bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Utilization of the Massive Amount of Real-Time Data Acquired in Wired Drillpipe Operations
Authors: Olberg Tor Stein , Laastad Harald , Lesso Bill , Newton Adrian 
Published: March 2008

Abstract
Drilling data telemetry rates with the current commercial mud pulse MWD systems present a severe bottleneck to the users of downhole drilling data. Wired drillpipe (WDP) telemetry allows for a several orders of magnitude increase in data transmission rates. StatoilHydro tested WDP during the drilling of the horizontal section of a well on the Visund platform in the Norwegian North Sea. There were two aspects of this test: first, the hardware and process operation of the wired drill pipe with a full range of MWD and LWD tools, and second, the use of this data by a multi-disciplinary team in real-time to turn data into information so that better drilling decisions could be made. While this paper discusses both of these areas, it concentrates on the use of WDP data.
High bandwidth downhole formation evaluation, wellbore, and drilling mechanics data from WDP telemetry were combined with standard surface drilling and depth data for transmission from the platform to an onshore support center. The WDP Enhanced Decision Team was deployed in a passive test mode adjacent to the center. The members of this team had expertise in geomechanics, petrophysics, geology, image interpretation, structural modeling, and drilling mechanics. The nature of the test was that the group could not directly make decisions, but could make recommendations to the Visund operations team who remained the sole authority responsible for the well.
Several value cases were identified during the test, most of which were used in the drilling decision process. These could be broadly categorized into HSE, improved drilling operations, well placement/geosteering, and data transmission. The most obvious and immediate benefit of WDP technology was identified in the areas of fast downlinks and control of downhole tools. High-frequency, time-based data was also useful for real-time torque and drag analysis and borehole quality using real-time caliper data. Better monitoring of downhole formation and wellbore pressures provided a basis for improved well control and borehole stability. The ability to send significantly more curves with higher resolution enhanced the well placement/geosteering process, and may, in the end, represent an even more significant value potential for this technology. Future WDP wells may easily implement these technologies.
Successful Development Drilling of an HP/HT Infill Well in a Highly Depleted Reservoir: Case Study
Authors: Fambon L. , Joffroy G. 
Published: March 2008

Abstract
Drilling infill wells on HP/HT fields after a significant depletion has occurred represents a real challenge. It requires drilling from a cap rock remaining at or close to virgin pressure into a reservoir in which pore and fracture pressures have largely decreased due to production. No mud-weight-window exists anymore at the transition between cap rock and reservoir. The difficulty is further increased by uncertainties in the pressure profile along the well path, the rock mechanics and their change generated by the high and rapid depletion, and also by depth uncertainty on the top reservoir.
For this reason, most HP/HT fields are developed by drilling all wells before a pre-defined limit of depletion level is reached at which the mud-weight-window closes. This limit is usually low.
However, HP/HT producer wells face depletion related threats to their integrity: sand production and / or deformation of the production liner under rock movement. When these threats become effective, the well and its associated production will be lost. Replacement wells will need to be drilled. Additional wells are also needed to increase reserves by creating new off-take points.
This paper describes the preparation work performed before drilling an HP/HT infill well in the highly depleted Franklin reservoir in the UKCS, the management of uncertainties during the drilling and some of the lessons learned from this first experience. Among them is the important influence of the reservoir depletion on the mechanics of the formations above reservoir.
The success of this first HP/HT infill well after significant depletion proves the feasibility of drilling such wells. It opens the door to new opportunities in HP/HT developments.
Innovative Hydraulic Isolation Material Preserves Well Integrity
Authors: Roth J. , Reeves C. , Johnson C. R. , De Bruijn G. , Bellabarba M. , Roy-Delage S. Le , Bulte-Loyer H. 
Published: March 2008

Abstract
Annular fluid or gas migration, resulting in surface hydrocarbon leaks or sustained casing pressure (SCP), is a problem operators face worldwide. With energy demands escalating, it becomes increasingly important to maintain production from existing wells and bring new wells on line without delay. Internal company policies regarding health, safety and environment, along with increased government scrutiny of the petroleum industry, can require wells to be shut-in if leaks or SCP are present.
Estimates of the number of leaking wells have varied widely as reporting standards have evolved over time and from country-to-country. In Western Canada, however, there are detailed reports of over 18,000 wells having Surface Casing Vent Flow (SCVF) that in some cases requires them to be shut in and production suspended.
From spud-in to abandonment, an oil well is subjected to numerous, repeated events that could compromise zonal isolation. Resulting damage, in the form of cracks in the isolation material or the creation of a microannulus, can allow hydrocarbons to flow to surface or become trapped below the wellhead.
This paper will describe a novel zonal isolation material that responds to a loss of hydraulic isolation. If hydrocarbon flows occur within or around the primary cement sheath, the material will seal these flows and reestablish well integrity. The system, which has slurry properties comparable to standard oilfield cements, is designed to be pumped as part of any primary cementing operation on wells drilled with water or oil-based drilling fluids. This material was used in well construction operations for wells drilled in Eastern Alberta, and can be applied to reduce the incidents of SCVF in this area.
This ability of this system to eliminate hydrocarbon flows has been confirmed with high-pressure laboratory testing, and it has been successfully field tested in Western Alberta.
A Successful Field Experience: Shallow Water Flow—How to Avoid the Need for an Additional Casing String
Authors: Pedersen Rikke , Øian Tore , Haugland Trond , Watts Ben , Taoutaou Salim , Stakkestad Arild 
Published: March 2008

Abstract
In areas with shallow water flow, additional casing strings are normally set to seal off the water-bearing zone. While drilling the first well in Fram East in the North Sea, the operator used a shallow 20-in. surface casing, but this measure increased well costs and caused a number of later limitations in the well construction process. To avoid these complications in other Fram East wells, the operator searched for alternative solutions.
It selected a cement design with properties compensating for the loss of hydrostatic pressure and thereby preventing the water flowing. The service company carried out extensive designing and testing of the cement formulations. A major challenge was qualifying the final design for a full-scale field test. A third-party laboratory qualified the cement system, using a modified setup of the gas migration equipment. The results were promising.
A dedicated cutting injection well was chosen for the field test. The successful test allowed planning the remaining wells using the new system—with projected savings of more than USD 20 million.
This paper will describe the development of the solution, the design, and testing of the cement formulation, and the full-scale field test performed.
Optimization of Deep Drilling Performance with Improvements in Drill Bit and Drilling Fluid Design
Authors: Black Alan D. , Bland Ronald G. , Curry David A. , Ledgerwood L. W. , Robertson Homer A. , Judzis Arnis , Prasad Umesh , Grant Timothy 
Published: March 2008

Abstract
Full-scale laboratory testing was conducted under a joint industry and Department of Energy program titled "Optimization of Deep Drilling Performance; Development and Benchmark Testing of Advanced Diamond Product Drill Bits and HP/HT Fluids to Significantly Improve Rates of Penetration." In total, seven bits and twelve different drilling fluids were tested in three different rocks at a variety of drilling parameters. Phase 1 results have been reported in a previous paper (Judzis et al., 2007). This paper presents the results from Phase 2 of the study. The goal of Phase 2 testing was to evaluate bit features and mud additives that might enhance ROP under high-pressure conditions. The test protocols developed in Phase 1 to simulate Arbuckle play and Tuscaloosa trend drilling at pressures in excess of 10,000 psi were employed to evaluate these features. Significant findings of Phase 2 include the following: Mud additives can substantially enhance ROPs in high-pressure conditions and may play a larger role than bit design features.A 16-ppg cesium formate brine increased ROPs 100% as compared to 16-ppg oil-based mud in Carthage marble and Mancos shale. The cesium formate improved ROPs by increasing both the efficiency and the aggressiveness of the bit.A 16-ppg oil-based mud weighted with fine particle size (D50 ≈ 1-3 microns) manganese tetroxide increased ROPs in Crab Orchard sandstone 100% as compared to a similar mud weighted with conventional barite. The manganese tetroxide improved ROPs by increasing the efficiency of the bit, but did not have a measurable effect on bit aggressiveness.Phase 2 tests continue to support the conclusion of Phase 1 that specific energy consumed while drilling is substantially higher than the confined compressive strength (CCS) of the rock.
Deepwater Exploration Well Pre-Drill DST Sanding Potential Prediction Using Probabilistic and Deterministic Approaches
Authors: Yi Xianjie , Sabolcik James E. , Goodman Harvey E. , Walton Brent W. 
Published: March 2008

Abstract
Sand control decisions are often made based on a deterministically predicted Safe Drawdown Pressure (SDP) without proper regard to the amount of uncertainty associated with the value of SDP. These uncertainties can be large when planning a Drillstem Test (DST) for a deepwater exploration well. On one hand, predicting too low of a SDP for a DST can result in unnecessary sand control. On the other hand, predicting too high of a SDP can lead to sanding during the test, which can cause numerous problems and ultimately cost much more than a sand control installation. Thus, a probabilistic study is warranted to quantify the expected sanding risk through a SDP probability profile, which can be used to estimate the risked expected value of a decision to install sand control or not.
In this study, data from 12 offset wells in nearby blocks from an Offshore Nigeria exploration well were reviewed. First, a regional geomechanical model (in-situ stress, pore pressure and rock mechanical properties) was calibrated and validated based on offset data. The calibrated geomechanical model was used with a sanding prediction model and was calibrated and validated based on offset DST and sand control data. Next, a statistical analysis of regional in-situ stress, sand pressure and rock properties for different sand intervals was performed to generate the necessary Probability Distribution Functions (PDF) and used as inputs to a SDP Monte Carlo simulation. And finally, a deterministic approach was also used to predict SDP. A comparison of Monte Carlo simulated SDP distribution and the deterministically predicted one from offset wells indicates consistent results. The SDP PDF allows estimation of the expected values for installing sand control or not and improves judgments of the true cost of obtaining the DST information.
New-Generation PDC Bits Allow Drilling at Record Rates of Penetration and Increased Durability in Challenging Algerian Applications
Authors: Aliko Enis , Hunt Terry , George Mathews , Nicol Jon , Christensen Hughes 
Published: March 2008

Abstract
Extensive research and development has produced a new generation of PDC bits, designed to drill harder and more abrasive formations than standard PDC bits, including those with the latest abrasion-resistant cutters.
The new-generation PDC bits allow drilling of formations that once were only drillable with TCI roller-cone bits and impregnated diamond bits. The success demonstrated in Algerian applications is likely to spread throughout the world, raising the performance bar and expectations for PDC bits.
The first new-generation PDC bits were introduced in a 12 1/4-in. Jurassic-Cretaceous application in the Algerian Sahara desert and immediately set performance records in one of the area's difficult fields. This application is characterized by a 2000-m long vertical section usually drilled with packed rotary BHAs through a variety of formations ranging from soft and abrasive to very hard. The challenge in this area for PDC bits is drilling the whole section in one run and maximizing the ROP. This challenge is made more difficult by a series of interbedded hard/soft formations that generate extensive vibrations. There also are extensive abrasive layers, leading to premature cutter wear and loss of aggressiveness and ROP.
In this paper, the authors will describe the technologies that were developed and included in these new PDC bits, as well as the field results in a specific application in the Algerian Sahara desert. The authors also will illustrate the importance of applying the correct operating practices in the achievement of record ROPs.
A Step Change in Total System Approach through Wired Drillpipe Technology
Authors: Nygaard Vebjørn , Jahangir Mohammad , Gravem Trond , Nathan Eugene , Evans John , Reeves Mike , Wolter Henrik , Hovda Sigve 
Published: March 2008

Abstract
The demand for increased oil and gas recovery requires the drilling of complex extended reach wells with optimized reservoir exposure for production and minimized overall production costs. In order to achieve these objectives, the use of high-end drilling and logging technology to optimize well placement is of the essence. However, the optimal utilization of this technology is often limited by the real-time transmission bandwidth of essential data from and to the downhole tools. The introduction of wired drillpipe technology has facilitated a step change in two-way data communication resulting in a high-speed data transmission giving much greater volume, resolution and quality of formation evaluation data and drilling dynamics data. Furthermore, the direct control of rotary steerable tools has now been enhanced to allow instantaneous programming changes and better utilization of dynamics data to enhance the decision making process required to address drilling dysfunction challenges, hole quality, gross ROP and BHA reliability.
The high bandwidth technology was used while drilling two laterals on the Troll field's reservoir in the Norwegian North Sea in 2007. The memory quality data was transferred through wired drillpipe to the surface while geosteering through relatively unconsolidated sandstones with localized zones of hard calcite cementation. The bottom hole assembly employed, comprised multiple formation evaluation and dynamics sensors to fully understand the downhole drilling conditions. The data was transferred to the expert advisory centre onshore for advanced processing and interpretation to enable the critical decision making process.
The adoption of a Total Systems Approach to select the ideal combination of application-specific drill bit, drilling system, and appropriate procedures and practices was presented and described by Stavland, et al (2006). Realizing the full benefit of the approach has been hampered by bandwidth restriction and time lag associated with conventional mud pulse telemetry. This paper will discuss how wired drillpipe technology has been utilized to enhance the Total System Approach concept during the first tests and how it will affect operations going forward.
Offshore Field Test of a New Integrated System for Real-Time Optimisation of the Drilling Process
Authors: Iversen F. P. , Cayeux E. , Dvergsnes E. W. , Ervik R. , Byrkjeland M. , Welmer M. , Torsvoll A. , Balov M. Karimi , Haugstad E. , Merlo A. 
Published: March 2008

Abstract
A new drilling control system enhancement for real-time optimization and automation control has been installed on the rig and tested in passive mode in preparation for a full-scale drilling test. The testing has been performed on the Statfjord C platform in the Norwegian sector of the North Sea.
The aim of the field test is to demonstrate that the incorporation of real time calibrated process models in drilling control can make the drilling process more reliable, increase efficiency, and improve safety for the drilling crew and with regards to control of the drilling process.
The system, described previously, performs continuous optimization of operational parameters using calibrated dynamic process models. Safe operational windows are calculated, and operational sequences are automatically optimized through forward model simulations. The results are applied to machine control in real-time, providing process safe-guards and increasing process efficiency.
A thorough description of the preparations and passive testing is given. The final test results are to be evaluated based on success criteria developed prior to the test in cooperation with field operator and drilling contractors. The implications for the work organization are also discussed, particularly in relation to control of data input, decision making and responsibility.
This technology will allow for direct integration of the know-how and best current practices into the drilling control system. Automated procedures and tests are to provide improved control of well conditions. Direct integration of process models shall enable safe optimization in the short time scale. And coupling the system to remote input will enable optimization in the long time scale, while built-in monitoring and diagnostics may ensure safe application of optimised parameters.
Successful Field Appraisal Well Makes Single-Diameter Wellbore a Reality
Authors: McKee Rob , Fritsch Jerry 
Published: March 2008

Abstract
Developing revolutionary technology requires persistence, perseverance, and vision to take an idea to a reliable product. A key factor in achieving the objective stems from how effectively the product development philosophy garners real results. For the development of the single-diameter wellbore, this philosophy resulted in a phased process that brought the technology from a concept to a reality.
This technology had to undergo final validation of some of the components before entering the final phase of the development process. This phase consisted of qualifying the tool for a specific application, with all of the components having been previously qualified for functionality. Successful integrated testing on the single-diameter system resulted in qualifying the phased-expansion system. The field appraisal test recently completed simulated the deployment operations by replicating hole angle, hole size, mud types, drill bits and other variables that factor into the complexity of the downhole conditions.
This paper will explain the product development philosophy and process used to drive the validation of the singlediameter wellbore. It will detail the current status of the technology, the process to determine quantifiers and the actual field appraisal and results. In addition, this paper will explain the factors that led to the product development and determined the commercial viability of the technology.
Solid Expandable Tubular System Mitigates High-Pressure Zones with Record Length
Authors: Bagley W. H. , Schultz Don , Mueller Joe , Vondenstein Marcus , Chowdhary Harsh 
Published: March 2008

Abstract
Dealing with higher than planned pore pressures, slim drilling margins and depleted zones in the same wellbore can quickly compound an already difficult deepwater drilling environment. Current market demands for oil and gas are placing more focus on deepwater development of existing reserves. Operators have had to utilize enabling technologies that are robust enough to address multiple problems to develop deepwater reserves that are difficult to access.
This paper describes a recent example of this dilemma when a deepwater operator successfully employed a solid expandable tubular system to isolate both overpressured and depleted sands The solid expandable system facilitated reaching the well objectives with a large hole size for maximize production rates. Over 6,865 ft (2,092m) of 7-5/8 × 9-5/8 in. expandable openhole liner allowed the operator to drill through both overpressured and depleted sands to an intermediate and unplanned casing point. Subsequent drilling operations below the expandable liner enabled the operator to reach the target zone and case the well with a 7 in. flush-joint production liner. Without the expandable installation, the operator would have been restricted to a maximum 5-1/2 in. casing at total depth (TD). Comparatively, 7 in. casing allowed the use of larger completion equipment providing Nexen Petroleum U.S.A., Inc., with significant additional production while reducing the mechanical risks associated with working inside smaller casing.
The solid expandable tubular operating envelope provides a robust technology for operators who need a responsive system that addresses conditions proven to hinder drilling objectives. This paper will describe the conditions that led to selecting the solid expandable solution and detail the challenges mitigated with the installation of this record-setting system. In addition, this paper will focus on how solid expandable tubulars are applicable in extremely difficult drilling conditions and also how these tubulars can reduce the risks and costs associated with deepwater drilling.