bluuebunny/crossref_metadata_2025 huggingface dataset:
Lessons Learned From Treating 500,000 Tons of Oil-Based Drill Cuttings on Five Continents
Authors: Pierce D. , Gaddis C. , Wood B.
Published: December 2007

As Yogi Berra is fond of saying, "it ain't over till it's over". During any oil-based mud drill cuttings treatment project, the task is not complete until the solids are clean and permanently disposed, the oil is clean and reused, and the water is clean and recycled or discharged. The project is over when the wastes pass the auspices of the local environmental rules and are no longer an environmental risk.

Thermally desorbing the liquids from the drilled solids is the easiest part of the job. It's the little things that really make the difference between a successful project and a total failure. This is true not only for the treatment company, but also for the oil company that is generating the cuttings. In most cases for these projects to benefit all, they must be approached as a partnership between the waste generator, the treatment company and the environmental agency. Anything else can lead to problems.

Our experience covers five continents and the successful treatment of more than 500,000 tons of oil-based drill cuttings. We will share data concerning many of our projects. Some problems will tend to be light hearted while others will be more complicated. Problems have arisen due to inadequate planning while others have been born due to an interpretation of the regulations. This paper will cover topics including transporting and storing oil-base drill cuttings, the need to pre-treat for a consistent homogeneous feed, re-hydrating the dried solids and separating the liquids into useable oil and dischargeable water. All of these pre and post treatment activities have a great deal to do with the success of a project.

Understanding the complete job and having an agreement between the treatment company, the oil company and the regulatory agencies prior to beginning the project is essential. Even when you have done your homework, unexpected problems arise. We will share some of our problems and how they were overcome, thereby decreasing the environmental risks as well as the financial risks associated with oil contaminated cuttings.
An Innovative Ultradeepwater Subsea Blowout Preventer (SSBOP) Control System Using Shape Memory Alloy Actuators
Authors: Song G. , Hu Z. , Sun K. , Ma N. , Economides M. J. , Samuel R. , Ehlig-Economides C. A.
Published: December 2007

API RP16E1 mandates that minimum acceptable Blowout Preventer (BOP) control system response times are 60 seconds or less for an annular preventer and 45 seconds or less for a ram type preventer. Norsok standard2 response time for closing rams when located at seabed is 30 seconds, or 45 seconds for annuli greater than 20 inches. As drilling moves to deep water, conventional BOP actuation technologies based on full or partial hydraulics (hydraulic, electrohydraulic or multiplex electrohydraulic systems) are unable to meet this standard because of the long hydraulic fluid communication path between the offshore platform and the BOP stack on the sea floor.

This paper presents an innovative undersea Blowout Preventer (BOP) using Shape Memory Alloy. The goal of this project is to develop innovative fast-response BOPs using only Nickel Titanium (Nitinol) Shape Memory Alloy (SMA) as the actuator. Nitinol SMA has a long fatigue life and high corrosion resistance. As a solid-state actuator, it is capable of up to 5% strain recovery or 72,500 psi restoration stress with many cycles. It can be actuated by electrical heating, thereby replacing hydraulic actuation and hydraulic lines with electric cable. With significantly fewer components, the SMA system will dramatically reduce total cost and will increase operation reliability. The new device could easily be retrofitted to existing conventional subsea control system so that other methods can also be used as a backup. Most important, the innovative all-electric BOP will provide much faster response than its hydraulic counterpart and will improve safety for subsea drilling.

To demonstrate the feasibility of such a device, a proof-of-concept prototype of a BOP with SMA actuation has been designed, fabricated, and tested at University of Houston. The BOP actuator uses strands of SMA wires to achieve large force and large displacement in a remarkably small space. Experimental results demonstrate that the BOP can be activated and fully closed in less than 15 seconds. The concept of this innovative device is illustrated, and detailed comparisons of the response time for hydraulic and Nitinol SMA actuations are included. This preliminary research reveals the potential of smart material technology in subsea drilling systems.
Next-Generation Multisensor Seismic-While-Drilling Technology
Authors: Cornish B. , Deady R.
Published: December 2007

Seismic While Drilling (SWD) technology provides a means to properly locate a well path with respect to depth and seismic travel time in order that the driller can effectively guide the bit toward a seismically-defined target. SWD can also facilitate drilling decisions such as setting coring and casing points, avoiding drilling hazards, and identifying overpressure-zones .

Accurate and reliable SWD tools must address at least two main issues: sensor coupling/fidelity, and precision timing. These issues must be addressed within the framework of the drilling environment, whose rigors impose significant constraints on the design and mounting of the seismic sensors and on the accuracy of the clock.

A next-generation SWD tool has been developed that addresses coupling issues through the deployment of multiple, multi-axis sensors, including ruggedized geophones, seismic accelerometers, and hydrophones, in combination with a novel, highly accurate clock and contingent surface systems. This paper investigates the performance of the new tool design and presents the results of field tests and operations in which seismic data were acquired using multiple sensors and types of sensors in various types of formations and in deviated boreholes. The data acquired while drilling are compared to baseline commercial wireline VSP measurements in order to verify that the system provides accuracy comparable to that of a standard commercial wireline.
Exploration Drilling in the Russian Far East: 2 Years of Experience and Learning Offshore Sakhalin Island
Authors: Thorogood J. L. , Hogg T. W. , Kalshikov A. G.
Published: December 2007

An exploration well drilled by a joint venture between Rosneft and BP in the summer of 2004 was the first success after a long period of no exploration activity. It represented a step out into a new and untested exploration play.

Wells in Sakhalin involve a permitting cycle that lasts for 7 months and a logistical supply chain that extends 3,500 miles back to Singapore, Figure 1. The sea ice-free weather window lasts from late June until mid-November, with severe storms building from September onwards. Environmental restrictions stipulate that all mud and cuttings from below the 30" conductor, even though the well may be drilled with a water-based mud, cannot be discharged to the environment and must be recovered for disposal. Figure 1Regional setting showing Sakhalin in relation to the mobilisation point of Singapore

The team overcame a wide range of organisational, logistical, regulatory, environmental and technical challenges to drill the well in the summer of 2004. Despite the highly compressed schedule, the operation was conducted with no harm to people or damage to the environment. The lessons learned were consolidated and formed the basis for a successful season in 2005 with a different rig.
ROP Enhancement in Ultrahard Rock
Authors: Roehrlich M. , Belohlavek K.-U.
Published: December 2007

Drilling the Middle and Upper Bunter formation (Triassic) in North-West Germany has been a challenge for nearly 40 years. The Bunter is a hard and very abrasive formation, typically in a depth range of 8000ft – 12500 ft. It consists of layers of quartzitic sandstone and silificated claystone. Low ROP and extremely high wear of tools is characteristic for drilling this formation. To improve the performance and decrease cost/ft, intensive research was done in the past.

This paper deals with the results of the analysis of historical data and the development of bits, motors and other BHA components to one system. This BHA system is to enhance ROP and reduce trips due to dull bits or BHA and drillstring failure. To date, 15 runs of these improved BHA systems have been performed. Performance data have been analyzed and will be presented to document improvements achieved. An outlook for future opportunities will be given.

Drilling the Bunter is still time consuming and expensive. In the past, typical ROPs in 12 1/4" sections were 3 – 6ft/hr. Back in the 1970's and 80's, 15 to 20 insert bits were required to drill the section and reaming was necessary due to under-gauge bits. Both, low ROP and short bit life contributed to significant total section times. The combination of new impregnated bits and new downhole motors together with improved hydraulics in larger ID drillpipe were the basis for improvement. Today, with an optimized system, ROPs of 8 – 19 ft/hr have been achieved. In addition, it is now possible to drill the bunter section in one trip. Two world records, for single footage and cumulative footage of an impregnated bit are held within EMPG (German ExxonMobil affiliate) in this section.

In recent and upcoming wells, new motor developments are tested to repeat latest successful results and to further improve ROP. In addition, a different bit design will be run for further potential ROP enhancement. Significant reduction of section time justifies the application of more sophisticated and more expensive tools on German land rigs to further reduce cost/ft.
Proven Commercial Implementation of Second-Generation Integrated Remote Drilling Operations Center
Authors: Nathan E. , Dagestad J. O. , Lilleng T. , Pedersen T.
Published: December 2007

One recent management trend is the establishment of onshore operations centers by oilfield operators that are currently developing offshore assets. Unfortunately, the formation of such a center has typically been a niche activity within many companies and, as a result, some may fail to consider the lessons learned from earlier operation center failures. It is also vital that those attempting to develop such a center make sure the center's purpose functions within the industry's overall framework. While these centers have often delivered, with varying degrees of success, on their anticipated benefits such as faster decision-cycle time, better, more informed decisions and reduced POB, robust business and organizational models are necessary to ensure these efforts' long-term viability.

As part of a long-established business partnership, Norsk Hydro and Baker Hughes INTEQ have recently implemented changes to the industry's longest continuously running remote drilling operations center. Supporting some of the Norwegian Continental Shelf's most technologically challenging drilling operations, the center is contributing to improved financial performance, reduced POB, enhanced service quality and supporting work process changes within both organisations.

The revised model has been implemented as the ‘normal’ service delivery channel for five drilling operations supported by the BEACON center on a 24/7 basis and routinely operate advanced technologies such as formation pressure testing while drilling, deep reading resisitivity and azimuthal imaging services.

This paper will outline the technical and commercial models that have been developed, provide insight to the challenges encountered and achieved successes.
Drilling and Completing Difficult HP/HT Wells With the Aid of Cesium Formate Brines— A Performance Review
Authors: Downs J. D. , Blaszczynski M. , Turner J. , Harris M.
Published: December 2007

Conventional drilling and completion fluids containing weighting solids or hydrocarbons or halide brines can create problems with hydraulics, well control, well integrity and well productivity in HPHT operations. The negative influence of conventional fluids on drilling and completion operations can be sufficiently serious to compromise safety and degrade the economics of challenging HPHT field developments.

Formate brines have been developed specifically to provide improved drilling and completion fluids that are free of the troublesome components found in conventional fluids and therefore better suited to meet the needs of oil companies involved in difficult HPHT well constructions.

Formate brines have been successfully used as reservoir drill-in, completion, workover and suspension fluids in more than 130 HPHT well construction operations over the past 10 years. These applications have included 100 cases in which high down-hole pressures have necessitated the use of cesium formate brines for well control purposes.

Some 15 applications of cesium formate brines to date have been HPHT reservoir drill-in operations in high angle wells where operators considered that conventional fluids could create a safety risk and adversely effect project economics. We review the published information on the field performance of the cesium formate brines in HPHT applications, and conclude that the novel benefits of the technology that were first promised some 15 years ago during the early product development phase have now been fully validated.
Andrew Low-Cost Drilling—Teamwork, Technology, and New Working Practices Extend Field Life
Authors: Sawaryn S. J. , Qureshi R. H. , Trythall R. J. B. , Bourne L. , Price B. , Telford C.
Published: December 2007

An innovative two-well Low Cost Drilling (LCD) programme has been executed to exploit small, un-drained oil targets in the Andrew field. The wells have been drilled with 10% fewer offshore drilling crew, enabling critical back-to-back inspection and fabric maintenance to continue. Reserves targets have been met and costs reduced by 35%, allowing access to other smaller targets and extending field life.

Three questions needed to be satisfied throughout the program. Is the oil there; can we access it cost effectively and can the platform accommodate the work? In 2004, we accepted the challenge to identify and develop these targets and embarked on a 3-point program to: (1) Better define oil targets using 4D seismic and Top Down Reservoir Modelling (TDRM) techniques to address uncertainty; (2) Minimize offshore drilling support by using an Onshore Operations Centre (OOC). Only 80 beds are available for managing the delivery of all aspects of the business. (3) Minimise drilling cost through sidetracking, de-scoping and executing preparatory well work prior to full rig mobilization. Highlights include drilling the 6" hole section in a single run using agitators to maximize ROP by maintaining WOB transfer and simplifying completions to use pre-drilled liners, isolating the production zones using swell packers.

This success has been achieved through innovation, technology and adopting industry best practice, with meticulous planning and outstanding teamwork between operations, subsurface and drilling, both onshore and offshore.
A Re-examination of Drillpipe/Slip Mechanics
Authors: Paslay P. , Pattillo P. D. , Pattillo II P. D. , Sathuvalli U. B. , Payne M. L.
Published: December 2007

Current models of slip crushing treat the rotary slip as an axisymmetric wedge that generates an axisymmetric radial load on the drillpipe lateral surface. However, recent tests on strain gauged drillpipe specimens suggest that this model does not adequately capture the mechanical response of the drillpipe. The tests show that drillpipe response is a complex and non-axisymmetric function of slip geometry, friction between the slip and the bowl in the rotary table, and the mechanics of load transfer between the slip and drillpipe.

This paper presents a new model of slip behavior that represents the slip system as a series of line loads. Analysis of the suspended tubular under these forces and axial tension leads to a limit load that characterizes slip crushing. A corollary of this analysis is the minimum slip length required to support a given axial tension.
The Effect of Friction on Initial Buckling of Tubing and Flowlines
Authors: Mitchell R. F.
Published: December 2007

The introduction of friction into the analysis of buckling stability causes problems. For sliding friction, the friction force is fully developed for small lateral motion, while the destabilizing effect of the axial force is proportional to the lateral motion. Because the sliding friction force develops so rapidly and destabilizing effects develop so slowly, buckling is essentially impossible.

But we know that pipe buckles with friction! In conventional analysis, the only possibility for buckling is to have an initial non-zero lateral displacement, so that the axial force contribution may exceed the fully mobilized friction force. This initial displacement cannot normally be accurately estimated, so the force needed to buckle pipe with sliding friction is essentially unknown.

A cylindrical pipe has another possible mode of lateral displacement. Instead of sliding, the pipe can roll. In this case, the friction force developed is static friction. Static friction may take on any value between zero and the peak static friction value, where the value of the static friction is usually determined from a balance of known forces in the problem of interest. Here, the magnitude of the static friction is determined from a balance of torsional forces on the pipe. The key fact is that the friction force develops gradually, so we may determine a critical buckling force in the traditional sense.

The introduction of axial torque adds further complications to the buckling analysis. This paper develops a comprehensive model for pipe with axial forces and torque, and then develops the critical buckling loads for three cases of interest. The first case corresponds to the pipe in the wellbore, as investigated by Dawson, Paslay, He, and Kyllingstad. The second problem looks at a pipe lying on a flat plane, as a pipeline on the seabed. In both cases, a critical buckling load is determined for pipe whose lateral motion is constrained by friction. The third case finds the critical buckling load for rotating pipe. Several sample calculations are performed to illustrate the importance of friction forces in the stability of tubing and in the stability of seafloor flowlines.
Ringhorne Development: Technologies Applied in Extended Reach Drilling—Successes, Failures, and Communicating Risks
Authors: Musaeus N.
Published: December 2007

This paper describes some of the key drilling technologies used in the well construction of long reach and extended reach wells as part of initial field development of 6 reservoirs from the Ringhorne platform. Difficult drilling conditions exist due to extended drilling targets through highly reactive shales and require Non-Aqueous Fluid (NAF) drilling fluids at elevated mud weights. The Ringhorne development was made possible by using a combination of latest drilling technologies for extended reach drilling and an adequately designed rig to ensure success. In order to mitigate the resultant tight drilling margins, a number of optimizations impacting well designs and field operating practices were implemented. Among these have been latest applications of the newest Rotary Steerable tools, refined directional surveying and anti-collision practices, use of hole openers and underreamers to mitigate tight drilling margins, surveillance practices, use of low viscosity drilling muds, lost returns response practices, Logging While Drilling (LWD) advancements for geo-steering and casing installation techniques.

The Ringhorne development is a project example where more of a project's risk is being carried in the well construction phase since the development is on the current outer edge of drilling technology. The structured well planning, design and review processes will be summarized and explained to illustrate how these were used both to balance technology application and communicate risks to stakeholders.
Planning and Detailed BHA Vibration Modeling Leads to Performance Step Change Drilling Deviated 24-in. Hole Section, Offshore Norway
Authors: Grindhaug G. , Elsborg C.
Published: December 2007

This paper presents a case study of the detailed planning and BHA modeling used to improve performance in drilling deviated 24 inch hole sections and its implication to the on-going Ringhorne extended-reach-drilling (ERD) program. The paper describes the planning; modeling and results of the 24 inch drilling performance achieved in the longest extended reach well drilled to date in the Ringhorne Development, Offshore Norway.

Ringhorne wells usually kick-off below the 26 inch conductor in 17-1/2 inch hole building angle from vertical to 65 degrees where 13-3/8 inch surface casing is typically set. This is not the case for the development with extended well targets where it came necessary to upsize the casing program with 18-5/8 inch surface casing. This requires a 24 inch deviated hole to be drilled from approximately 300 meters measured depth (mMD) to 70 degrees by 1000 mMD with casing point at approximately 1600 mMD to enable drilling to the reservoir targets at 1700 – 2000 meters true vertical depth (mTVD).

The first 24 inch section was drilled using a 17-1/2" polycrystalline diamond (PDC) bit, rotary steerable system (RSS) and PDC hole-opener. Severe vibration problems were experienced while drilling through the Utsira sands near the base of the section causing a rotary steerable tool failure. This led to loss of angle and slightly earlier casing point than planned. The next 24 inch section was drilled using a two-run strategy including a 17-1/2 inch RSS to total depth (TD) before picking up a 24 inch hole-opener in a separate run. The first hole-opener run twisted off above the bottomhole-assembly (BHA) while drilling the massive Utsira sandstone and three subsequent hole opening runs were pulled due to poor performance resulting in a tapered casing string to be set.

Because of the poor BHA performance and the associated drilling problems, the operator and the service company conducted an extensive analysis of offset drilling performance followed by a thorough modeling study to ensure success in drilling the long reach 25/8 C-12 (C-12) well from the platform. Due to the complexity of the well, no deviation from the well path could be tolerated and the casing shoe had to reach the planned depth. Time and depth based data, formation information and vibration measurements from the offset wells were evaluated using analytical software. These results were used to analyze various BHA's for stability.

This investigation led to the development of a stable BHA configuration and selection of optimum bit properties, recommendation for parameter combinations and response plans for the formations encountered. A plan was developed that focused on drilling practices and parameter adjustments according to the formation. The result was a significant reduction of vibration that enabled the rig crew to successfully drill the 24 inch section following the well path and run the 18-5/8 inch casing to planned TD without incident.
The Next Generation of Sakhalin Extended-Reach Drilling
Authors: Viktorin R. A. , McDermott J. R. , Rush R. E. , Schamp J. H.
Published: December 2007

Six of the ten longest reach wells in the world have been drilled in Chayvo field on Sakhalin Island. Significant learnings have been gained from these wells and have been applied to the remaining wells to reduce cost and improve well performance. The learnings are discussed in this paper.

The most significant improvement in the Chayvo wells involved redesigning the completion. Initial completions were cased, cemented and perforated on coiled tubing to achieve a low-skin completion with zonal isolation. Alternative completion methods were evaluated after experiencing problems with production liner cementing and coiled tubing perforating. The revised completions incorporate stand-alone screens (SAS), predrilled liners and swell packers to achieve a low damage, sand free completion with zonal isolation.

Initial wells required extensive backreaming to make connections and trips. Bit designs, bottom hole assembly (BHA) configurations and operations practices were modified to minimize the amount of backreaming, improve overall rate of penetration (ROP) and achieve a "One-Pass Trippable Hole". Implementation of ExxonMobil's Fast Drill Process1 (FDP) was incorporated to achieve additional improvements in ROP.

Another learning was the importance of rotary steerable system (RSS) reliability since eliminating trips to replace the tools were a primary driver in overall performance. Rotary steerable systems were improved by evaluating failures, redesigning downhole components and implementing an incentive contract based on run time. Understanding and managing the causes of vibration using surface and downhole vibration measurement tools also contributed to increased rotary steerable life and higher overall ROP.

The evolution of Sakhalin bit designs was driven by a variety of factors. Initial bit design focused on steerability and instantaneous ROP. Second generation bit features were designed to reduce overall drill string torque by reducing micro-tortuosity and bit reactive torque in the 8-1/2 in. hole section. The most recent generation of bit designs have experimented with extra long gauge lengths to reduce bit darting and excessive vibrations in hard stringers while maintaining high ROP capability.

The first generation of casing installation employed full or partial flotation to run the 13-5/8 in. casing, 9-5/8 in. casing and 7 in. liners. On site engineering surveillance and calibration of torque and drag models enabled the use of conventional mud-filled casing runs on the subsequent 13-5/8 in. casing and 7 in. liners. Running conventional mud-filled strings reduces the risk of casing collapse and decreases running costs.
Achieving Technical Limits: Expanded Application of Real-Time Pressure-While-Drilling Data Helps Optimize ROP and Hole Cleaning in Large-Diameter, Directional Intervals
Authors: Lapierre S. , Courville G. , Song J.
Published: December 2007

In large-diameter directional intervals, high instantaneous rates of penetration (ROP) must often be sustained in order to achieve directional objectives. The combination of the large diameter hole, high ROP, and high inclination can present a number of challenges for effective hole cleaning. Nonproductive time (NPT) associated with pack-offs, lost returns and stuck pipe can result if the proper balance between ROP and available hole-cleaning capacity is not achieved.

Conventional practices for ensuring adequate hole cleaning when drilling with conventional directional assemblies include incorporating additional circulation time prior to making connections. However, if the additional circulation time is inadequate, the risk of pack-off increases significantly. If the additional circulation time is excessive, the operator is not able to drill at the technical limit of efficiency. Conventional practices also include monitoring real-time equivalent circulating densities (ECD) from pressure-while-drilling (PWD) tools to gauge hole-cleaning effectiveness and to identify pack-offs. Unfortunately, the abrupt nature of a pack-off and the rapid increase in ECD that ensues provide little forewarning, resulting in only a limited ability to minimize NPT.

An expanded application of real-time PWD measurements can be used to optimize ROP and hole cleaning, and so enable the operator to maintain the technical limit of efficiency more effectively. Based on the use of real-time equivalent mud weight (EMW) measurements acquired during ordinary pump cycles, this technique involves new methodologies to identify hole-cleaning deficiencies earlier in their development than currently possible through conventional real-time ECD monitoring. As a result, the operator can manage hole-cleaning improvements based on direct determination of hole-cleaning efficiency.

The effectiveness of this technique is demonstrated in a comparison of two similar wells drilled in the East Breaks (EB) area of the Gulf of Mexico by Kerr-McGee Oil & Gas Corporation. On "Well A", EB 688 #8, conventional practices were used to drill 2,254 ft of 17.5-in. hole to 45° inclination in 3.4 days. On "Well B", EB 686 #2, the expanded PWD application was employed to drill 3,107 ft of 20-in. hole to 53° inclination in only 2.5 days. This paper describes the details of the expanded PWD application and results from its field implementation.
Well Design for Drilling Through Thick Evaporite Layers in Santos Basin—Brazil
Authors: Poiate E. , Costa A. M. , Falcao J. L.
Published: December 2007

The presence of evaporite sections in prospects for oil or gas exploration is, in itself, a factor that increases the probabilities of success in the area due to favorable conditions for the hydrocarbons generation and trapping. However, many operational problems such as stuck pipe and casing collapse have been reported by the industry when drilling through those salt layers.

Historically, in the Campos Basin - Brazil, several deep wells have been drilled through thick salt intervals. Up to the 90's, the lack of reliable ways to predict salt behavior at high temperatures and high differential stresses led to very high drilling costs and even loss of wells.1

This paper presents a methodology for drilling fluid and casing design and drilling strategy for drilling at great depths through thick salt layers. The numerical simulation to evaluate the creep behavior of salt rocks (halite, carnalite and taquihydryte) submitted to high differential stress and high temperature was done through the application of an in-house finite element code developed.

Results obtained by the numerical simulations in prospect with 2000 meters thickness of different evaporite rocks with high creep rate was used to predict the evolution of the well closure with time for various drilling fluid and analyze several technically feasible alternatives to drilling strategy. The casing design was accomplished with several failure scenarios of cement the casing/borehole annulus through the salt, and drilling fluid in annulus to determine the nonuniform loading and timing of salt loading on well casings deformation or ovalization. The casing was design to be capable of supporting high creep rate of carnalite and taquihydryte.
Achieving Statoil Visund's World Record Reach With Intermediate Size Drillpipe—A Case History
Authors: Ogilvie W. , Chandler R. B. , Devlin A. , Kile H. , Rolfsen K. , Eilertsen Ø.
Published: December 2007

Statoil ASA's Visund project is operated from a floating installation located in the Tampen area of the Norwegian North Sea. The Visund field has been developed through 16 subsea-completed wells over the past six years. Recently, Statoil ASA set a world record by drilling the longest reach well from a floating installation. The well A-6HT2 (A-6) was drilled to a measured depth of 9,082 meters, 819 meters deeper than the Visund A-22 AHT2 (A-22) well. A-22 previously held the record. In addition to setting a new world record, well A-6 was finished ahead of plan, within budget and set a Visund record for the fastest spud to total depth ERD well with an average rate of penetration (ROP) of 108 meters per day.

Compared to the A-22 well, a key technology used on A-6 was a full-length, intermediate sized 5 7/8-inch drill string. Well A-22 used a conventional tapered drill string with several different drill pipe sizes. Some of the achievements noted with the intermediate sized pipe were improved running and handling speed, reduced handling tool inventory and maintenance, reduced surface pump pressure and maintenance, reduced drill string weight and a large cost benefit from improved drilling speed. Achieving this record reach has enabled Statoil ASA to hit targets from the floating installation that were previously thought unreachable, reducing the need to develop the field with less economical mobile floating rigs and offset subsea developments.

Since its introduction in 1999, the design and operational benefits of intermediate sized 5 7/8-inch drill pipe have been presented in many publishing's.1,2 Few have focused on specific case histories with documented performance improvements. This paper will present a case history of 5 7/8-inch drill pipe in use and how it allowed a world record to be set. A novel method for equivalent circulating density (ECD) reduction in the troublesome 8 1/2-inch hole section will also be presented.
Liner Hanger Trapped Annulus Pressure Issues at the Magnolia Deepwater Development
Authors: Eaton L. F. , Reinhardt W. R. , Bennett J. S.
Published: December 2007

ConocoPhillips is developing the Magnolia field with a Tension Leg Platform (TLP) in 4,674 ft of water at Garden Banks block 783 in the Gulf of Mexico. The wells are completed using dry trees from the TLP.

The production casing for each well consists of an 8.062 in. liner set near the base of a 10.75 in. liner. The 10.75 in. liner is tied back to the subsea wellhead. The subsea wellhead is tied back to the TLP with an 11.75 in. production riser.

To minimize heat loss in the produced fluid above the mudline, the production riser x tubing annulus is filled with low-pressure nitrogen. Completion brine is left in the well below the mudline. Two of the eight wells did not have cement behind the 10.75 in. liner hanger polished bore receptacle (PBR), leaving a trapped annulus.

Results from annular pressure build-up programs and finite element analysis (FEA) of the PBR tieback stem configuration, indicated that the combination of increased annular pressure due to temperature heat up during production along with the reduced hydrostatic pressure of the nitrogen in the annulus could cause a collapse failure of the 10.75 in. liner hanger PBR. Since the tieback string had been run and cemented, it was not possible to access the annulus behind the liner hanger PBR by conventional means.

A number of potential solutions to address the problem were considered: scab liner, expandable casing, perforate and squeeze annulus, low heat-transfer gel instead of nitrogen, and high-density brine. This paper will discuss the analysis of the potential collapse issue of the liner hanger PBR, the potential solutions, and implementation of the solution on the actual wells.
Experimental Study on Cuttings Transport With Foam Under Simulated Horizontal Downhole Conditions
Authors: Chen Z. , Ahmed R. M. , Miska S. Z. , Takach N. E. , Yu M. , Pickell M. B. , Hallman J.
Published: December 2007

The use of drilling foams is increasing because foams exhibit properties that are desirable in many drilling operations. A good knowledge of cuttings transport efficiency under downhole conditions is essential for safe and economical foam drilling. Previous cuttings transport studies with foam are limited to low pressure and ambient temperature conditions; no experimental study has been conducted under downhole (i.e. elevated pressure and temperature) conditions. This paper presents an experimental study of cuttings transport with foam in a horizontal annulus under simulated downhole conditions.

Experiments were conducted to determine the effects of polymer additives, foam quality, flow velocity, temperature and pressure on foam cuttings transport. Experiments were carried out at elevated pressure (100 psi to 400 psi) and temperature (80°F to 170°F) conditions in a unique full-scale flow loop with a 73-ft long test section (5.76" × 3.5" concentric annulus). A field-tested commercial foam system consisting of surfactant (1% v/v) and Hydroxylethylcellulose polymer (HEC) was used in the experiments. Three different polymer concentrations (0.0%, 0.25% and 0.5% v/v) were tested. Foam quality was varied from 70% to 90%.

During a test, cuttings were injected continuously to the flow loop until a steady state condition was established in the test section. In-situ cuttings volumetric concentration in the test section was determined using nuclear densitometers, load cell measurements, and by weighing cuttings flushed out of the flow loop. Test parameters recorded during the experiments were: liquid and gas injection rates, cuttings weight in injection and removal towers, mixture density, friction pressure loss, pressure and temperature in the annulus.

Two flow patterns, stationary cuttings bed and fully suspended flow, were observed during the cuttings transport tests. The flow pattern depends on polymer concentration, foam quality and annular velocity. Annular flow velocity, foam quality and polymer concentration all affect cuttings transport efficiency and frictional pressure loss. This paper will help to better design foam drilling and cleanup operations.
Re-engineering Barge Drilling for Deep Miocene HP/HT Frontiers in a Mature Basin
Authors: Husband F. J. , Bitar G. , Begnaud T. , Petticrew T.
Published: December 2007

Although considered a mature exploration area, the United States continues to attract exploitation of developed gas fields due to its well developed downstream infrastructure. However, natural gas production from major US basins is expected to fall below U.S. demand in the near term. Deep Miocene gas exploration programs in the Gulf of Mexico have emerged to exploit this supply shortfall. While attention has focused on jack-up rig designs for shallow water offshore prospects in this market, recent discoveries lie in 18 feet or less of water in Louisiana; the traditional operating area of the conventional swamp barge fleet.

Penetration rates, hole stability, and mud properties are key well construction parameters for both deepwater and deep gas projects, and lessons learned apply to both areas of operation. Deep gas targets have comparatively more compacted formation, higher temperatures, and low margins between flowing wells and lost returns, thus well control is a driving factor in well design. This paper describes the re-engineering of a conventional deep drilling barge rig to deliver a new generation high pressure/high temperature/high flow barge rig designed for increased reliability and specification for deep gas drilling programs in the US Gulf Coast region. Upgrading the main power and distribution systems and high performance pump configuration are discussed as well as resulting auxiliary system modifications.

Results of initial prospects drilled with this modified rig (Rig 76 B) in south Louisiana are presented, describing how upgrades on the rig impacted drilling performance. Safety and environmental results, hydraulics optimization, high pressure mud circulating system performance, and trouble shooting new components are included. The successful integration of drilling technologies including real time formation evaluation, bottomhole assemblies and performance drilling is discussed from the rig perspective. Finally, a check list of potential areas for improving the full potential of the rig in the market is provided to expand the application as more challenging drilling prospects are evaluated for technical and commercial feasibility.
Use of Real-Time Data at the Statfjord Field Anno 2005
Authors: Milter J. , Bergjord O. G. , Høyland K. , Rugland B.
Published: December 2007

The Statfjord Field has produced about 635 million Sm3 (four billion bbl) of oil and exported 68 billion Sm3 of gas since the production start in 1979. Currently, the field is in its tale production, producing at an oil rate of approximately 20,000 Sm3/d, which is about 17 per cent of plateau production rate. Improved recovery and thereby extended production life of the Statfjord Field is now to be obtained by changing the drainage strategy from pressure maintenance to depressurisation. About three million working hours are planned for in connection with the upgrades required to extend the lifetime of the Statfjord Field by approximately 10 years. The production will continue and be optimised during the upgrading and changed drainage strategy.

Real time data transfer from offshore to land enables support of drilling, well intervention and production operations in an efficient manner. New work processes were required in order to facilitate remote support as well as quality control of production logging, measurement while drilling, drilling parameters, geology structures, well completion, process adjustments and production optimisation. In addition, onshore engineering support results in a much better utilisation of engineering resources. Visualisation in onshore/offshore meetings (twice a day) has enhanced a common understanding and made the work process integrated. Careful planning of adjusted work processes and making an energising involved personnel were the most important issues in order to achieve results and drive the changes.

The results so far are successful and the conclusion is a continuation of the project and an expansion of the involved professional disciplines to gain increased quality and time efficiency of the offshore operations.
A Comprehensive Expert System for Diagnosing and Assessing Formation Damage
Authors: Garrouch A. A. , Malallah A. H. , AlEnizy M. M.
Published: December 2007

An expert system capable of diagnosing the potential of formation damage caused by clay swelling, fines migration, inorganic scale deposition, and organic scale precipitation was developed and implemented. In this manuscript, we present results for the expert modules pertaining to asphaltene precipitation and asphaltic sludging. These modules estimate heuristically the potential for asphaltene precipitation, and for asphaltene sludge due to acidizing.

Rules of thumb pertaining to asphaltene precipitation caused by solubility incompatibility between crude and solvent were collected. Membership functions to fuzzify these rules were constructed. The asphaltene module is capable of estimating the potential of asphaltene precipitation for a wide range of phase-behavior reservoir conditions, and for a much wider range of live and stock-tank crude compositions than what can normally be handled by a human expert. The acid sludge module makes its judgment based on factors such as acid strength, acid type, solvent preflush, iron control additives, Ferrous and Ferric ion concentrations, mutual solvent concentration, corrosion inhibitor type, and surfactant types used. A model has been formulated to predict the amount of asphaltene sludge that is likely to form as a consequence of crude-acid contact.

A graphical user interface using various templates for data input and modules output has been built to make the expert system user friendly. The expert modules have been validated using a range of field data. This expert system gives the advantage of automating the diagnosis process pertaining to formation damage.
When and Where Relative Permeability Modification Water-Shutoff Treatments Can Be Successfully Applied
Authors: Sydansk R. D. , Seright R. S.
Published: December 2007

This paper provides guidance on when and where relative- permeabiliy-modification/disproportionate-permeability- reduction (RPM/DPR) water-shutoff (WSO) treatments can be successfully applied for use in either oil or gas production wells. When properly designed and executed, these treatments can be successfully applied to a limited range of oilfield excessive-water-production problems. When these treatments are applicable, they may be placed using bullhead injection (not requiring mechanical zone isolation)—a very favorable feature. However, there are a substantial number of limitations and possible pitfalls relating to the successful application of RPM/DPR WSO treatments. First-time application by an inexperienced operator should be considered a somewhat high-risk undertaking. In order to successfully treat unfractured production wells (i.e., radial flow through matrix rock into the well) that are fully drawn down, the oil and water zones should not be in pressure communication and the oil- producing zone(s) must be producing at 100% oil cut (dry oil). When treating unfractured and multi-zoned production wells that are not fully drawn down, the well's long-term oil- production rate can be increased if the post-treatment drawdown is increased substantially. Treatments that promote short-term (transient) decreased water/oil ratios can, in principle, be applied to many unfractured production wells (that are not totally watered out) in matrix rock reservoirs. However, these latter treatments must be custom designed and engineered on a well-by-well basis. Furthermore, for most wells, the performance and the economics of such transient WSO treatments are generally marginal. An attractive application of RPM/DPR WSO treatments is the use of robust pore-filling gels in the matrix reservoir rock that is adjacent to a fracture(s) when oil and water is being co-produced into the treated fracture.
Optimizing Disproportionate Permeability Reduction
Authors: Seright R. S.
Published: December 2007

An idealistic goal of water shutoff technology is identifying materials that can be injected into any production well (without zone isolation) and will substantially reduce the water productivity without significantly impairing hydrocarbon productivity. Although many polymers and gels reduce permeability to water more than to oil or gas, several factors currently limit widespread field applications of this disproportionate permeability reduction property. First, adsorbed polymers and weak gels (suspensions of gel particles) show large variations in performance. Second, in unfractured wells (i.e., radial flow into porous sand or rock), the oil residual resistance factor, Frro, (permeability reduction factor) must be reliably less than 2. Third, adsorbed polymers and weak gels reduce permeability by greater factors in low- permeability rock than high-permeability rock.

Strong pore-filling gels were investigated to overcome these limitations. For porous media with pre-gel kw (at Sor) ranging from 120 to 6,500 md, one Cr(III)-acetate-HPAM gel (with 0.5% HPAM) consistently reduced kw to about 0.24 md (ranging from 0.12 to 0.37 md). In contrast, in Berea sandstone with kw (at Sor) ranging from 222 to 363 md, a weak gel (with 0.18% polymer) exhibited a much wider range of post-polymer kw values—from 0.75 to 202 md. Thus, strong pore-filling gels can provide greater reliability and behavior that is insensitive to the initial rock permeability.

With sufficient oil throughput, pore-filling gels dehydrate, thus increasing permeability to oil. Several gel formulations provided water residual resistance factors greater than 2,000 and ultimate Frro values of 2 or less. These results provide hope that our current approach will identify gels that can successfully and reliably treat either fractured or unfractured production wells without zone isolation. Significant oil throughput was required to achieve low Frro values, suggesting that gelant penetration into porous rock must be small (a few feet or less) for existing pore-filling gels to provide effective disproportionate permeability reduction.