bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Transfer of Through Tubing Drilling (TTD) Technology Between Provinces
Authors: Morrison John W. 
Published: December 2007

Abstract
Many companies operate on a global basis. Often a new idea or technology can make a step-change in the economics, or performance, in a particular province or field. That leaves the company with the enviable problem of understanding how and where it could impact its operations in other areas of the world.
One area where bp has had such success is in the North Slope of Alaska, where TTD has made a dramatic impact on their infill-drilling programme. In fact, Alaska had developed two distinct TTD techniques, Coiled Tubing Drilling (CTD) and Through Tubing Rotary Drilling (TTRD). This paper discusses how we transferred the technology to the North Sea. The subject is tackled on three levels: Transfer of practical knowledgeThe tactical choice on the optimum techniqueDetermination of the strategic value of the technology
It illustrates what needs to be done to ensure a successful business outcome when trying to gain the benefits of a new technology, but in a different operating environment.
To illustrate the issues, the paper will present performance information on both TTD techniques used in Alaska. It will talk about their differences, and why the application of CTD, in particular, has made such a significant impact. It will then discuss how the North Sea operating environment differs from the North Slope, how this influenced the choice of technology and the potential magnitude of the benefit that could be realised.
By the end of the analysis, it became clear that the solution and strategy for the North Sea had to be different from that of Alaska. It also makes it apparent why CTD has struggled to make an impact in the North Sea.
Northstar Drilling - A Progressive Arctic Endeavor
Authors: Kidd Gavin N. , Holt Barbara M. 
Published: December 2007

Abstract
So what is it that makes the Northstar Development stand out among all other drilling operations on the North Slope? Certainly the size, location and access are the three most obvious aspects of the project. Drilling an 8400-acre oilfield from a 3.7-acre manmade island 6 miles out in the Beaufort Sea has presented some distinctive challenges. Many of these challenges were anticipated and addressed, while many others were not. Despite the unique backdrop of such an extreme location, Northstar is a great example of how Beyond the Best principles have been applied. From FEL (Front End Loading) to execution and implementation of the Technical Limit Process, the Northstar team employs proven processes to strive for performance that is truly beyond the best. New technologies have been applied, along with the learning's from GPB (Greater Prudhoe Bay), to great effect. The paradigm of Northstar is such, that without a coordinated approach by all functions of the project, from Facility engineering, reservoir management, logistical support, construction engineering to drilling, the project would have failed. With aligned goals, determination and excellent attitudes, Drilling has consistently produced best in class performance. This paper explores the Northstar paradigm in more detail, along with the logistical details of supplying for an accelerated Drilling Program during seasonal restrictions in a lay-down area equivalent to 50% of a football field.
Drillstring With Aluminum Alloy Pipes Design and Practices
Authors: Gelfgat Mikhail Ya. , Basovich Vladimir S. , Tikhonov Vadim S. 
Published: December 2007

Abstract
The up-to-date aluminum drill pipes design made it possible to develop ultra-long drillstrings for super-deep and extended reach wells. The new generation software providing for drillstring analysis including consideration of drillpipe tool joints and pads in buckling helical loads evaluation. Drill string dynamics is also taken into account. The case studies of ADP application proved their benefits over the steel ones, and recent analysis have shown an opportunity to design a super-long 15,000 m well and this was not the absolute limit.
Riserless Drilling Performance in a Shallow Hazard Environment
Authors: Roller P. R. 
Published: December 2007

Abstract
Riserless drilling has become an increasingly important aspect of deepwater operations. This is particularly true when drilling in areas with shallow gas and shallow water flow potential.
The following paper highlights the operational pre-planning and successful results of drilling a deepwater prospect with both known and un-known shallow hazards. The aspects of drilling fluid and supply vessel management along with its relationship to the successful operation will be addressed in detail. The documented results of this project should reinforce the importance of emergency preparedness in all types of well operations.
Multilateral Technology Coupled with an Intelligent Completion System Provides Increased Recovery in a Mature Field at BP Wytch Farm, UK
Authors: Redlinger T. , Constantine J. , Makin G. , Glaser M. , Brown C. , Cooke D. , McLaughlin J. 
Published: December 2007

Abstract
Exploiting proven technology, improving functionality and adding intelligent completions, create an intelligent level 4 multilateral junction ideal for offering commingled, isolated, or deferred production. The junction offers re-entry access to the lateral and a low risk installation.
This intelligent multilateral installation should pay for the completion and drilling of lateral to new target zone in estimated "saved" revenue from the mainbore, which is normally lost in a traditional sidetrack.
The TAML level 4 junction was built around the proven concept of a hollow whipstock. The hollow whipstock technology has been significantly improved allowing for high-pressure capability before and after milling the window. An innovative concave geometry protects the concave face from milling process. After drilling the lateral, the liner is installed and cemented across the junction. The hollow whipstock and liner are perforated to regain production. Selective isolation is then achieved through an intelligent sliding sleeve completion system.
The all-hydraulic intelligent completion system combines several new and existing technologies. A downhole hydraulic logic unit was run which minimized the number of surface control lines whilst allowing individual flow control devices to be addressed from surface. The logic unit also controlled the setting of the production packers. Hydraulic flow controls were included to allow selective isolation without intervention of the producing intervals.
Shortly after the completion installation the flow control devices were activated resulting in the avoidance of a probable ESP workover.
Results:
This is the case history of the first intelligent TAML Level 4 multilateral installation at Wytch Farm. It will highlight the drivers that led to selecting multilateral and completion configurations, illustrate the installation sequences, and comment on continuous improvement efforts to ensure future successful installations of this technology.
Real-Time Web-Based Data Delivery Improves Drilling Efficiency in Deepwater: Thunder Horse - A Case Study
Authors: Looney B. , Alvarado R. J. , Essawi A. , Will M. 
Published: December 2007

Abstract
Real-time Web-based data delivery is now available for monitoring drilling processes. This paper demonstrates how both drilling decisions and workflow can be improved through effective use of this real-time collaboration tool. The examples are from the Thunder Horse deepwater project in the Gulf of Mexico.
As a first example, lateral vibration problems, which could have led to tool failures and an expensive trip out of the hole, were first detected in the office by an expert who was monitoring the operations using the Web-based data delivery system. An expert drilling team was then assembled in the office to collaborate with the rig personnel using the Web tool. The virtual rig-office team experimented with drilling parameters such as surface revolutions per minute (RPM) and weight on bit (WOB). The Web system provided instantaneous feedback from the rig showing the effects of these changes. The team was able to develop a vibration-minimizing solution, saving more than $400,000 for a trip. Furthermore, the team solved the problem in far less time than would have been possible without the data delivery system.
Other examples include real-time leakoff test monitoring, real-time density image analysis, and integration of real-time data from different sources on the rig, including gas and lithology data. This paper shows how the Thunder Horse team developed a novel workflow for deepwater operations, leveraging real-time Web-based data delivery to facilitate remote, team-based decision making and dramatically improve drilling efficiency.
Directional Drilling with Casing
Authors: Warren Tommy , Houtchens Bruce , Madell Garret 
Published: December 2007

Abstract
Drilling with casing has proven to be an effective method of reducing drilling costs and solving drilling problems. Most of the current Casing Drilling* activity is focused on drilling vertical wells, but interest in directional wells is increasing as the benefits of Casing Drilling in straight holes are demonstrated.
A directional Casing Drilling system has been run sufficiently to prove that directional drilling with casing can be practical with casing sizes from 5-1/2" to 13-3/8". The system uses a wireline retrievable directional drilling assembly, positioned in the lower end of the casing, to replace the conventional directional tools used when drilling with drill pipe. These tools have been used to drill to inclinations greater than 90° and have been retrieved and re-run at inclinations ranging from vertical to horizontal.
The directional Casing Drilling system can be used for a broad range of directional applications to capture the proven advantages of Casing Drilling that have been demonstrated for vertical wells.
Non-Selective Placement of a Polymer Gel Treatment to Improve Water Injection Profile and Sweep Efficiency in the Lagomar Field, Venezuela
Authors: Romero C. , Marin A. B. , Candiales L. E. , Mejias O. J. , Romero E. J. , Angulo R. J. , Flores E. , Norman C. 
Published: December 2007

Abstract
Results of polymer gel treatments in injection wells, suggest worldwide that there is a positive correlation between larger gel volumes and resulting incremental oil production in offset producing wells1–5. However, gel placement procedures, particularly in matrix (unfractured) reservoirs, remain a source of controversy. Many operators heavily rely on the permeability contrast in heterogeneous matrix reservoirs to assure the correct placement of the gel treatment, claiming that polymer gels will not penetrate and damage lower permeability zones to any significant degree. However, other studies indicate that in a matrix environment, the gel will enter any layer(s) that is not mechanically isolated during the gel injection, risking damage to "unprotected" zones. This paper presents PDVSA's experience in Venezuela with a polymer gel treatment that was placed without mechanical isolation into an injector in the Lagomar Field with positive results. This layered reservoir, characterized as highly heterogeneous, has been under waterflood for over 4 decades and currently, high water cuts are affecting its production and forcing the closedown of production wells in the area. In this work we include new evidence that might explain why this placement technique has been successful in this originally "unfractured" reservoir. In this new analysis, geological and geomechanical features are revised as part of the diagnosis, in order to determine the low sweep efficiency problem, and this information is used to aid in the injection strategy planned for the well.
Results from the treatment were evaluated with Production logging tools (PLT) run before and after the treatment, showing the blockage of the thief zones and redirection of injection water to lower permeability zones. A total of 3700 bbls of gel were injected and response in two associated producers was observed 5 months after the treatment with an average reduction of 30% in the water cut and 26,850 bbls of incremental oil.
Comparative Study of Different Silicone Compounds as Candidates for Restriction of Water Production in Gas Wells
Authors: Lakatos I. , Tóth J. , Bauer K. , Lakatos-Szabó J. , Palásthy Gy. , Wöltje H. 
Published: December 2007

Abstract
The paper demonstrates both converging and controversial laboratory results in potential application of silicone compounds (silanes, siloxanes and silicone oils and resins) to be used for restriction of water production in gas wells. The research program was extended to determination of surface and colloid chemical, rheological, hydrodynamic and retention properties of silicone-containing fluids in natural and synthetic porous media. Special attention was paid to the effect of different silicones on absolute, effective, relative and normalized relative permeability, and capillary and normalized capillary pressure curves. The complex survey has clearly shown that some silicone compounds, particularly in low permeable, tough porous media, drastically change the capillary forces, the spontaneous imbibition rate, and hence they offer a special option for delay of water break-through in gas/water systems. The comparison of different silicones provided sufficient information for development of a new technology which has been tested under field condition for restriction of water production in a tough, low permeable gas field (Algyő field, Hungary).
Development of a Hydrophobically Modified Water-Soluble Polymer as a Selective Bullhead System for Water-Production Problems
Authors: Eoff Larry , Dalrymple Dwyann , Reddy B. R. , Morgan Jim , Frampton Harry 
Published: December 2007

Abstract
For many years, bullhead systems have received a great deal of attention from the oil and gas industry. Because of the completion techniques used in many wells, protecting the hydrocarbon interval effectively during a water control treatment is not always practical or cost-effective. Bullhead systems offer the option of a treatment without zonal isolation and are designed to decrease water production with little or no decrease in oil or gas production. This paper describes the laboratory development of a new polymer that shows promise as a bullhead system.
The material falls into the class of hydrophobically modified water-soluble polymers; that is, a water-soluble polymer into which water-insoluble moieties have been introduced. The unique associative and adsorptive properties of this class of polymers are well documented, but they have not been commercially exploited to a great extent in oil field applications.
These materials offer improvements over the hydrophilic polymers traditionally used for permeability modifications. For example, hydrophobic modification appears to improve cleanup of the polymer that penetrates an oil saturated core, resulting in less risk of damage to oil permeability. Hydrophobic modification, depending on the structural features, also increases reduction to water flow in comparison to the unmodified polymer. This paper includes a general description of hydrophobically modified polymers and their properties, as well as detailed descriptions of the development and laboratory testing of the new system.
Application of Water-Based and Oil-Based Aphrons in Drilling Fluids
Authors: Growcock Frederick B. , Khan Asif M. , Simon Gerard A. 
Published: December 2007

Abstract
Aphrons are specially stabilized micro-bubbles created in situ to aid in suppressing the loss of drilling fluid into high-permeability formations. Water-based aphrons are designed for aqueous drilling fluids, while oil-based aphrons are designed for non-aqueous fluids. In both cases, the micro-bubbles are composed of a core of gas or liquid stabilized by proprietary polymers and surfactants, which can aggregate to form a tough, elastic barrier to loss of drilling fluid in permeable zones. Some of these zones are typified by water-wet sands that are susceptible to fluid seepage and differential sticking. Others are characterized by laminated sand and shale sequences, which are expensive to drill with conventional drilling fluids or underbalanced drilling rig equipment.
The authors describe how use of water-based and oil-based aphrons in drilling fluids can mitigate losses of drilling fluids downhole.
Application of an Ammine-Complex Adsorption Technique as an Alternative to Dielectric Constant Measurements (DCM) for Offshore Shale Typing
Authors: Sanders M. W. , Stewart J. , Tavendale F. M. , Abernethy R. H. , McCurdy P. 
Published: December 2007

Abstract
Dielectric Constant Measurements (DCM) are often a significant component of field wellbore stability studies. The DCM technique is a recognised method for characterizing clay material, providing good correlation between specific surface area measurements and rock strength. The most accurate methodology is to characterize intra-reservoir shale whilst drilling. A portable DCM instrument can be used offshore; unfortunately such units cannot always be made available.
Previous work has suggested a correlation exists between DCM specific surface area measurements and methylene blue titration (MBT) cation exchange results. However, a number of concerns were raised over the relative accuracy of the technique, and more importantly, on the consistency of testing between engineering personnel. Hence, an alternative, more quantitative method for accurately and rapidly determining the cation exchange capacity (CEC) of shale was required.
A method, first proposed by Bardon et al.,1 based upon the interaction of ammine-transition metal complexes with the clay exchange sites, was selected and adapted for use offshore. The reactivity of the clay material could then be determined colorimetrically based upon cobalt hexammine trichloride depletion. This method was applied in an actual field situation.
The Nelson field is located on the Forties-Montrose High within the Central Graben, UK Central North Sea, and some 113 miles east of Aberdeen. The reservoir, an oil producer, consists of submarine fan sands of the Forties Formation at approximately 7,200 feet TVDSS (true vertical depth sub sea). Serious problems were experienced with intra-reservoir shale while drilling the1 near-horizontal 8 1/2-inch section of Nelson well 22/11-N30y. Intra-reservoir shales were prognosed on a subsequent well, 22/11-N32 of similar trajectory. In order to minimise drilling risks, a full wellbore stability study was conducted. The ammine-complex adsorption test was used offshore, in place of DCM, to determine shale reactivity as part of a ‘shale type risk assessment matrix’ developed from this study.
A good correlation between specific surface area measurements and cobalt hexammine complex adsorption was found, providing a viable alternative to offshore DCM measurements for shale characterisation. It is believed by the authors that this is the first time this particular technique has been used in the field for this application.
The Chemistry of Formate Brines at Downhole Conditions
Authors: Javora Paul H. , Ke Mingjie , Stevens Richard F. , Berry Sandra L. 
Published: December 2007

Abstract
Sodium, calcium and zinc bromide and chloride brines have been used successfully as clear completion and packer fluids for more than 20 years, and their chemistry and applications have been evaluated and reported. Sodium, potassium and cesium formate brines are relatively new brines being explored for use as clear completion and packer fluids. However, relatively little information has been published about their chemistry in oilfield usage, especially under hostile conditions of temperature and CO2 environments. This paper describes the chemistry of formate brines used in the oilfield not previously published.
Extensive research and laboratory data was developed to understand the effects of pH, buffer capacity, CO2 content and temperature on the corrosion potential and decomposition of formate brines. Results from thermal stability testing and corrosion testing are presented which identify conditions for thermal decomposition of the formate ion and conditions for significant corrosion of oilfield tubulars at typical downhole conditions. Conditions for hydrogen gas generation, carbon monoxide gas formation, scale formation and corrosion potential are described. Understanding the results derived from this work could be critical to the selection of formate brines used for downhole conditions.
Unusual Oilfield Corrosion Inhibitors
Authors: Martin Richard L. 
Published: December 2007

Abstract
This paper summarizes a laboratory study of unusual corrosion inhibitors subjected in kettle tests to conditions that might exist in the oilfield. Some corrosion inhibitors are compounds with another primary function. Quaternary ammonium compounds are in this group; the primary function is often biocidal but under the right conditions, substantial corrosion inhibition is observed. Tetrakishydroxymethyl phosphonium sulfate (THPS) is another compound frequently used for its biocidal properties. Under certain conditions THPS is a corrosion aggravator, under others it is an effective inhibitor.
Calcium ions alone are not corrosion inhibitors. However, some inhibitors are considerably more effective when calcium is present in the corrosive brine. Some inhibitor/corrosive systems are not influenced. This system was examined for trends.
Other unusual corrosion inhibitors are tabacco extract and molasses. These materials were examined earlier in acid and in cleaning systems, but this paper examines inhibitive properties under conditions representative of oilfield corrosion.
Although few of the above substances are likely to be used alone as practical corrosion inhibitors, the information presented in this paper is useful to corrosion engineers dealing with oilfield corrosion. For example, further study might show tobacco extract to be a low cost component for corrosion inhibitor formulations.
An Improved Encapsulated Breaker to Decrease Hydrostatic Release and Increase Thermal Stability
Authors: Still John W. , McConnell S. Bruce , Miller Matthew J. 
Published: December 2007

Abstract
Encapsulating oxidizers with impermeable coatings is a well-known method for delaying the viscosity reduction of a fracturing fluid. It also enables the concentration of oxidizer breaker in fracturing fluid filter cakes formed during the leak-off and fracture closure process. The oxidizer is released by crushing the encapsulated particles during closure, but some oxidizer is also released before closure through a combination of hydrostatic release and mechanical abrasion.
This paper discusses the effect of the particle coating thickness on the hydrostatic release mechanism. Tests were conducted on encapsulated oxidizers with varying coating thickness to determine release rates at temperatures ranging from 175 to 250°F using a specialized oxidizer breaker release apparatus. The coating thickness required to minimize hydrostatic release was identified.
Analysis of both active and inactive oxidizer species during the hydrostatic release experiments also enabled the determination of the effective oxidizer breaker lifetime. Because oxidizers are designed to decompose into free radicals (the molecules responsible for polymer molecular weight degradation), shielding the oxidizer from the high-temperature environment extends the oxidizer breaker lifetime. We show that the encapsulation process is able to protect an otherwise unstable molecule from thermal and hydrolytic decomposition and the extent of the protection is related to the coating thickness.
The information obtained from this study was coupled with rheology experiments to validate breaker performance at temperature for a new thicker-coated oxidizer. The benefit of this material is increased concentration of active oxidizer breaker downhole, which facilitates fracture fluid cleanup and improves fracture conductivity and half-length.