continuously. DSF differs from some systems in that it arrests fracture growth though the development of an immobile mass within the fracture rather than through the formation of a blockage at the fracture aperture. It is also relatively inexpensive. This case history is also significant because the fluid worked successfully in long intervals of very low permeability (0.1 md), which has historically been challenging for a continuous stress-building fluid.

The paper will discuss the development of the technology to allow successful application of DSF, the pilot program that validated the observed increases in integrity, and the operational learnings that were developed during the pilot program.
Well Design for Environmentally Friendly Drilling Systems: Using a Graduate Student Drilling Class Team Challenge to Identify Options for Reducing Impacts
Authors: Burnett David B. , Yu OK-Youn , Schubert Jerome Jacob
Published: March 2009

The Oil and Gas industry is becoming more adept in reducing its impact on the environment and in showing optimal use of resources. This approach to environmentally friendly drilling offers the two-fold advantage of the reduction of the footprint of drilling operations while realizing savings by reducing waste treatment, hauling and remediation costs.

The Harold Vance Department of Petroleum Engineering at Texas A&M University has incorporated an Environmentally Friendly Drilling System (EFD) design into its PE 661 graduate drilling class. The "661 Team Challenge" semester project was assigned to the students to "design a well on paper" using low impact drilling technology. A systems engineering optimization protocol approach was utilized to incorporate a number of current and emerging EFD technologies into a single clean drilling system with no or very limited environmental impact. A web-based decision optimization tool was developed to follow the systems approach technology evaluation procedure and select an optimal system. The resulting well designs were judged as to their suitability for implementation in a protected wetland on the Texas Gulf Coast.

Introduction

The Harold Vance Department of Petroleum Engineering at Texas A&M University offers a series of five graduate courses designed to introduce Petroleum Engineering to new graduate students with a limited Petroleum Engineering Background. One of these courses is PETE 661 Drilling Engineering where we teach "drilling for non-drillers". Although this course is designed for non-drillers, there are a number of students with considerable experience in drilling who take the course as a refresher or for exposure to an alternate view of Drilling Engineering.
Water Based Fluid Designed for Depleted Tight Gas Sands Eliminates NPT
Authors: Hoover Erik , Trenery John , Mullen Greg , Richards Lawrence
Published: March 2009

Unconventional gas resources offer the only significant gas production growth potential in the coming years, currently accounting for 43% of the US gas production. Tight gas represents approximately 70% of the unconventional production and significant reserves are yet to be developed. In the United States, Utah, Colorado and Texas host the vast majority of those resources. Other major potential fields are located in China, Algeria, Argentina, Indonesia and the Middle East.

Drilling in mature depleted fields can be costly in non-productive time (NPT) associated with stuck pipe, whole mud losses and side tracks. A new water-based mud system addressing depleted tight gas reservoirs has been successfully introduced to provide increased drilling performance as compared to conventional water-based mud systems. The new High Performance Water Based Mud (HPWBM) is a viable solution for onshore drilling in mature, depleted tight gas sands. This technology is applicable to any tight depleted gas reservoir where losses or stuck pipe occur.

This paper provides a technical overview of the new HPWBM performance in a technically challenging field where massive losses, stuck pipe, twist-offs and other fluid associated NPT are common. The case histories presented are from an independent operator drilling in South Texas and highlight the successes and optimized learning curve of the system as compared to offsets drilled with conventional water-based mud (WBM) and oil-based mud (OBM) systems by the operator.
Rotating Magnetic Ranging Service and Single Wire Guidance Tool Facilitates in Efficient Downhole Well Connections
Authors: Oskarsen Ray T. , Wright John W. , Fitterer Donal , Winter Dave , Nekut Anthony , Sheckler Jed
Published: March 2009

Downhole connections between multiple wellbores have applications in many operations such as extended-reach drilling, multilateral completions, subsurface pipelines, and downhole fluid separation.

An R&D project was undertaken to develop and validate an electromagnetic ranging concept for enabling cost-efficient downhole connections—namely, Rotating Magnetic Ranging Services and Single Wire Guidance. After extensive testing that found the ranging technology suitable, an existing offshore well jacket located in Southeast Asia, in 5.1 m of water and 1.3 km from shore, was identified as a good candidate for field validation of the concept. The electromagnetic-ranging technology facilitated the successful intersection of the target well according to plan, including by-pass within specified proximity (< 40 cm) and in the correct sand (+−1.5 m TVD window).

This paper discusses some of the many applications of downhole well connections. Furthermore, it explains the Rotating Magnetic Ranging Service and Single Wire Guidance ranging concept, which enables efficient downhole well connections.
Tracking Drilling Efficiency Using Hydro-Mechanical Specific Energy
Authors: Mohan Kshitij , Adil Faraaz , Samuel Robello
Published: March 2009

Over the last few years, different types of bits have been introduced to meet the challenges of steerable as well as rotary steerable systems; and it is imperative that bits be utilized optimally in these systems. As challenges increase with increasing depths, it becomes even more important for one to efficiently utilize the available energy. A new correlation identifying inefficient drilling conditions is presented in this paper. Mechanical Specific Energy (MSE) has been used to improve drilling rates, with mixed results. Hydro Mechanical Drilling Specific Energy (HMSE), which is introduced here, encompasses hydraulic as well as mechanical energy. HMSE quantifies the amount of energy required to drill a unit volume of rock and remove it from underneath the bit. HMSE includes axial, torsional, and hydraulic energy and is different from MSE because it includes a hydraulic term. The initial MSE correlation (Teale, 1964) was modified to accommodate the new hydraulic term. This paper attempts to better model downhole drilling by introducing the hydraulic energy term in the MSE correlation by defining it as hydro mechanical specific energy. While the majority of the drilling occurs because of the bit, it is a well known fact that some drilling occurs due to the "jet impact impingement" caused by the drilling fluid as well.

A comprehensive set of equations have also been developed and introduced here for hole opening scenarios.

Experimental and field data presented in this paper show that HMSE can identify inefficient drilling conditions. The new hydraulic term included in the specific energy correlation is the key to correctly match the amount of energy required to drill and overcome the strength and stresses of formation being drilled. Also, this new term illustrates how much hydraulic energy is needed to drill faster when the mechanical energy (axial and torsional) is increased. The results also show the importance of including the bit hydraulic energy term into any specific energy analysis for drilling optimization. The pump-off force for weight on the bit due to the fluid force is also included in the calculation. Field results reveal specific patterns for inefficient drilling conditions and also reveal a good correlation between calculated HMSE and the expected requirements for rock removal under existent conditions of stress at the bit face.
Development of the 18-3/4" – 20,000 psi Subsea Wellhead System for High Pressure and High Temperature Applications
Authors: McCoy Bernard , Singeetham Shiva
Published: March 2009

There is an increasing need for higher pressure and higher temperature rated equipment as wells are being drilled in such reservoirs in deep water subsea fields. This paper presents the development of the first 18-3/4" – 20,000 psi subsea wellhead system rated for 0°F to 350°F temperature applications utilizing high capacity running and specialty running tools. Included are details of the three year development project including component design, reliability analysis, and prototype testing of the equipment in the laboratory with simulated field conditions. With this technology, operators can explore fields while further completion technology is developed. This 20ksi subsea wellhead technology will enable operators to drill wells using 15ksi BOP stacks while the 20ksi BOP stack is under development. The wellhead system includes special provisions to enable annulus seal assemblies to be tested to 20ksi while isolating the BOP stack. Drilling into high pressure zones for logging or testing can be performed through a 13-5/8"-20ksi BOP stack which latches directly to the subsea wellhead. In synopsis, this paper highlights the wellhead system details utilized for extreme environments up to 350°F and up to 20,000psi working pressure. The goal of this paper is to open the industry's horizons to production fields and reservoirs that operators previously could not develop due to technological constraints such as the higher bottom hole pressures or greater well temperatures with existing subsea mudline wellhead equipment.
A Fit for Purpose Combination of Positive Displacement Motor and Rotary Steerable Systems Delivers a Step Change in Drilling Optimization in Tomoporo Field: A West Venezuela Case Study
Authors: Ochoa Danny , Palacio Julio , Akinniranye Goke , Chirinos Edween
Published: March 2009

Drilling directional wells in the Tomoporo field in western Venezuela is a challenging and risky operation. Wellbore instability, differential sticking and weak sand zones are common problems in the area. Considerable Non-Productive Time (NPT) is the result of difficult trips, poor hole quality, circulation losses and stuck pipe incidents. Under these conditions, the use of conventional positive displacement motors (PDM) escalates the risk of stuck pipe when difficult sliding and low rates of penetration increase the exposure to open hole conditions. The use of rotary steerable systems (RSS) allowed mitigating some of the hazards, but high shocks and vibrations (S&V) in laminated formations added to the harsh drilling conditions raised the number of unplanned bit trips and downhole tools damage.

A drilling assembly containing a rotary steerable tool below a specially designed, high-torque PDM provided the benefits of both conventional and RSS drilling by delivering faster rotation per minute (RPM) at the bit. The increase in RPM reduced vibration perpetuation and transmission in the rest of the drill string. The PDM dampened S&V, mitigated the effects of stick/slip and helped prevent damage to the RSS tools. The combination of PDM and RSS had a positive impact on the life of the bit and downhole tools, and resulted in an increase in both on-bottom and average rate of penetration. This approach marks a step change in performance, achieving a reduction in drilling time of approximately 50% compared to the average established for the area over the previous 5 years.

This paper will present a detailed study of this fit for purpose solution to increase footage per day mitigating shocks and vibrations and its success in dramatically reducing risk in directionally drilled wells.
Significant Step Taken to Eliminate Sustained ‘B’ Annulus Pressure in Major North Sea HPHT Development
Authors: Hunter Liz , Kinnaird Bill , Grégoire Michel
Published: March 2009

Detailed engineering analysis and good placement practices have been key in the prevention of chronic ‘B’ annulus pressure in the Central Graben HPHT area. A solution was developed based on independent life-of-well studies conducted in tandem by the cementing and oil companies which predicted the risk of sheath failure and subsequent gas migration.

Long-term isolation of the gas-bearing Hod formation has been an issue in Central Graben HPHT since earliest development, leading to costly management and maintenance of sustained ‘B’ annuli pressure. Elimination of the problem is a major challenge highlighted by plans for future sub-sea completions.

The Elgin-Franklin field is the world's largest HPHT development, so effective well design is crucial. Five clear steps were taken to achieve life-of-well isolation.

Analysis to predict failure mechanisms across all well-events were carried out with engineering programs from both the oil and cementing companies. Results were similar, identifying risk areas, the main being cement-formation debonding at the change to lightweight completion fluid. Effects on risks were investigated by altering well parameters, such as fluid weights and pressures. Most effective reductions were made by altering mechanical properties of the cement such as Young's modulus, Poisson's ratio and tensile strength. Extensive lab analysis was used to develop the best solution. A cement slurry was designed providing optimum mechanical properties. North Sea environmental restrictions were an important consideration. Triaxial measurements were made by both parties independently. A full-scale yard trial qualified the design for the field. Cement and other property enhancing additives were blended, transported and delivered to a cement unit where it was mixed on-the-fly. The large volume job was carried out with the rig cement unit, no special equipment was required. Good displacement practice meant adjustment of slurry rheologies to meet actual well conditions. The logistics of using a special blend were a consideration.

Since placement, the annulus pressure has been recorded. No abnormal pressure has occurred in 14 months since completion, during fluid change-out, or throughout high production output.
Casing Drilling 24-in. Surface Section Enables Operator to Add One Extra Slot to the Existing Drilling Template and Cut Operation Costs Offshore Congo
Authors: De Luca Stefano , Aliko Enis
Published: March 2009

Foukanda permit is situated offshore Congo to the north of Kitina platform and to the west of Pointe Noire town. The Foukanda platform comprised a drilling template with eight slots, all of which were drilled through a 30-in. conductor casing that was laid on sea-bottom and connected to the platform's drilling template, and all were directional wells.

The operator wanted to drill another well to explore another structure of the reservoir, but this was not possible with the existing template. The custom way of securing an extra slot was that which involved setting of a 30-in. diverter with 2° angle to the sea bottom, conventionally drilling some length of new hole with a 26-in. roller cone bit and then running and cementing a 20-in. casing through this 30-in. diverter and with free returns to sea bottom. This method had a negative aspect, which was the difficulty of re-entering the 26-in. hole with the 20-in. casing because of the sag of the conventional drilling assembly at the exit of the 30-in. diverter.

To resolve this problem, the operator opted for an innovative drilling technique: drilling with casing. A 24-in. casing drilling bit was manufactured on purpose and was run through the diverter on a 20-in. casing string which drilled 66 m of new formation at 2° inclination and with returns to the seabed. The casing was cemented in place and the casing drilling bit was than successfully drilled out with a roller cone bit. This operation enabled the operator to secure the extra slot, to get out of the existing wells trajectory and to save the costs associated with difficulties to re-enter the hole.

In this paper, the authors will describe the casing drilling bit technology, the planning of operations, the implementation, and the results compared to conventional drilling.
Test of a BOP/Riser Connection with an External Inflate (EI) Inflatable Packer
Authors: Vaucher D. , Parrish C. , Brooks B.
Published: March 2009

With the oil and gas industry increasingly looking for energy offshore, there will be growing costs associated with the complexity of drilling below the ocean floor in deeper water. A leak detected after latching the lower marine riser package (LMRP) in deep water can cost the rig and the energy producer up to a staggering $12 million in lost time. Clearly, there is a need to be able to test the BOP/riser connection and cap seal for pressure integrity at surface before the operator runs to depth with the LMRP.

This paper describes a procedure to test at surface for leaks inside the BOP, at the cap seal and annular seal; all connections are tested offline and, most importantly, these tests do not interfere with drilling operations. This method is also safe and economical since it uses existing, field proven equipment and can be performed in as little as half an hour.

First, the tool is inflated inside the BOP, above the cap seal. Pressure is then applied from below the tool to test this seal's integrity.

The tool can then be inverted and placed higher up in the BOP in order to test any of the BOP/riser connections. In either position, by observing the applied pressure, it is possible to confirm the presence or absence of a leak, as well as its location. A case study is presented, showing conclusive results. Testing did detect the presence of a leak, which was fixed, and subsequent test runs did in fact confirm this.
Remotely Managing a Project in a Volatile Security Environment
Authors: Al Hashmy Louayd , Assalman Waleed , Sabah Marwan , Qutob Hani
Published: March 2009

Iraq is undergoing a period of transition after the overthrow of former regime. This created a vacuum of authority throughout the entire country which has lead to a dangerous security situation, posing serious risks to a range of targets, delaying reconstruction and making it very difficult to provide any services for developing the country.

Therefore, the lack of utilities, security and basic services has forced a significant portion of the skilled workforce to leave the country. Furthermore, oil and gas industry infrastructure was in a very poor state and required tremendous support of equipment and experienced manpower.

All the above factors prevented many major oil companies from operating and introducing their technology in Iraq. On the other hand, Weatherford was firmly committed to establishing their business inside Iraq but decided to control and manage their operations remotely rather than inside Iraq. More specifically, the management team was based in Dubai to plan, manage and support operations and an established team in Iraq to follow directions from management office.

Coordination of operations was done using state-of-the-art communication systems, effective information reporting procedures and experienced technical support on the ground. Field personnel were extensively trained through class-room and interactive sessions, as well as QHSE training to comply with Weatherford standards. Finally, an integrated project management system was created to provide clients with experienced project management, well engineering expertise and the optimum technology for integrated projects to jointly create greater value in an environmentally responsible manner. The positive outcomes are better access to technology, teamwork and an alliance spirit with mutually agreed objectives.

The many successes achieved through this remote management system demonstrate the effectiveness of Weatherford's approach in tackling the challenges of operating in a volatile security environment such as Iraq.
Development and Installation of an Extended Reach Multilateral Junction
Authors: Peterson Erick , McKeever Steve , Hartwig Dennis , Eggemeyer Jerome , Ortiz Alex , Pendleton Bryan , Martens Hal
Published: March 2009

A multitude of extended reach technologies have been utilized in the West Sak field on the North Slope of Alaska to reduce surface impact in a remote and environmentally sensitive area. Significant to the shallow heavy oil West Sak development is the use of multilateral horizontal wells with a junction providing mechanical support and both through-tubing lateral isolation and re-entry capabilities. However, as extended reach drilling capabilities evolved to routinely reach departure to true vertical depth ratios in excess of five to one, multilateral junction technology did not evolve at the same pace.

A new multilateral junction was designed to match current extended reach drilling capabilities and replace existing multilateral equipment which was utilized beyond its intended limit incurring both installation and production risk. The newly designed junction allows lateral liners to overcome drag limitations by rotating the liner and junction to setting depth in one trip and includes several positive indicators to ensure a successful installation.

This paper discusses the evolution of multilateral wells in the West Sak development, the limitations of multilateral junctions when utilized in extended reach wells, the development and testing of a new multilateral junction, and several successful field installations. Operation highlights during the completion phase of a multilateral well with a lateral departure to true vertical depth ratio in excess of six to one are included. Existing tools such as oil based mud lubricants and thorough torque and drag prediction were combined with the new junction for a successful completion which progressed the application for multilateral junctions in extended reach wells
Successful Drilling of a Deviated, Ultra-HTHP Well Using a Micronised Barite Fluid
Authors: Gregoire Michel , Hodder Mike , Peng Shuangjiu , Massam Jarrod
Published: March 2009

This paper reviews the design and application of a micronised barite fluid (MBF) to drill a deviated high-temperature, high-pressure (HTHP) well in the Northern North Sea. The key technical challenge was to avoid sag of the weight material. On a previous well, using an API-barite-weighted fluid, sag had resulted in considerable non-productive time.

The various fluid options were assessed by a technical prequalification exercise which involved extensive testing for viscosity, fluid loss and barite sag under simulated downhole conditions. The MBF was used to drill the 8½-in. section from 6,354 to 7,327 m; the deviation at the 9⅝-in. casing being 42 degrees. The bottomhole static temperature (BHST) was 205°C and maximum mud weight 2.15 sg.

The well was successfully drilled to TD, but two stuck-pipe incidents necessitated sidetracks. Despite these operational incidents, no significant sag occurred, and as a result, considerable time savings were achieved on flow checks, trips, and cementing operations and the required logging program could be performed.
Surface BOP System Operational Experience Offshore Brazil in 1,900 m of Water
Authors: Tarr B. A. , Taklo T. , Hudson A. , Stockwell L. , Schroeder J.
Published: March 2009

This paper presents the recent operational experience using a surface BOP system for both drilling and subsea completion activities offshore Brazil in the first phase of the Parque das Conchas development (block BC-10) that encompasses several reservoirs in up to 2,000 m of water.

The Transocean GSF Arctic I, a moored rig capable of operating in 945 m of water using a conventional 18-3/4" subsea BOP stack and marine riser system was equipped with a pre-laid mooring system and surface BOP system especially designed for this project that could extended the rig's effective water depth capacity to as much as 2,250 m.

Prior to the start of drilling operations a service vessel was used to pre-install the conductors for both the wells and the subsea pumps. In addition to taking these activities off the critical path, the precision achieved by using a subsea hammer to install the well conductors at each drill center minimized the time required to move from well to well for batch drilling and completion operations.

The start up performance and learning's from the following new elements used in this project will be presented: Site specific pre-laid polyester taut-leg mooring systemSlim-bore wellhead system (to land production casing hanger)Purpose built 16" OD high pressure riser systemPressure test hose line, strapped to riser (to press. test tubing hanger & packer)Lower shear ram in SID replaced with fixed 7-5/8" pipe ram (to seal on slick joint)Power and hydraulic lines added into the SID umbilical (to reduced ROV support needed)Vertical subsea tree, Tubing Head Spool and slim bore tubing hanger with hydraulic running toolSpacer Spool (same height as Tubing Head Spool)

The start up performance of this uniquely equipped rig system will be presented to show how attention to detail and a strong learning culture have paid handsome dividends.
Maintaining Steerability While Extending Gauge Length to Manage Whirl
Authors: Dupriest Fred E. , Sowers Steven F.
Published: March 2009

This paper discusses the results of a global campaign to increase the length of the gauge area of bits used on rotary steerable systems (RSS) to mitigate bit whirl and its undesirable effects. The desired steerability was achieved with lengths in excess of 4 in. with all RSS tools utilized. The modifications have resulted in reduced vibrations, significant improvement in drill rate, improved borehole quality, and reduced tool damage.

When the operator's performance management process was implemented, real-time and post drill analysis of mechanical specific energy suggested 40% of footage drilled worldwide was affected by bit whirl or lateral instability. One element in the programmatic response was an initiative beginning in 2006 to extend bit gauge lengths to constrain side-cutting and reduce the amplitude of whirl-induced patterns. The value of extended gauge lengths has been demonstrated in numerous papers, but field implementation by the industry has not been uniform, and a significant issue has been concern that steerability would be reduced. The purpose of the initiative was to demonstrate that common build rates could be achieved with all RSS tools used by the operator with bits having a minimum gauge length of 4 in. In the subject wells over a two year period normal build rates (3-5 deg/100 ft) were not affected with 4-in. gauges if the profile and aggressiveness were properly designed. The gauge profiles used to maintain steerability included full taper, full undercut, and partial undercut. While the desired steerability was achieved with both point-the-bit and push-the-bit RSS tools, specific modification required in the gauge profile varied with the RSS used, desired build rate, and drilling environment. Drill rate performance and bit life also improved, but this was partly attributed to implementation of the performance management process and specific rig crew training. Extension of the gauge length is also known to benefit bent motor operations5, but the effects of various gauge profiles are less certain and motor operations are not discussed in this paper.

The objective was not to determine the maximum build rates achievable, but to simply confirm that gauge lengths of 4 in. or greater could be used as standard practice in normal operations. This paper discusses the rationale for use of extended gauges, the modified profiles used to maintain steerability with various RSS tools, and the field performance achieved.
Dry Dope-Free OCTG Connections: A Novel Environmentally Friendly Technology Validated Through Diverse and Severe Field Conditions
Authors: Castiñeiras T. , Núñez A. , Gallo E. , Carcagno G.
Published: March 2009

The development of dope-free alternatives to standard thread compounds used for the assembling of OCTG connections (tubing & casing) started in the late 90's when some initial solutions were tried, being really commercially available from late 2003. The challenges from the galling resistance needs, as well as the handling and storage requirements, were addressed and the lessons learnt from initial uses and experiences were incorporated to define products that are reliable and have proven the suitability in different environments as those from the extremely humid and cold Barents Sea conditions to the sandy and hot environment in the Middle East. The extension and diversity of the uses and experiences collected today allows not only to confirm the validity of initial drivers for the development of this alternative, mainly related to the environmental care, but to detect and confirm additional benefits from the possibility of complete elimination of thread compound from the casing and tubing installation and storage process.

The dope-free solution demonstrated suitability for application in all tubing and casing dimensional ranges, and for all type of steels as common carbon steel (both API grades and proprietary), 13Cr, and Corrosion Resistance Alloys (CRA), in premium connections with metal-to metal seal, and big-OD semi-premium connections.

This paper describes the different experiences related to the field use of a fully-dry dope-free solution, the improvements and adjustments incorporated after initial experiences and operators feedback, the verification activities in laboratory, and especially in experimental rigs under actual field conditions, and summarizes the advantages and the value added through the use of this type of technology.
Targeting Challenges in Northern Areas Due to Degradation of Wellbore Positioning Accuracy
Authors: Bang J. , Torkildsen T. , Bruun B. T. , Hâvardstein S. T.
Published: March 2009

The surveyed position accuracy degrades when one approaches the magnetic and geographical poles. Both magnetic and gyroscopic tools are affected. We have analyzed the accuracy of several magnetic and gyroscopic services in a number of representative synthetic wellbores. Locations representative for the North Sea and the Barents Sea are chosen. The results show that an increase in horizontal target dimension by a factor of 2 is necessary when moving from 60°N to 75°N, to maintain the same hitting probability.

Examples of areas which may be affected by these findings, are: target design, well planning, surveying programs and practices, anti-collision criteria, and the ability to drill relief wells.
Pull Your BOP Stack—Or Not? A Systematic Method to Making This Multi-Million Dollar Decision
Authors: Sattler Jeff
Published: March 2009

Category: Deepwater Drilling or Case Studies

Pulling your BOP stack, particularly in deep water, is one of the singularly most costly events in the drilling of a well if it occurs. While in most cases this course of action is correctly undertaken, occasions occur when the stack pull could have been avoided. These regrettable incidents occur for a variety of reasons, including inadequate information and/or staff training, unclear understanding of regulatory or company requirements, and non-availability of experts to assist in the decision making due to time zone differences, among others.

This paper presents several case studies where planned stack pulls were circumvented or could have been, as well as a systematic protocol that can be developed prior to starting a well to define the decision making process for stack pulls for your specific program.
Drilling and Completing the First U.S. Offshore Gas Storage Wells in Mississippi Sound, Offshore Alabama
Authors: Fulks Robert , Cagle Douglas O.
Published: March 2009

In 2006 Falcon Gas Storage Company concluded a study of the Dauphin sands in the shallow waters of Mississippi Sound, Alabama. The study was conducted to determine if the depleted reservoir could be used as a gas storage facility. With preliminary seismic analysis indicating a suitable closed structure existed, further studies were done to determine the practicality of drilling and completing a series of shallow gas injection/producing wells. This paper addresses that feasibility and the subsequent well planning challenge which ensued.
Latest Enhancements in High Strength Sour Service Tubulars
Authors: Urband Bruce P. E. , Bernard Frédéric , Morey Steve , Bradley Bruce , Legay Frédéric , Marchebois Hervé , Linne Cédric , Lynn Garth
Published: March 2009

Today more deep water, high pressure high temperature (HPHT) wells are being drilled and completed in the presence of Hydrogen Sulfide (H2S), requiring an ever increasing volume of high strength ( >=110 ksi ) sour service-rated tubulars. As this trend moved forward, suppliers overcame critical metallurgy challenges to improve the original offer in 110 ksi sour service materials, extending production toward thicker products and developing dedicated products such as 110 ksi for mild sour use, or thick DST strings used in extreme HPHT wells. These metallurgy improvements also paved the way to develop 125 ksi mild sour service grades. Based on these latest enhancements, and taking the traditional API grades as historical reference, the objective of this paper is to discuss various high strength sour service tubulars, their relative applicability in well conditions, basic manufacturing techniques to optimize tubular as well as the NACE testing performed to characterize the different sulfide stress cracking properties.