bluuebunny/crossref_metadata_2025_split huggingface dataset:
Quantitative Risk Assessment for DP Operations Aboard the Belford Dolphin
Authors: Naismith S. , Cowan M. , Linzi P. 
Published: December 2007

Abstract
This paper presents a summary of a study that has been carried out to demonstrate that the drilling operations planned for the dynamically positioned drillship, the Belford Dolphin, can be carried out within defined quantitiative risk acceptance critieria for oil spills. The basis for the study is the vessel's past position keeping history, the operating experience for similar vessels, the subsea equipment design and the uncertainties associated with the subsurface geology of the project.
Eastern Gulf of Mexico: Inhibitive Water-Based Drilling Fluid Sets Ultra-Deepwater Records
Authors: Watson Pat , Meize Bob , Aldea Catalin , Blackwell Billy 
Published: December 2007

Abstract
Two record wells were recently drilled in the ultra-deepwater Eastern Gulf of Mexico. The wells were the fastest two wells drilled in water depths greater than 7,000 ft in the GoM. A high-performance water-based mud (WBM) was used to drill the intermediate sections. The fluid had comparable performance to a synthetic-based mud (SBM), with the advantage of cuttings disposal permission in this environmentally sensitive offshore area. Significant savings were realized by not carrying the cuttings to shore for disposal. Other advantages included (a) no losses while running and cementing casing and (b) easier displacements. The fluid was re-used on two consecutive wells and then stored for further applications.
The authors will detail the careful planning that coupled with fit-for-purpose solutions allowed setting these records while reducing the overall well cost. The wells were drilled in the Lloyd Ridge area of the Eastern Gulf of Mexico, categorized as "zero-discharge" for SBM cuttings. The use of the high-performance WBM saved the hauling and disposing of approximately 2,000 bbl of cuttings on each well. Cost savings were also accomplished by avoiding fluid losses when running and cementing the casing. On a similar project drilled completely with SBM, 2,156 bbl of mud were lost while running and cementing the 13⅝-in. casing.
Comparison of drilling and economic performance of the new water-based mud and the synthetic-based mud are included in this paper to offer a comprehensive analysis. Also presented are innovative solutions introduced to optimize hole cleaning and shale inhibition.
Onshore Mobile Platform: A Modular Platform for Drilling and Production Operations in Remote and Environmentally Sensitive Areas
Authors: Kadaster Ali G. , Millheim Keith K. 
Published: December 2007

Abstract
Anadarko Petroleum Corporation has demonstrated the use of a reusable Modular Platform* to minimize the footprint and environmental impact of a drilling operation in an ecologically sensitive area.
The modular platform was installed on a location in the North Slope Borough of Alaska, for the continuous coring of the Hot Ice #1, a joint venture hydrate exploration well in cooperation with the U.S. Department of Energy (DOE) and Noble Drilling subsidiary, Maurer Technology Inc.
The concept was approved in spring of 2002 and the design, fabrication, systems testing, and mobilization to North Slope was completed by the start of field operations in January 2003. The removal of the platform is scheduled for March 2004. During all phases of the project, the platform was monitored for stability and its impact on the tundra.
The modular platform application represents a significant step towards establishing temporary or permanent drilling and production sites in ecologically sensitive areas with a minimal footprint and environmental impact. It is readily configured for deep or shallow wells, for applications in the arctic or the marsh or the foothills. The modular platform is also suitable to be designed and utilized as a production platform or pipeline facility, in areas without road access.
Basis of Design for Coiled Tubing Underbalanced Through-Tubing Drilling in the Sajaa Field
Authors: Suryanarayana P. V. , Smith Bruce , Hasan ABM , Leslie Charlie , Buchanan Richard , Pruitt Randy 
Published: December 2007

Abstract
This paper describes the technical basis for the design and implementation of a Coiled Tubing underbalanced drilling (UBD) campaign in the Sajaa field in Sharjah, UAE. The campaign calls for up to three multi-laterals per well to be drilled underbalanced from existing wells thru-tubing. The paper describes the analysis, modeling, result and their implication in the selection of the operational approach. The key issues associated with the campaign, many of which were unique and challenging within the context of UBD, and their consideration in the basis of design and implementation plan are discussed, with specific reference to the Sajaa-3 well, which was the first candidate. These include
■ Temperature modeling and thermal considerations due to the high bottom hole temperature, ■ Compositional PVT behavior of the produced fluid, ■ Feasibility, underbalanced operability and controllability of CT drilling thru tubing, ■ Risk to underbalance from near-wellbore depletion of the reservoir due to long-term production from the motherbore, ■ Estimation and impact of the productivity of the motherbore and open laterals while drilling subsequent laterals, ■ Risk from reservoir parameter uncertainties, ■ Hole cleaning risks, ■ Designing for zero flare, ■ Consideration of mechanical and hydraulic limitations to the drillable lengths, and ■ Equipment limitations.
The paper details the analysis approach used, assumptions, models used, and results. It should be noted that the Sajaa produced fluid is a retrograde condensate, and the inflow performance was non-linear, and therefore consideration of these in the basis of design becomes critical.
The goal of this work was not only to create the technical basis of design for the well Sajaa-3, but also to set the parametric limitations for a wide range of well types that were likely to be encountered in the continuation of the campaign. Based on this work, an approach to drilling and monitoring the well so as to minimize the risks was developed and formed the basis of the drilling operation. The campaign is now on its seventh well, and the results of the drilling operation of Sajaa-3 and the subsequent wells, and their implications to the design basis are also discussed.
Advanced Analysis Identifies Greater Efficiency for Testing BOPs in Deep Water
Authors: Franklin C. Mark , Vargo Richard F. , Sathuvalli U. B. , Payne Mike 
Published: December 2007

Abstract
Pressure testing Blowout Preventers (BOPs) with Synthetic-Based Mud (SBM) requires lengthy testing times as a result of pressure/volume/temperature (PVT) influences associated with SBM. PVT influences are especially pronounced in deepwater and high-pressure test environments.
This project was motivated by an effort to better understand the mechanics that transpire during BOP testing. The primary objective was to demonstrate that the pressure decline is quantified by the fluid PVT behavior, mechanical influences, and thermodynamics of pressurization and subsequent cool down. The second objective was to demonstrate that the pressure decline caused by a leak can be detected reliably and efficiently with high resolution pressure data.
It was theorized that the phenomena primarily result from heat added to the system during pressurization. To pursue this investigation, real-time PVT data was gathered at the cementing unit (CU) suction and discharge while testing the BOP. In addition, pressure-temperature (P-T) gauges were placed in the drillstring: one at the drill floor, one at the midpoint between the drill floor and the BOP, and one above the BOP stack. The gauges confirmed significant heat up as the system was pressured up for each test. The pressure decreased as the system cooled back towards the ambient. Modeling techniques were developed to understand the system response. This paper presents salient aspects of data acquisition, data interpretation, and modeling techniques.
Results demonstrate the potential to significantly impact the industry with respect to safety, time, and costs for BOP testing.
Qualitative Risk Analysis of Emergency BOP Control Systems to Ensure Availability
Authors: Sattler Jeff , Lewis Ed 
Published: December 2007

Abstract
Many of the latest generation of ultra deepwater capable rigs included emergency BOP (Blow Out Preventer) control capabilities, sometimes referred to as secondary intervention systems. Such systems represent the last line of defense in containing a well. Should it be necessary and unavailable, the result could be environmentally and humanly catastrophic.
Building on installations that have been in service for many years, these capabilities range in functionality and purpose, from providing an alternate means to operate BOP functions in the event of total loss of the primary control system to assisting personnel during incidents of imminent equipment failure or well control problems. They can be actuated automatically or manually, and utilize components of the primary BOP control system or be totally independent. With as many permutations as there were rigs built, an understanding of the capabilities and limitations that exist on a particular rig is of critical importance in assessing the risks associated with a drilling program.
While there currently are no standard terms in use to describe the essential attributes of systems, this paper recommends definitions and terms for a common understanding. The defined terminology is then utilized to compare and contrast system parameters, identifying various system strengths and weaknesses for use in risk analyses.
Possible enhancements to existing emergency control systems will then be discussed, as well as their benefits and anticipated costs. Finally, the paper will recommend best practices for moored rig operations and those for operations utilizing DP (Dynamic Positioning).
The First Use of Gravity MWD in Offshore Drilling Delivers Reliable Azimuth Measurements in Close Proximity to Sources of Magnetic Interference
Authors: Matheson Elizabeth , McElhinney Graham , Lee Richard 
Published: December 2007

Abstract
Measurement While Drilling (MWD) is the preferred method of surveying a well bore when drilling deviated wells. MWD has an advantage over other types of surveying in that the tools are part of the Bottom Hole Assembly (BHA) and surveys can be obtained quickly without the need for interrupting the drilling operation to run a separate surveying tool. However, like all magnetic survey instruments, MWD is susceptible to magnetic interference. The directional azimuth information becomes unreliable when in close proximity to sources of magnetic interference such as casing strings or adjacent wells.
This paper describes a new method of MWD surveying which includes a second accelerometer sensor package to derive azimuth rather than using magnetometers. It is therefore not prone to magnetic interference and the same drawbacks as conventional MWD. The technique uses the inherent bending of a BHA between the two sets of accelerometers in order to measure the relative change in azimuth.
Two case histories are outlined where this technique was successfully used to sidetrack two near vertical wells from directly below existing casing strings despite the presence of magnetic interference. In both cases, the ability to initiate the build as early as possible was important as it provided the greatest possible chance of achieving the relatively tight directional plan.
The use of Gravity MWD may provide considerable cost savings compared to alternative techniques that could incur additional rig time, be sensitive to movement and may not be capable of including real time Logging While Drilling (LWD).
A Pressure Activated Deployment System for Openhole Memory Logging Tools and its Application in Directional Wells
Authors: Spencer M. C. , Ash S. C. , Elkington P. A. S. 
Published: December 2007

Abstract
Openhole memory logging was introduced in 1999 as a more efficient alternative to pipe conveyed wireline logging. It was developed subsequently into a shuttle system that conveys logging tools inside drillpipe, and which provides formation evaluation logs after drilling to supplement basic real-time logging-while-drilling (LWD) data. The original shuttle design used a dart pumped from surface to move the logging string into open hole after the assembly reached TD. In a new development, the dart has been eliminated together with the associated pumping time. In its place is an electro-mechanical pressure activated release mechanism capable of simple two-way communication. The method has been used in trials to activate and deploy logging tools downhole, and to return status information to surface. It has the potential to be developed further for post-drilling real-time data transmission, and is a key component in a repeat formation pressure tester being developed for memory operations.
Multilateral / Intelligent Wells Improve Development of Heavy Oil Field – A Case History
Authors: Rump Pascal , Bairagi Ronjoy , Fraser John , Mueller Klaus 
Published: December 2007

Abstract
Multilateral systems provide production from two or more wellbores and Intelligent Well Systems provide control over production. The combination of these complementary technologies can lead to future wells offering maximum reservoir and production efficiency.
Although both Multilateral and Intelligent Well Technologies have been available to the industry for many years, it is only recently that wells offering both capabilities have been installed. One reason for this hesitation in recent years has been the perceived risk of each technology and the concern with overall project risk when considering a combination of the two technologies. But many of today's multilateral and intelligent well systems have evolved to the point that low risk, highly flexible combinations of these two technologies are fully compatible and feasible in a variety of well situations.
A cost-effective Technology Advancement Multilateral (TAML) level 3 junction system was successfully installed in three horizontal dual-lateral production wells in the Mukhaizna heavy oil field. The junction allows for installation of 7" liners in both legs and selective access to each leg while providing suitable barriers to sand production. This paper will highlight a recent well installation in Oman that successfully utilized both multilateral and intelligent well technologies. The intelligent completion was installed in conjunction with a shrouded Electrical Submersible Progressing Cavity Pump (ES-PCP) lift system, a world's first. The single-valve hydraulic-operated system allows semi-selective zonal control and production testing for cost-effective reservoir management. As will be detailed, in addition to offering the flexibility demanded of a high technology well, this well also shows that such a system can be easily installed with minimal risk.
Surface Facilities Considerations for the Production of a Large Sour Gas Resource and the Injection of Sour and/or Acid Gas
Authors: Sourisseau Kenneth D. , Ibrahim Ibrahim Ahmed , Al-Jabri Adel , Wetzels Guus 
Published: December 2007

Abstract
An on shore reservoir containing a large volume of lean sour gas with hydrogen sulfide and carbon dioxide concentrations of 30 mole % and 10 mole % respectively was considered for production. A study was conducted to determine the feasibility of producing this gas and injecting the sour gas or the acid gas components in adjacent reservoirs. Production, processing, and injection of this gas requires extensive surface facilities. Equipment is required to handle the drop out of elemental sulphur that is expected to occur as the gas is produced. Large gas sweetening units are required, as well as large sour gas compressors. Dehydration of the sweet gas stream is required and dehydration of the injection gas stream is also proposed. Energy integration and heat recovery is an important consideration in the overall plant design. This paper describes the required surface facilities and presents the process, material and energy balance considerations that have been incorporated in the design.

Study Overview
Significant undeveloped sour gas reserves exist in Abu Dhabi. A feasibility study was conducted in ADNOC with the aim to increase sweet gas availability by unlocking these resources. The sweet gas could be the product of sour gas treating, the result of displacing current sweet gas injection volumes, or a combination of the above.
The source reservoir under study contains various zones with different conditions, but the average conditions of the sour gas reservoir used in this study are 380 bara and 142°C.
The average dry gas composition of the reservoir is:55.9 % methane,33.2 % H2S,9.5 % CO2,1.0 % hydrocarbons in the C2-C7 range, and0.4 % nitrogen.
Trace quantities of carbonyl sulfide and mercaptans are also present. The reservoir fluid is assumed to be saturated with water at the reservoir conditions. A calculated water content of 29.4 g/m3 was used. Experience and theoretical considerations indicate that the reservoir fluids are likely to contain elemental sulphur that will drop out of the fluid as it is produced. The well tests did not specifically look for elemental sulphur, but there is anecdotal evidence that the well test tubing was plugged during testing. A conservative design approach was taken, assuming that the reservoir fluid is saturated with elemental sulphur at reservoir conditions. Calculations based on data from Alberta Sulphur Research1 indicate a sulphur saturation of 7.5 g/m3. Reservoir volume estimates and production engineering work indicated that an initial raw gas flow rate of 22.5 106 m3/d would be optimal for the project.
Sweet gas from the project has to meet the normal pipeline specifications of:maximum H2S 20 ppmv,minimum LHV 33.7 MJ/m3,hydrocarbon dewpoint at 39.2 bara of -5°C,water dewpoint at 39.2 bara of -30°C, andthere is no maximum total sulphur specification.
Predicting Carbonate Scale in Oil Producers from High Temperature Reservoirs
Authors: Ramstad Kari , Tydal Trine , Askvik Kjell Magne , Fotland Per 
Published: December 2007

Abstract
Calcium carbonate scale is a common problem in the oil industry leading to reduced well performance and obstruction of the safety valves. Recent field experiences indicate that scaling may be a problem at lower Saturation Ratio (SR) than earlier anticipated. In a high pressure, high temperature Scale Cell crystal growth in synthetic formation water has been studied. Induction times and growth rates have been determined using a microscope cell. The results have been interpreted using nucleation theory. The findings indicate that wells may be safely operated at SR below 2.5 at 85°C. At higher temperature crystal growth is less dependant on SR and the temperature dominates the system. Care should therefore be taken when operating wells at temperature above 100°C.
Enhanced Scale Management through the Application of Inorganic Geochemistry and Statistics
Authors: Webb Philip J. , Kuhn Oliver 
Published: December 2007

Abstract
The surveillance of oil and gas production systems for evidence of scale deposition commonly involves trending well inflow performance, pressure, temperature, rate of flow and the composition of produced water. Surveillance using produced water composition data can be improved by the application of geochemical understanding of formation waters, including the processes that controlled the evolution of formation water composition. Also, use of multivariate data analysis (MDA) techniques provides methods that can resolve subtle and significant differences, and increase the reliability of information derived from produced-water composition data. MDA provides a systematic method of evaluating data as a whole as opposed to single variable investigation, which can overlook significant information.
The information derived from geochemical understanding of formation waters and MDA can also benefit reservoir and production management, for example reservoir compartmentalisation studies and subsea production allocation.
Shell Exploration and Production UK Ltd's operations in the North Sea have benefited from a combined application of geochemical understanding of formation waters and MDA. In addition, formation water composition data derived from residual salt analysis (RSA) of reservoir core has provided additional data for several fields, which has assisted produced- water data interpretation and reservoir management. Examples of the benefits include the case of the ETAP Heron Cluster fields, where well-intervention costs in excess of £1 million per well were saved. The Bittern field benefited from postponement of scale-squeeze treatments when erroneous tracer observations suggested injection water breakthrough had occurred. HPHT prospects in the Central Graben have been assessed for the risk of halite deposition before drilling based on regional studies.
Assessing Scale Risks and Uncertainties for Subsea Marginal Field Developments
Authors: Graham G. M. , Collins I. R. 
Published: December 2007

Abstract
The risks and uncertainties associated with scale control in new field developments can often have a significant impact on the field economics. This can be especially true for marginal subsea fields producing from areas with high barium concentrations in their formation waters. Other aspects such as completion design, reservoir formation and heterogeneity also have a significant impact both on the severity of the scaling potential and also the ability to effectively treat production wells via conventional bullhead squeeze treatments. In this paper we describe an analysis that was conducted during the Pre-Front End Engineering and Design (FEED) stage of a field in the Norwegian sector of the North Sea. The field was expected to produce hydrocarbons from two subsea templates located 1.6km and 6.3km from a floating production system over a field life of ~ 10 years. Seawater injection was preferred over gas injection for pressure support owing to the higher predicted hydrocarbon recoveries. Of particular concern was the high barium concentration of &gt; 700 ppm recorded from an appraisal well water sample, indicating a very severe barium sulphate scaling potential with raw sea water injection. For this field, in addition to the very severe potential barium sulphate scaling regime, a number of factors combined to present an exceptionally severe risk to the fields net present value. This related to: subsea completions with multiple production wells co-mingling at the wellheads (although dual production lines were incorporated into the design plan partially to assist in scale management); and long (500 - 700m) horizontal production wells and completion designs involving open hole screens served to increase the risks associated with scale formation and effective chemical placement. A range of alternative options were examined together with the associated risks and uncertainties. In summary, the most significant risks and uncertainties associated with the economic viability for seawater injection in this field related to: Uncertainties associated with the initial formation water composition.The ability to squeeze treat wells without inducing fines mobilization and plugging sand control screens as observed in analogue fields.The ability to effectively place scale inhibitor treatments along the length of the horizontal producers by bullhead treatments rather than coil tubing operations.The potential for changes in the base case field production scenario
This work therefore allowed the design team to make informed decisions at the pre-FEED stage in a field where scale control had a significant impact on the fields economic viability.