bluuebunny/crossref_metadata_2025 huggingface dataset:
Solubility, Miscibility and their Relation to Interfacial Tension for Application in Reservoir Gas-Oil Systems
Authors: Ayirala Subhash C. , Sequeira Daryl S. , Rao Dandina N.
Published: December 2007

Miscible CO2 gas injection is becoming the most popular enhanced oil recovery process for light oil reservoirs in the world. An accurate determination of miscibility conditions is essential to improve the economics of these gas injection projects. The terms, miscibility and solubility, are widely used in phase behavior studies of ternary fluid systems. The distinction between these two terms appears to be still hazy, leading to their synonymous use in some quarters. Furthermore, the relation of these two properties with interfacial tension has largely remained unexplored.

Recently, a new experimental technique of Vanishing Interfacial Tension (VIT) has been reported in the literature, relating miscibility with interfacial tension for gas-oil systems. Therefore, the objective of this study is to correlate miscibility and solubility with interfacial tension and to investigate the applicability of the new VIT technique to determine miscibility compositions in ternary fluid systems. For this purpose, a standard ternary liquid system of benzene, ethanol and water was chosen since their phase behavior and solubility data were readily available. The interfacial tension of benzene in aqueous ethanol at various ethanol enrichments was measured in pendant drop mode, using the Drop Shape Analysis (DSA) technique.

The experimental results indicate the applicability of VIT technique to determine miscibility conditions for ternary liquid systems as well. Comparison of IFT measurements with solubility data showed a strong mutual relationship between these two properties, in addition to demonstrating a clear distinction between solubility and miscibility. This study has identified the need to use pre-equilibrated solutions for IFT measurements in soluble regions in order to eliminate compositional effects on IFT. The interfacial tension appears to be independent of solvent-oil ratio in feed, provided pre-equilibrated solutions are used during experimentation. The conceptual extension of these experimental insights to gas-oil systems at reservoir conditions would be of immense use in determining miscibility conditions for gas injection EOR projects.
Expandable Liner Installation Avoids Sidetracking Following Production Casing Failure in the Gulf of Mexico
Authors: Chustz Mark , Mason David , Schober Jamie , De Lucia Frank , Butterfield Chuck , Didyk Vladimir
Published: December 2007

During initial completion operations on a deepwater subsea oil well in the Gulf of Mexico, the 7-3/4 in., 46.1 lb/ft casing failed the pressure test in the production liner. Subsequent operations located the casing leak 1,800 ft above the target completion intervals. The original completion was planned to be a stacked, commingled frac pack with reservoir depths over 23,000 feet and pressures over 14,500 psi.

To best address the problem and maintain the original well objectives, a solid expandable tubular system was selected to isolate the casing leak. The first expandable cased-hole liner run in the well failed to initiate expansion and was recovered. Reviews, lab mechanical tests and surface prototype tests were conducted to determine the cause of the unsuccessful start and to plan a second run for casing remediation. The revised design deviated from standard equipment and used a shorter launcher with a smaller outside diameter (OD) and a closed-ended system. In addition to the equipment modifications, lessons learned from the first attempt influenced procedural changes for the second installation.

The second cased-hole liner run in the well a few weeks later was successfully installed and expanded. The ∼2,300 feet of expandable liner used eight elastomer seal anchor joints specifically located to isolate the leak and allow completion operations to resume essentially as planned. This installation was carried out with straightforward dimensional changes to the expansion system and revised procedures. The post-expansion dimensions of the liner enabled the completion of the well with a 7 in., 38 lb/ft equivalent inside diameter (ID) casing using standard completion equipment. At the time, this application set a record as the deepest cased-hole expandable liner ever run. The financial benefits of the installation included avoiding costs of drilling a risky sidetrack and production deferment.

This paper will discuss the problem on the first installation attempt, the operational response, subsequent recovery, lab tests and surface trials. The second installation will be covered in detail with an overview of completion operations and a brief outline of the value added through this expandable liner solution.
Fully-Rotating Rotary Steerable and Concentric Reamers Technology Combination Eliminate Wellbore Threading in Deepwater
Authors: Lenamond Chris , da Silva Augusto Carvalho
Published: December 2007

Improving hole quality is a major factor for accurate formation evaluation and reduced well construction costs in deepwater. Further optimization of the borehole quality using new generation drilling assemblies is now possible. Not only to improve formation evaluation, increase penetration rates, and reduce the risk of drill string failure, but also to reduce the load points of salt formations on completions. Concurrent drilling and reaming techniques have been successfully used to mitigate the effect of non-uniform, transverse loading of salt formations on completions as well as improve hole quality for higher wireline log success rates.

During the execution of deepwater wells in offshore Brazil, multiple bottomhole assembly configurations were deployed to drill the various hole sections and the use of logging-while-drilling (LWD) imaging and wireline calipers provided a direct comparison of hole quality performance of each drilling system. A culmination of various drilling systems were evaluated, during a drill-off test, in a single well while performing enlarging-while-drilling (EWD) of a 12 ¼" to 14 ¾" hole. Salt formations were drilled to fully compare each system in a common drilling environment without variations due to formation types.
Experimental Investigation of Steam/Methane Flooding in a Heavy Oil Reservoir
Authors: Sola Sedaee
Published: December 2007

The application of steam injection in different forms of processes is widely used for thermal heavy oil recovery. Several studies have been carried out to evaluate the effect of injecting steam with gaseous additives such as, Hexane, Nitrogen, Carbon Dioxide, Propane and air. However there is very little literature about addition of methane or natural gas to steam in order to improve steam injection process.

This experimental study, investigates the effect of methane as an additive to steam. A consolidated core sample of an Iranian carbonate heavy oil reservoir (12°API) was used. The experiments involved injecting steam with methane in various methane/steam ratios ranging from 0:100 to 10:100 at reservoir conditions pressure and fluid saturations. Superheated steam was injected at 1200 psi which is higher than reservoir pressure at datum depth. Oil production rates, pressure drops and methane/steam ratios were measured to compare the effect of methane on oil recovery and other parameters at various fluid injection rates as well as steam temperatures.

With optimum methane/steam ratio it was noticed that oil production is accelerated, steam injectivity is increased and also recovery is higher when compared to injection of pure steam.
Optimizing Production from Fractured Damaged Reservoirs
Authors: Mufarji Said S. , Oyeneyin M. B. , Jihan S.
Published: December 2007

Formation impairment due to fines migration during production continues to cause inflow reduction. Proper fines management can optimise productivity, safeguard facilities and cut down on well maintenance cost. Today’s core flood test limitations keep us away from being capable of limiting or avoiding fracture damage. The limitations include: safety aspects which prevent utilisation of hydrocarbon gas in multiphase fluids in confined laboratories, core sample conditions due to recovery problems, reliability of scaling up to field extent, and so forth. Hence based on such limitations, unique approaches were carried out for damage risk assessments.

This paper presents unique techniques to analyse conditions leading to fracture damage, ability to characterise the damage impact and prediction of well performance. The techniques incorporate a CFD and 3D reservoir simulation packages.

Results suggest that in high permeability sands, the finer the grain size (10-100microns) the lesser the pressure decline rates. When 150 - 200 fines microns were simulated, the declines in pressure were comparatively sharper. The sensitivity of grain size in normal matrix formation is less compared to that found in fractured or very permeable formations as in the letter, higher magnitudes of permeability decline were revealed in which case possible shallow invasion damage mechanisms were likely. Unlike the grain size influence to pressure drop and permeability declines, the simulated fines concentration ranging from 20% to 50% by volume of crude along horizontal direction, did have different impact compared to results of same concentration across the width of the sand body. Water cut sensitivity on the other hand revealed significant permeability drops between 0% and 10% water cut at fixed fines concentration.

In these analyses, solid fines velocities were exclusively being monitored in the multiphase flow and could be distinguished from fluid velocities.
Milling of Isolation Valve with Wireline Conveyed Technology
Authors: Krüger C. , Sælensminde T. , Myrmel S.
Published: December 2007

A revolutionary drilling technique has emerged allowing drilling with electric wireline utilising metal machining technology in combination with field proven Well Tractor technology.

As the Well Tractor technology evolved and confidence was gained during the past several years, the application of a cost efficient method for milling of specific downhole hardware (i.e. valves, plugs etc.) as an alternative to existing methods has emerged. The technology is specifically needed on offshore installations where the logistical limitations are high. The article will describe the actual operation and the process of developing the technology.

The first ever operation involving the milling of a blocked borehole on wireline was conducted in late 2003 in an oil producer on a North Sea platform. A single plate isolation valve was stuck in closed position and it was imperative to get the oil producing well on-stream at short notice. During the tests leading up to the actual operation, the concept had been tested onshore in a test-loop with an estimated drilling time of 35 minutes to drill an 80 mm (3.15") hole trough a 2 cm (0.79") thick "super chrome" single flapper. The total operational time in the well for the entire milling operation was 11.5 hours from rig-up to rig down while the milling itself only took 7 minutes. During this operation all milled material was retrieved and the challenges of controlling stalling and actual control of the retrieval of the milled out plate were met. The development of wireline drilling used the Well Tractor features to achieve Weight On Bit and reactive torque control, while the limited total power available was addressed by designing specific bits for specific applications based on an approach of "surgical" intervention. The added advantage is that the risk of getting stuck by wedging the BHA in the object or in cuttings has been virtually eliminated by targeting a well defined area within the object itself.
Field Application in the Development of Low-Cost 3D Rotary Steerable Systems
Authors: Burnett W. T. (Tom) , Travis John T. (Tim) , Samuell John G.
Published: December 2007

The benefits of continuous rotary drilling in directional wells through application of 3-Dimensional Rotary Steering Systems (3D RSS) are well documented in the industry. ExxonMobil Development Company (ExxonMobil) continues to expand application of these systems where economic incentive exists. ExxonMobil's targeted strategy to influence the development of low-cost 3D RSS has been published1 and has generated further discussions with 3D RSS providers. This strategy is intended to accelerate the development of low-cost 3D RSS in order to capture benefits of this technology to improve drilling performance and economics, particularly in lower-margin projects.

This paper describes the results to date of the application of our stated strategy. Systematic usage of the tools in various modes (maintaining verticality, building/dropping angle, holding angle and azimuth, etc.) have given the provider valuable real-world testing to validate and improve tool design and to improve reliability of components. The role of field testing in support of the development plan, results of applying this technology at its current level of development and an assessment of its value will be discussed.
Compressed Natural Gas (CNG): An Alternative to Liquid Natural Gas (LNG)
Authors: Economides M. J. , Kai S. , Subero G.
Published: December 2007

Natural gas is becoming one of the most important resources of energy, with its share in the world consumption expected to increase dramatically over the next two decades. Currently, natural gas is transported to the markets by pipelines and as liquefied natural gas (LNG). Transporting the natural gas by pipelines is convenient and economically attractive onshore. For the offshore transport of natural gas, pipelines become challenging as the water depth and the transporting distance increase. LNG, an effective means of transporting gas for long distances across the seas, constitutes 25% of the world gas movement. But LNG projects require large investments along with substantial natural gas reserves and are economically viable for distances such as 2500 miles and beyond.

Compressed natural gas (CNG) technology provides an effective way for shorter-distance transport of gas. The technology is aimed at monetizing offshore reserves, which cannot be produced because of unavailability of pipeline or because the LNG option is very costly. Technically, CNG is easy to deploy with lower requirements for facilities and infrastructure. "Coselle" and "VOTRANS" are two would-be commercial, high-pressure gas storage and transport technologies for CNG. Technical and economic analyses of these two technologies were done in this study and a comparison is provided. The results show that for distances up to 2500 miles natural gas can be transported as CNG at prices ranging from $0.93 to $2.23 per MMBTU compared to LNG, which can cost anywhere from $1.5 to $2.5 per MMBTU depending on the actual distance. At distances above 2500 miles the cost of delivering gas as CNG becomes higher than the cost for LNG because of the disparity in the volumes of gas transported with the two technologies.
Evaluation of Matrix-Fracture Transfer Functions for Countercurrent Capillary Imbibition
Authors: Babadagli T. , Hatiboglu C. U. , Hamida T.
Published: December 2007

Different functions describing matrix-fracture transfer were tested for counter-current capillary imbibition interaction. The recovery curves obtained from capillary imbibition experiments were used to fit the transfer functions. The exponential coefficients yielding the best fit to the experimental data were obtained and correlated to the effective parameters such as the viscosity, IFT, matrix length and diameter, matrix permeability and porosity, and wettability using multivariable regression analysis.

To obtain the recovery curves, experiments were conducted on Berea sandstone and Indiana limestone samples. Cylindrical samples with different shape factors were obtained by cutting the plugs 1, 2.5, and 5 cm in diameter and 2.5, 5, and 10 cm in length. All sides were coated with epoxy except one end. More than fifty static imbibition experiments were carried out on vertically and horizontally situated samples where the imbibition took place upward and lateral directions, respectively. Brine-air, brine-kerosene, brine-mineral oil, and surfactant solution-mineral oil pairs were used as fluids. For many matrix shape factors (especially longer and small diameter ones), dividing the recovery curve into three parts were needed as the early, intermediate, and late times, which are typically distinguished by the time required for the imbibition front to reach the closed boundary at the end of the core.

Correlations amongst the exponential coefficients and rock/fluid properties were developed. It was observed that different rock/fluid properties and transfer mechanisms (capillary imbibition and gravity drainage) govern the process for each part. Hence, the analyses done in this study were useful not only for developing explicit transfer functions but also identifying the physics of the counter-current imbibition recovery.
Experimental Determination of Time-Dependent Matrix-Fracture Shape Factors for Different Geometries and Fracture Filling Regimes
Authors: Chaobal Aditya N. , Rangel-German Edgar R. , Kovscek Anthony R.
Published: December 2007

The multiple continuum framework for fluid flow in fractured porous media typically employs matrix to fracture transfer functions. Historically, transfer functions were developed from rather oversimplified assumptions such as pseudosteady state flow and a fracture network that is instantly and completely filled with water. This approach results in constant, time independent shape factors and pessimistic predictions of recovery. This paper presents a study designed to measure and interpret multiphase matrix-fracture transfer in two geometries: i) small-cubic matrix blocks with an external fracture and ii) large-cylindrical core samples with intersecting fractures. Water is injected into the fractures to observe the physical process of imbibition and flow through fractures in multidimensions. X-ray computerized tomography is employed to measure in-situ water-phase saturation and observe the progress and pattern of imbibition. Results are classified as either filling-fracture or filled-fractured depending on the fracture aperture and injection flow rate.

A new methodology arising from dimensional analysis is used to interpret the time dependence of the shape factor. Significant time dependence is found. Interestingly, plots of shape factors versus dimensionless time display similar characteristic behavior despite the much different experimental geometry. The time-dependent portion decreases linearly with a slope determined by the fracture aperture, fracture width normal to the flow direction, and the flow rate in the fracture. At a dimensionless time of roughly 0.1, shape factors became constant for all cases. The methodology proposed is promising for obtaining the shape factor for any fracture geometry, length and dimension, as well as water rate. No upscaling of the shape factor functions is required because they are obtained from dimensional analysis.
Microvisual Analysis of Matrix-Fracture Interaction
Authors: Rangel-German Edgar R. , Kovscek Anthony R.
Published: December 2007

A micromodel employing a two-dimensional representation of the pore space of a fractured sandstone was used to investigate matrix-fracture interactions and water imbibition into the matrix. Pore-level mechanisms of wetting and nonwetting fluid flow are observed directly with a microscope.

The rate of water flow through fractures is shown to be relevant to displacement at the pore level. A "filling-fracture" regime is marked by relatively slow flow of water through fractures, rapid fluid transfer from the fracture to the matrix, imbibition that is microscopically cocurrent, and recovery of the nonwetting phase that scales linearly with time. On the other hand, a "filled fracture" regime is noted when fractures fill relatively quickly with water and recovery scales with the square root of time. Additionally, imbibition is found to be microscopically countercurrent. Within a single field of view, some pores are responsible for the uptake of water while immediately adjacent pores expel nonwetting phase into the fracture. The cocurrent flow mode in the filling fracture regime was more efficient with respect to recovery of the nonwetting phase versus the volume of water injected.

Wetting and nonwetting fluids flowed simultaneously in both the fractures and the matrix. These observations provide insight into the discrepancies among fracture relative permeability curves presented in the literature. It is suggested that fracture relative permeability is sensitive to the total fluid velocity within fractures and the rate of uptake of water by the matrix.
Extending Rotary Steerable Capabilities to Locate Thin, Complex Sands
Authors: Lee Andrew
Published: December 2007

This paper will describe the challenges, solutions, and technology applications for drilling and positioning directionally complex wells into thin, complex sands from the Ringhorne platform. The concept of a Multi-Penetration Pilot (MPP) was proposed by the integrated work team to increase the number of reservoir penetrations. By drilling an undulating pilot with LWD and penetrating the top and bottom of the reservoir multiple times, sand mapping would be substantially improved and geologic risk of the prospect would be thereby reduced.
True Hybrid Operations Combining Coiled Tubing Drilling and Conventional Rig Workover Techniques and Practices
Authors: Cassee Udo , Rock Devin , Kara Dan , McLaughlin Sean
Published: December 2007

This paper documents the results of a new stage of development in the application of coiled tubing drilling. Combining coiled tubing drilling technology with a conventional jointed pipe workover capability represents the next step change in providing low-cost reserves access solutions through selection of the most efficient tool for the application.

Drilling sidetracks using coiled tubing is an established practice in Alaska's North Slope oil fields. During these operations the use of jointed pipe, except for running liners, with the coiled tubing drilling rig was avoided. A conventional workover rig was the preferred approach to prepare the coiled-tubing-candidate well when it required a change out of production tubing or other workover activity.

In 2001 a North Slope operator evaluated the opportunity to utilize one rig to perform both operations. In 2002 a workover rig was modified to fit the need.

Although it appears very obvious and straightforward to combine two established technologies, there are many challenges to overcome. Specialized equipment, multidisciplinary personnel, and control of overall well cost are just a few of the many parts of the operation that had to be planned. This paper details the results, problems encountered, solutions, and a quantification of the real benefits achieved combining coiled tubing drilling with a jointed pipe workover.
Jade North Sea HPHT Development: Innovative Well Design Generates Best In Class Performance
Authors: Palmer I. A. C.
Published: December 2007

The UK North Sea Jade Phase I development project demonstrates that high rate HPHT wells can be consistently drilled and completed within a £18.5mm well cost. Compared to other North Sea HPHT developments Jade is unique in providing the first experience of simultaneous drilling and production, with proven depletion levels up to 1600-psi, and no well integrity issues disrupting production. At the core of this success is a well design that is unconventional in comparison to other North Sea HPHT developments. This design was the basis upon which Best In Class (BIC) drilling performance was achieved.
Benchmarking Drilling Performance: Achieving Excellence in MODU's Operating Practices for Deepwater Drilling
Authors: Valdez Hugo , Sager Jurgen
Published: December 2007

Practical and straightforward application of continuous improvement and benchmarking techniques to monitor, document, analyze and detect best practices during the drilling process can improve operational efficiency and reduce well costs significantly.
Automated Parameter Estimation from Well Test Data Using the Signal Theory
Authors: Martínez-Romero Néstor , Samaniego V. Fernando , Cinco-Ley Héber , Villagrán Jorge Arévalo
Published: December 2007

This paper presents a new methodology for the automated parameter estimation from well test data, based on type curve matching using the Signal Theory. This procedure solves the inverse problem faster than the conventional techniques, with the additional advantage that the results are not affected by noisy data.

The new procedure has been proved with hundred of synthetic and field cases, and it can be used for the interpretation of all the different tests currently of common use in the field. In the present paper this technique is applied to three tests, all already published in the literature.

The methodology derived in the study surpasses the currently available matching theory based on non linear regression, since it requires a smaller computing time and its assured convergence (selection) of the correct (best) model that describes the physical conditions of the formation on the vicinity of the well. On the other hand, the conventional regression methods require large computing times for the solution of the system of non linear equations; in addition, they are affected by the presence of noise in the recorded pressure response and usually present convergence problems when the initial solution for the unknown parameters is not close enough to the searched solution.

The conventional type curve matching procedure inherently introduces interpretation subjectivity and the possibility of errors, because of the close similarity of the different pressure responses, and to its visual solution approach, which currently is not well understood; thus, it is not possible to develop fully efficient codes that could emulate this human function.

Based on a comprehensive set of type curves, the technique proposed in this paper allows an automated match of the pressure response, without the need of the visual effort of the analyst. The Signal Theory has been modified for the automated interpretation of well test data. The new matching correlation derived in this work, based on rules of shift, multiply and sum, solves the matching of pressure data in an improved way.
Development Modeling—Matching Rigs With Programs
Authors: Keener C. , Keji-Ajayi I.
Published: December 2007

Transocean's 28-rig deepwater fleet has logged more than 375 years of service. Within that population, the 13 newbuild 5th-Generation rigs have accumulated more than 60 years of well-construction experience. On the depth and breadth of that experience, the company is uniquely positioned to assess the merits of various rig types and equipment suites in relation to different programs.

In a paper presented at this forum two years ago, we introduced a performance modeling initiative grounded in the review of 80 exploration wells from 15 rigs. On that early work, we were able to predict relative timeline performance, and ultimately program cost for each of the rigs assessed. In the last two years, we have introduced a number of refinements, particularly in relation to completion activity. To date, we have modeled more than a dozen development programs with several operators, and are now able to make broad associations between rig specification and commercial advantage in relation to program attributes. It is evident that rig specification should factor significantly in preparing a subsea development strategy.
Drillable Perforating System Saves Effort and Rig Time
Authors: Ortiz Jonathan , Hinkie Ron
Published: December 2007

This case-history paper presents accounts of several field applications of a drillable perforating system (DPS) that has been used on 400 jobs in the Gulf of Mexico, with a near-100% success rate.

Components of the drillpipe-conveyed system are both drillable and disposable. The aluminum gun is mounted below a drillable packer. After perforating, the packer and gun can be drilled out by conventional drilling methods. There are no mobilization or demobilization charges such as those associated with use of wireline units. Because no mud system is needed for the operation, clear fluids can remain in place for workover operations. Once in place, the firing head is actuated by pump pressure applied through the tubing.

The paper describes use of the system to perforate underbalanced, perform plug-to-abandon operations, perform block squeezes, and perform other operations. The DPS can be used to cement and perforate in underbalanced conditions, limited-entry in-flow testing, cementing with clear fluids, and plugging and abandoning wells.

The paper presents results that show the DPS to be an effective alternative to conventional perforation and squeezing methods now followed in the oil and gas industry. In case histories presented, significant rig time was saved, along with savings in material and time to first sale after application. DPS offers several advantages over conventional equipment and techniques.

Clear fluids can remain in place during workover operations because no mud system is needed for well control. The DPS is a cost-effective and safe alternative to traditional methods of squeeze perforating. The DPS assembly is a one-trip perforating, packer-placement, and squeeze-cementing method that can eliminate a great amount of rig-time expense.
Enhancing Drilling Risk & Performance Management Through the Use of Probabilistic Time & Cost Estimating
Authors: Akins W. M. , Abell M. P. , Diggins E. M.
Published: December 2007

Not only is risk management critical to the well construction process, but in several jurisdictions around the world, a demonstrated risk management plan is a pre-requisite to doing business. One of the key elements of well risk management is a comprehensive understanding of the inherent risks at each stage of the process, their inter-relationships and the impact on project cycle time and capital cost. This paper describes a probabilistic approach to developing a drilling / completion time and cost model that can be used throughout the well construction life cycle, from project conception through operations and as a tool for project review.

The process starts with the development of a well specific sequence of operational steps. A step by step risk and hazard analysis is undertaken including examination of time and cost variances from relevant offsets, probability of occurrence of events representing both productive and non productive / problem time, and identification of possible contingency steps. The result of this analysis is a time and cost distribution for each step in the operational sequence. These distributions are input to a Monte Carlo simulator and the subsequent output includes a comprehensive time and cost probability distribution, including detailed risk information. Multi-well / campaign models can be developed by connecting a series of individual wells but with the added feature of applying appropriate learning curves and optimization measures.

This process allows for a non-biased, statistically based approach to project scoping, AFE preparation and management of capital spend through the operating phase allowing more informed decision making to occur at critical points in the project. It provides a tool which can be used to enhance senior management / asset team understanding of possible project time and cost outcomes; recognizing the inherent risks and the sensitivity of time and cost to these risks.
Extended Reach Drilling in the GOM - Ram Powell Case Study
Authors: Algu Dave , Landgrave Steve , Esquinance Bruce , Volokitin Yakov , Derise Bill
Published: December 2007

The Ram-Powell Unit encompasses eight OCS leases in the Viosca Knoll Area of the Eastern Gulf of Mexico.

The blocks are located approximately 125 miles east, southeast of New Orleans and approximately 80 miles south of Mobile, Alabama in water depths ranging from 2,000 to 4,000 ft. Since the drilling of the discovery well on Viosca Knoll Block 912 in May 1985, five commercial pay sands have been logged between 5,500 and 13,500 ft subsea.

This paper describes the planning and successful execution of the highly challenging A9 extended-reach well designed as the first development of the G sand interval. G sand represents the new geological play for the field as it is approximately 1,500 ft shallower than the main reservoir horizons of the field. The well was designed as a combined exploration and development project and a fast-track completion scheme was devised

The authors will discuss the design strategy, which focused on hole cleaning and the urgency of getting the casing to bottom immediately after drilling. The drilling and completion team employed a systematic approach to planning and execution of the well, which integrated both drilling and completion.

Along with detailing the planning and execution of the project, the authors also will detail the lessons learned, including the difficulty in distinguishing between borehole instability and hole cleaning problems when pulling out of the hole.
New Slimhole Technology Maximizes Productivity in Middle East Horizontal Drilling Programs
Authors: Al-Wahedi Tariq , Hay Mahmoud Abdel , Waheed Tamer , Grimes Bobby , Tyagi Sarvesh
Published: December 2007

Numerous operators are using advanced slimhole drilling technologies in development programs throughout the Middle East. These programs involve new and re-entry wells with long horizontal sections, typically 6" or 6-1/8" in diameter. Rollercone bits are often used in these applications because of their overall robustness, superior directional characteristics and predictable sidecutting ability. Slimhole PDC bits are run when possible, but problems with high torque, toolface control and drillstring dynamics often prevent their use. Traditionally, operators have been reluctant to attempt long runs with slimhole rollercone bits due to the potential for lost cones after undetected seal failures.

An innovative new metal sealed slimhole rollercone bit was recently developed. The downsized primary metal seal has proven its ability to significantly improve bearing life and reliability. The longevity of the new bearing has allowed operators to gain considerable confidence, which has translated into more on-bottom drilling hours and a high TD rate. The metal seal is especially useful on high speed (200 – 450 rpm) steerable motor assemblies, where elastomer seals wear at an accelerated rate.

The new bits are achieving over 1100 krevs at 80% reliability throughout the Middle East, while conventional elastomer sealed bits achieve only 600 krevs at 80% reliability in head to head comparisons. In Abu Dhabi, the new bits are used to drill out from 7" casing, then geosteer horizontally for 4000ft+ of limestone with a UCS between 5,000 psi and 15,000 psi.

The authors will document significant cost reductions through improved bit performance from several years of drilling in active fields in UAE (2003 - Aug 2004). The primary advantage of utilizing the new slimhole bit is they can drill the horizontal section in one fast run. Historically, it takes two elastomer sealed bits to complete the hole section. Reduction in drilling time due to higher ROP and elimination of tripping for a new bit has led to significant savings in rig time while minimizing formation damage by reducing the exposure of reservoir formations to drilling fluids.
Overbalanced Pre-Khuff Drilling of Horizontal Reservoir Sections with Potassium Formate Brines
Authors: Simpson M. A. , AbdRabAlreda S. H. , Al-Khamees S. A. , Zhou S. , Treece M. D. , Ansari A. A.
Published: December 2007

Interbedding of hard shale and sandstone sequences across the Lower Permian ‘Unayzah and Jauf formations of Saudi Arabia which usually occur between 12,900 to 14,600 ft tvd, present unique drilling fluid density requirements such that 90-102 pcf (12.0-13.6 ppg) drilling fluids are often required to mechanically stabilize the shales while only 66-89 pcf (8.8-11.9 ppg) is needed to balance the ‘Unayzah and Jauf reservoir pressures.

Review of offset wells drilled with similarly high overbalances indicated that the differential sticking forces effected drilling 5-7/8" horizontal hole with conventional KCl-polymer water based drilling fluids or halide brines weighted up with calcium carbonate can easily exceed the allowable overpull on 5" drillpipe if as little as 200 ft of high permeability virgin reservoir is traversed and drilling fluid HTHP filtrate, HTHP filter cake; bridging material particle size distribution and lubricity are not properly maintained; resulting in differentially stuck pipe, expensive fishing and or sidetracking operations.

The requirement to drill 1500 to 5000 ft horizontal sections across the pre-Khuff with 250 to 3508F BHST's which severely degrade the aforementioned fluids properties; catalyzed Saudi Aramco's search for an alternative drilling fluid which was also non-damaging to the sensitive pre-Khuff sandstone reservoirs.

Formate brine drilling & completion fluids appeared to meet all of the above criteria and were therefore selected for field trials.

This paper describes the use of a 90 pcf (12.0 ppg) sodium/potassium (Na/K) formate brine to drill a 1556 ft build to horizontal section across the ‘Unayzah-A formation at 13,900 ft tvd, with 820 psi overbalance and 2958F BHST in TINT-3, a 92 pcf (12.3 ppg) potassium (K) formate brine to drill a 1761 ft horizontal section across the Jauf formation at 14,500 ft tvd with 302°F BHST in HWYH-201 and the use of a 102-105 pcf (13.6-14.0 ppg) Na/K-formate system with calcium carbonate used as a bridging and supplementary weighting agent to drill a 1646' horizontal section across the ‘Unayzah-B formation at 13,900 ft tvd, with maximum overbalance of 1600 psi and BHST of 3238F in HRDH-658.

One of the wells exhibited greatly improved drill string/wellbore lubricity, bit performance, reduced torque and drag, ECD's and pump pressures whilst inadequate drilling fluid density masked the full benefits of formate brine use on the other two. However, differential sticking did not occur in any of the wells.
Rotating While Packed off May Cause Unexpected Heat-Induced Drill Pipe Tensile Failures
Authors: Gokhale Samit , Reynolds Nicholas , Ellis Sean
Published: December 2007

The amount of tensile pull that can be applied to free a stuck drill string is usually restricted by the drill string's minimum margin of overpull (MOP).1 To free a stuck string, the drill string is often rotated and pulled simultaneously. When this is done, the maximum permitted pull is reduced, depending on the amount of torque applied.

Application of pull, either based on MOP or the decreased tensile rating given the applied torque, has resulted in instances of overload failures of drill pipe. These failures have occurred at loads significantly lower than the drill strings rated capacity. In each of these failures, the formation had packed off around the string and circulation was lost.

This paper presents case studies and lessons learned from the analysis of such drill pipe failures. Metallographic examination of the failed drill pipe has revealed that the frictional forces produced while rotating the string induced sufficient heat to either locally temper the pipe or cause a phase transformation (change in grain structure) of the drill pipe material. As the material gets locally heated (often to temperatures above 1,500°F), the material hardness (and thus strength) decreases. The actual load capacity of the drill string depends on the temperatures reached downhole.

This paper discusses the factors that contribute to these failures and provides test data to support the findings. In addition, this paper presents the limitations of currently available methods used to determine the maximum allowable loads that may be applied when packed off with no circulation.
Magnolia Deepwater Development – Striving for Best in Class Drilling Performance
Authors: Reinhardt W. Randall , Williamson Roger N. , Eaton Luke F. , Actis Stephen C.
Published: December 2007

ConocoPhillips is developing the Magnolia field with a Tension Leg Platform (TLP) in 4674 ft of water at Garden Banks (GB) block 783 in the Gulf of Mexico (GOM), see Figure 1. The field was discovered in 1999 and appraisal wells were drilled in 2000 and 2001. The well construction strategy included drilling six additional development wells from a mobile offshore drilling unit (pre-drilling) prior to the installation of the TLP. Drilling the new wells consisted of two phases; batch setting all six wells through 20 in. casing followed by deepening the wells to total depth (TD). The wells targeted multiple zones resulting in complex, designer directional wells with 50°-60° maximum hole angles. This paper examines the application of drilling best practices that were used to deepen the wells to TD after batch-setting operations were complete1.

To minimize drilling costs while deepening the wells to TD, project goals were to eliminate trouble time; minimize combined drilling, circulating and tripping time per interval; maximize simultaneous activities; and reduce the number of trips necessary to drill the well. The goal of achieving Best-n-Class performance required detailed planning, documenting and implementing results and lessons learned, effective communications, equipment quality control, and implementation of a team environment with all the companies involved in the drilling program. The complex high angle wells required employing extended reach best practices to balance on-bottom drilling performance with the ability to effectively clean the hole to allow trouble free tripping of the bottom hole assembly (BHA), running of casing, and obtaining primary cement jobs.

The best practices discussed in this paper include changes made to improve rotary steerable reliability; simultaneous drilling and under reaming BHA design2; hole cleaning; and torque and drag monitoring. The paper will also discuss activities that reduced the number of required trips and activities that were conducted out of critical path such as moving the subsea BOP from wellhead to wellhead with an innovative bottom hole assembly (BHA), BHA run and retrieve wear bushings, subsea guidebase installation via a winch and ROV, off critical path make-up of BHA components, and drill string management.
Performance and Safety Gains with New Generation Land Rigs
Authors: Orr Alan , Tardio Juan Pablo
Published: December 2007

SPE-92482-PP

A fleet of 32 new-build Flex3Rigs has accumulated 55 rig years of experience as of 1 November 2004. Performance highlights to date include, but are not limited to the following:

>70% of the wells have been drilled under the customers' time estimate Average well cycle times have been greatly reduced Record wells have been drilled in several areas TRIR rates have been dramatically reduced >99% utilization rates Personnel retention has been much improved

These significant gains in productivity and safety are the result of:

Implementation of new technology Value by design Continuity of personnel Elimination of repetitive manual labor that can be mechanized or does not add value to the well construction process Safety by design Training Daily communication, sharing of learning and performance achievements across the rig fleet

Customers are demonstrating their support for this approach by paying premium dayrates in exchange for lower total well (drilling) costs and accelerated production.

The latest field data, including drilling curves, from the 55 rig years of experience will be used to support this.

The "learnings" from this paper may be applied by operators to make better value based decisions and by drilling contractors to evaluate strategy and new rig design alternatives.

The proposed paper adds technical knowledge by demonstrating the synergistic power of the following concepts/principles:

New technology can be successfully implemented on a large scale Creation/provision of an enhanced "working environment" greatly improves personnel safety and retention and enables field employees to achieve breakthrough results Pre-project training coupled with daily sharing of learning and performance achievements creates a progressive learning and performance environment for achieving breakthrough results.
Comparison of Formation Pressure and Mobility Data Derived During Formation Testing While Drilling with a Mud Motor with Production Data and Core Analysis
Authors: Strobel J. , Bochem M. , Doehler M. , Meister M. , Buysch A. , Pragt J. , Schrader H.
Published: December 2007

New tools for Formation Testing While Drilling (FTWD) were introduced to the market less than two years ago. They are used in an increasing number of wells in a wide range of operating environments. The tools are capable of performing accurate tests in the dynamic drilling environment of rotary and rotary steerable drilling. They measure formation pressure and some provide formation mobility estimations in real-time. The application expands formation testing into extended reach drilling where pipe conveyed wireline testing is of high risk. It also allows formation pressure testing in boreholes where drilling risk or hole stability exclude conventional data acquisition. During FTWD operations circulation is maintained at all times to insure wellbore integrity. This presents a challenging dynamic environment for accurate formation pressure measurements.

In this paper, the application of an FTWD tool in conjunction with a mud motor is described within an even more challenging environment, due to motor rotation and associated drillstring vibrations, as no circulation bypass valve was used. The Baker Hughes INTEQ TesTrak tool was capable of performing accurate formation pressure and mobility measurements with an overall success rate of over 80% in an extreme pressure and vibration environment. Pressure and mobility test results will be shown and compared to conventional wireline logging results from nearby wells. Mobility data, which are calculated downhole and transmitted to surface in real-time, are compared to previous well test data from neighboring wells. The FTWD mobility data showed a good match with reservoir simulation and core data, and even better agreement than the data derived from conventional wireline measurements.

In this application the FTWD tool was run in combination with a triple combo LWD suite. This allowed real-time reservoir evaluation as well as optimizing pressure point selection during on-site formation evaluation. No additional wireline logs needed to be run afterwards and the hole could be cased immediately.
Project-Specific High-Pressure Completion Tubular for ChevronTexaco's Tahiti Project
Authors: Chandler R. Brett , Hensley J. Rodney , Gonzalez Manuel E. , Muradov Andrei , Jellison Michael J.
Published: December 2007

This paper presents the results of a two-year comprehensive effort to design, test, manufacture and implement a high-pressure completion tubular for ChevronTexaco's Tahiti project. Several enabling technologies resulted, including the project-specific design of a premium seal, rotary shouldered connection to withstand absolute pressures up to 29,000 psi, metallurgical and heat treatment advances to permit manufacture of ultra-high strength tool joints (12.5% greater than the industry standard yield strength) and an industry first rotary shouldered connection testing program consisting of simultaneously applied internal and external pressures with temperature, bending, tension and compression loads. Field results from the completion operations are presented.