bluuebunny/crossref_metadata_2025_split huggingface dataset:
Packers Designed for Coiled Tubing Completions, Recompletions, and Stimulation
Authors: Scott W. Sid 
Published: December 2007

Abstract
This paper includes mechanical, hydraulic, and inflatable packers designed specifically for use with coiled tubing in completions, recompletions, stimulation and cement work. Illustrations of current use of these packers are discussed: Velocity Strings, Tubing Patches, Tail Pipe Extensions, Gas Lift and Jet Pump Installations, Gravel Pack and Sand Screen Control, Wellhead Repairs, Zone Isolations, and Straddle Stimulation/Testing.
Reservoir Stress Changes Induced by Production/Injection
Authors: Chen Her-Yuan , Teufel Lawrence W. 
Published: December 2007

Abstract
This study uses a 2D poroelastic plane-strain model, together with Mohr's circles, to show some basic behavior of the reservoir stress field during production or injection. The flow-induced horizontal total stress field is analyzed for the evolution, distribution, orientation, maximum vs. minimum, and tension vs. compression. Changes in reservoir horizontal total stresses depend on production/injection mode: become less compressive during production (decreasing fluid-pressure) and become more compressive during injection (increasing fluid-pressure). Furthermore, these changes are anisotropic (i.e., different magnitudes in different directions). The horizontal differential stress, however, tends to stabilize for sufficient large time.
Slug Flow Model for the Prediction of Pressure Drop for High Viscosity Oils in a Horizontal Pipeline
Authors: Colmenares J. , Ortega P. , Padrino J. , Trallero J. L. 
Published: December 2007

ABSTRACT
A modified mechanistic model is formulated to predict the pressure drop in horizontal slug flow for two-phase flow (viscous liquid and air). The model is evaluated by using accurate PDVSA INTEVEP experimental data for liquid with viscosity of 480 cP. A comparison between the modified model and experimental data shows that the absolute average relative error in pressure drop prediction is less than 6%.
Precise Well Placement using Rotary Steerable Systems and LWD Measurements
Authors: Tribe I. R. , Burns L. , Howell P. D. , Dickson R. 
Published: December 2007

Abstract
This paper demonstrates profitable geosteering of a Central North Sea, UK horizontal well by using a Rotary Steerable System (RSS) together with new generation azimuthal Logging While Drilling (LWD) tools. The nature of the Tertiary Turbidite reservoir meant that to be commercial the following criteria had to be met: Maximise stand-off from an oil water contact within a sand unit with a circa 50 ft oil column.Achieve 1500-2000 ft of good quality reservoir.While maintaining the stand-off from the OWC, make a corresponding azimuth turn in order to follow the crestal dome structures of the reservoir trap.Avoid the risk of stuck pipe by carefully monitoring real time drilling and well data and by using RSS technology.
During drilling of the well, correlation software enabled comparison of offset well and real time LWD data and visualisation of the position of the well in the reservoir sequence. This modelling complemented wellsite biostratigraphic and geological correlation work and enabled changes to the trajectory to be planned, which were then achieved while constantly rotating using the RSS tool. Azimuthal density measurements were used in real time and as post-well image logs for structural dip and fault interpretation.
The well was geosteered into a sweet spot within 5 ft of the reservoir roof as much as 56 ft from the OWC. The RSS tool completed the well in a single run of 3844 ft with an average ROP of 68 ft / hr and with no stuck pipe problems. The target of 1500-2000 ft of pay was met with 1980 ft of &gt;20 % porosity sand and 88% nett to gross. Water saturation of 10% was much lower than expected and the well is currently producing at 11,500 bopd.
This well demonstrates the combinability of the latest RSS and LWD technology to successfully meet ever-demanding drilling and geological objectives under circumstances of high-economic risk and ultimately maximise potential well production.
Real Option Evaluation of a Satellite Field in the North Sea
Authors: Galli A. , Jung T. , Armstrong M. , Lhote O. 
Published: December 2007

Abstract
This case study is on a satellite close to a large gas and condensate field in the North Sea. At present one well has been drilled. The discovery well will be recompleted as a producer and one or two more producers are envisaged. These could be drilled straightaway or scheduled sequentially, in which case a revision of the project will be carried out. This paper presents a new way of sequentially updating the technical parameters (e.g. size of reserves, productivity of wells, etc) in response to new well information and incorporates this into a real option evaluation of the whole project.
The production scenario is that the project is stopped as soon as the costs exceed the revenue. Two different models (Black and Scholes and a mean reverting model) have been used to describe fluctuations in the oil price on which the gas price is indexed. Monte Carlo simulations have been used to evaluate the three development options (1 or 2 extra wells, drilled immediately or sequentially) for both price models.
Health, Safety and Environment Impact Assessment for Onshore Sour Gas Wells
Authors: Rezaei C. , Al Mehairy M. M. K. , Al Marzooqi A. 
Published: December 2007

Abstract
It is recognised that the drilling of high sour gas wells entails higher risk to workers, more complex drilling procedures and potentially higher concequences should a well failure occur. The sour gas well studied is known to contain 36% vol/vol of H2S which in the event of a blowout could have a significant impact. Concentrations capable of causing health difficulties could occur over 30 kms from the wellsite. Sour wells with high H2S release potential or those near dwellings require site specific emergency response plans. In case of a significant release of H2S, the health & safety of the public will be protected either by their evacuation or ignition of the well. At night, with stable conditions, the dispersion distances may be increased by a factor of 10.
The emergency response plan comprises an Emergency Planning Zone (EPZ) of 4-km radius and Emergency Awareness Zone (EAZ) of 8-km radius of the sour well. This study combined both an HSE impact assessment of a sour gas well, and a review of the adequacy of the risk management tools for associated drilling operations. Hardware & software measures are introduced to reduce the frequency of well incidents. The principle environmental concerns are potential impacts to air quality associated with flaring or uncontrolled releases of sour gas with high levels of H2S. The environmental impact of this well is within acceptable limits and largely unaffected by the reservoir composition. Waste management at each well site remains the key focus, irrespective of well composition. There are no long-term environmental impacts anticipated, except the loss of vegetation and wildlife habitat associated with the new access roads/wellsites. It must be ensured that the drilling management system identifies the requirement for a HSEIA sufficiently early to allow full incorporation of the findings.
Economic Real Time Fracture Optimization Using Bottomhole Monitoring Systems
Authors: Shepel T. D. 
Published: December 2007

Abstract
Fracturing operations continue to become more sophisticated in design, execution, and evaluation. The advancements in fracturing fluid technology and the increased complexity of fracturing operations have made the already complicated task of calculating an accurate bottomhole pressure (BHP) very difficult. The industry continues to struggle with the complexities of calculating an accurate BHP.
This paper address a technical application of a real time bottomhole pressure and temperature system, which has allowed operators to obtain real time data economically during the fracturing process; including pre-fracture build up, mini fracture, main fracture treatment, flowback, and well production data.
Case studies demonstrate how the bottomhole pressure differs from the calculated value during the fracturing operations. Engineers are better able to make pro-active decisions to optimize the operation, either from the field or from the office, based on the more accurate BHP. In several instances, the main fracture treatment was re-designed after the mini fracture analysis based on an accurate BHP. The paper reviews the theory on how the bottomhole pressure is calculated; shows the many uncertainties related to the calculated BHP; and with case studies, shows the value of accurate bottomhole pressures.
Instrumented Oilfields: Downhole Production Allocation by Passive Acoustic Listening
Authors: Haugen O. , Fallet T. , Nyhavn F. 
Published: December 2007

Abstract
Passive acoustic listening is relatively simple to implement in downhole equipment and has an interesting potential for downhole measurements. During a flow loop test at high temperature and pressure, SINTEF measured the acoustic noise inside a choke valve and developed an empirical model for prediction of flow rates of gas, oil and water. The accuracy is better than 7% FSO. An accuracy of 5% FSO is achieved for sensorfusion of an acoustic sensor with a differential pressure sensor, a watercut sensor and a differential temperature sensor. SINTEF has developed a filterbank HT ASIC for the downhole signal processing of acoustic data.
Autonomous Seabed Data Acquisition
Authors: MacDonald Alastair 
Published: December 2007

Abstract
Within the offshore industry there is growing demand for "faster, better, cheaper" offshore operations, and, whilst not compromising HSE issues, offshore operational parameters are getting ever tighter. The industry knows that only by a radical re-appraisal of traditional operational methodology will it be able to achieve its new objectives.
With the emergence of autonomous technology, the offshore industry is now being offered a new tool for offshore seabed exploration and surveying which meets its demands. After ten years of focused development, Maridan A/S of Denmark has now brought to market its M600 series of autonomous underwater vehicles (AUVs) and this technology is now achieving the industry’s desired operational improvements for offshore surveys. Maridan can safely say that the Maridan M600 AUV is proving its worth in the real world and this technology is no longer the subject of research projects or blue-sky developments. The key features of the Maridan M600 AUV includes: ModularityManeuverabilityNavigationReliabilityAutonomySingle Integrated Sensor suite
Offshore Gas-To-Solids Technology
Authors: Fitzgerald Antony , Taylor Mark 
Published: December 2007

Abstract
BG Group’s Hydrates Gas–to-Solids (GtS) technology has been established to investigate ways of managing gas in regions lacking suitable gas infrastructure and/or local markets. Put simply, the technology amounts to adding natural gas to water and stirring. This converts the gas into hydrate that is then shipped to market for regasification to supply power generation facilities or other gas customers.
The low complexity of this technology and the potential for small-scale modular operation is particularly appropriate for offshore associated gas applications where growing environmental pressures to reduce or eliminate gas flaring frequently create situations in which oil developments cannot proceed if there is no technical or economic means for gas disposal.
BG is progressing further pilot plant scale testing and engineering definition programmes with the aim of targeting a potential commercial plant operation by 2006.
Intelligent Well Technology in Mature Assets
Authors: Akram Navid , Hicking Steve , Blythe Paul , Kavanagh Peter , Reijnen Paul , Mathieson Derek 
Published: December 2007

Abstract
Sustainable growth in mature areas of the oil sector must continually focus on finding additional value often coupled with reducing lifecycle costs. New technologies promise much in realising these aims but must first be successfully implemented. Implementation of new technologies in mature areas often poses significant integration challenges, particularly with respect to existing field infrastructure.
The Northern Business Unit (NBU) of Shell U.K, operator in the U.K. sector of the North Sea for Shell and Esso, operates nine fields that produce 400 Mboepd oil and gas from both offshore platform and subsea facilities. Intelligent well technology, in particular downhole flow control, has been identified as having significant value adding potential for these fields.
The Interval Control Valve or ICV is the core component of a downhole flow control system and is a device analagous to traditional wireline operated sliding sleeves. The ICVs provide on-line remote control of the communication path from the reservoir zone to the production tubing. The devices can be either binary (open and close only) or variable (capable of some degree of choking).
For the mature assets the key value adding capabilities facilitated by the ICVs include the optimisation of oil production, the provision of zonal water management capability and the provision of more flexible cost-effective gas capacity management. In order to realise this potential a number of challenges in terms of integration with existing infrastructure, qualification of new equipment and operating philosophy had to be addressed.
Worked examples are presented for wells installed in the Brent and Tern fields highlighting where the intelligent well proposals add value, outlining the technical challenges and introducing the operating philosophies required to realise lifecycle value post-installation.
A Model-Based Approach to Assist Operation of a Gas-Constrained Multizone Intelligent Completion in the Ness Formation
Authors: van Delden R. M. , Uv E. H. , Jalali Y. 
Published: December 2007

Abstract
We examine the nearly one-year history of a horizontal well equipped with three downhole valves to control production of three presumably distinct sand channels of the Ness formation in the Oseberg field. We present a modeling methodology to assess the impact of downhole flow control on production performance, and explain how this methodology addresses the problems of zonal allocation and valve settings selection.
Implementation of Advanced Wellsite Data Management and Communications System Adds Value and Efficiency to Welltesting Operations
Authors: Pahmiyer Robert , Flowers Andrew , Almanza Edgar , El Assal Hossam 
Published: December 2007

Abstract
In the past, in order to carry out any type of real time analysis or control during a welltest, the subject matter expert had to be present at the wellsite. This paper will describe a recently developed real time operations (RTO) data acquisition and management system that uses advances in software operating systems, networking, telecommunications and Internet/intranet access to allow users to have access to real time data and information regardless of their locations. This type of real time access to well information allows expertise to be available that might not have been in the past due to distance constraints, and time and expense required to travel to the wellsite. It also allows real time collaboration from all individuals who have access to the data, regardless of their location, so that reservoir management decisions can be made quickly and more efficiently.
The system has been successfully deployed on a number of welltests in the deepwater Gulf of Mexico, offshore Egypt and onshore eastern Venezuela. An overview of the operations, which includes efficiency gains and time saved, will illustrate how controlled access to real time data and information via a local area network (LAN), a wide area network (WAN), an intranet, or the Internet can positively affect cost and efficiency by allowing state-of-the-art testing to be performed in remote areas where it previously might not have been possible or economically feasible using traditional testing systems.
Microbial Enhanced Oil Recovery: Diverse Successful Applications of Biotechnology in the Oil Field
Authors: Bailey S. A. , Kenney T. M. , Schneider D. R. 
Published: December 2007

Abstract
The field history and performance of microbial culture products for the oil field is examined. For over 15 years, microbial culture products have been used for paraffin control, production enhancement, well bore treatments as well as for scale and corrosion problems. The wide-ranging capacity of microbes to effect positive changes in oil and water properties is described. The broad spectrum of oil types and formations that have been treated successfully is reported along with treatment protocols. Mechanistic considerations for modes of action are analyzed. Traditionally, these considerations involve the continuous production of biosurfactants, solvents and other oil mobilizing agents.
Continuous advancement of microbial technology has led to more recent development of new applications that use unique metabolic capabilities of microorganisms to address specific well problems. Examples of applying these products to problems in oil field production systems are shown. The outlook for development of new technologies and the future application of these products to the oil field is discussed.
Use of Permanent Resistivity and Transient Pressure Measurement for Time-Lapse Saturation Mapping
Authors: Charara M. , Manin Y. , Bacquet C. , Delhomme J. P. 
Published: December 2007

AbstractOptimization of hydrocarbon recovery requires information on the space and time behavior of the saturation of the various fluids present in the reservoir. This is particularly true for oilfields under secondary recovery such as water flooding, where an even reservoir sweep or zones of by-passed oil can be assessed by a proper description of the water front advance.Permanent downhole electrodes have recently successfully been deployed in oil wells.This technology allows the time variation of the electrode potentials to be interpreted in terms of changes in saturation within the formation. In practice, the depth of investigation of such measurements is however limited. Time-lapse pressure transient is an independent source of information with a greater depth of investigation, therefore provides an adequate complement to the permanent resistivity array measurement.In this paper, we propose to use pressure build-up from shut-in in association to the electrical measurements. After recalling analytical analogies in both types of measurements, we propose a quick-look method for interpreting the time-lapse pressure transients. We then compare the physical and practical advantages of each type of measurement and the domain of application of the two measurements with respect to fluid and reservoir properties. Finally we propose an example showing the benefit obtained by coupling the two techniques.
Jintan: Optimizing Field Development through Multi-Scenario Modelling
Authors: David Frank M. , Weesie H. B. M. Paul 
Published: December 2007

Abstract
A Multi-Scenario Modelling approach was used to select a field development option that is robust for most if not all of the sub-surface realisations. This approach was adopted for the Jintan carbonate gas field, located offshore Sarawak, Malaysia in the South-China Sea. The Jintan field will be developed as a satellite to the nearby M1 offshore gas production facility for the supply of gas to the MLNG Tiga plant, which is currently under construction. First gas is in July 2003. Significant value has been added through an integrated, multi-discipline sub-surface study which provides the basis for the field development plan: (1) cost savings of more than 60% were realised through integration of Jintan in Shell's existing gas infrastructure of Sarawak and by reducing the number of wells from 12 to 6, (2) the expectation initially-in-place volumes increased by approximately 1 Tscf to 4 Tscf of gas.
Key uncertainties for the Jintan field are gross rock volume (GRV) and porosity, permeability (tight streaks, karst and fault features), the initial pressure (due to possible depletion from the nearby producing fields) and the effective aquifer strength. The applied workflow to model these uncertainties included structural uncertainty modelling, stochastic inversion, static reservoir modelling and dynamic simulation.
The deliverable of the (Jason) stochastic inversion study were 93 combined depth/porosity models. Five of the 93 depth/ porosity models were selected for the final porosity modelling and exported to the 3D static reservoir simulation software. The static modelling resulted in 11 different static models, which were used for the dynamic modelling.
In the dynamic simulator, the initial pressure uncertainties were combined with the 11 static models into 33 sub-surface realisations which were then combined with different aquifer strengths and karst realisations. For each of the realisations an optimal development option was selected based on the currently expected capacity/offtake requirements and possible future changes/flexibility.
The resulting field development plan is robust for the following reasons: The selected development option caters for the uncertainty range of almost all modelled subsurface scenarios.Dependent on the subsurface scenario, 4 to 7 wells will be drilled. The exact number of wells required to provide a given capacity will be determined during the drilling phase.Well head compression is required in almost all scenarios but never within the first years therefore allowing sufficient time to monitor the reservoir performance and, if required, execute a compression project.
The described workflow, with a high level of integration between the subsurface disciplines, demonstrates the value of multi-scenario subsurface uncertainty modelling in situations where large uncertainties exist.
Underbalanced Coiled-Tubing Drilling in a Thin Gas Storage Reservoir: A Case Study
Authors: McCallister John V. , Haddad Kerima L. , Keenan Robert 
Published: December 2007

Abstract
This paper is a case study of a Coiled Tubing Drilling (CTD) project in which a lateral extension was drilled from an existing wellbore into a gas storage reservoir. The project took place in the Donegal Storage Field located in Southwestern Pennsylvania. The gas storage reservoir is the Gordon Stray Sandstone at a depth of approximately 2,680 feet true vertical depth (TVD) in the project well (Donegal #4621). The focus of this case study is on the geological and engineering considerations as part of pre-planning and candidate selection, drilling operations, problems encountered during the project, and the deliverability enhancement that was achieved.
The drilling of a lateral extension using CTD technology was considered as a method to improve deliverability for several reasons: the failure of previous attempts to stimulate wells in the field using conventional and unconventional methods, geological considerations (including the extremely limited reservoir thickness of approximately four feet), the wellbore configuration, and the reduced footprint (environmental impact).
Drilling operations used several technologies that are considered unconventional in the Appalachian Basin. Build rates and steering were controlled via an umbilical within the coiled tubing. The umbilical contained an electric line for the transmission of Logging While Drilling (LWD) data, and hydraulic lines to manipulate the direction of the bit. The well was also drilled in a constant state of underbalance using on-site generated nitrogen to reduce mud column weight and four-stage separation to control flow rates at the surface.
Although several problems were encountered, and are discussed at length in the body of this paper, the lateral extension on Donegal #4621 was successful. A 698 foot lateral was drilled with approximately 450 feet located in the storage reservoir. Initial testing indicates that the horizontal extension has yielded over an 8,000% increase in deliverability from this well.