bluuebunny/crossref_metadata_2025_split huggingface dataset:
Discrete Optimization of Oil Production in Thin Oil Rim Reservoir Under Geological Uncertainty
Authors: Hasan A. I. , Ciaurri D. E. , Foss B. A. , Kleppe J. 
Published: December 2009

AbstractA control system that distributes fluids from an injection to a production well at an adjustable rate has attracted considerable interest in recent years. Several optimization algorithms have been developed for this system and these techniques have proved to be beneficial in reservoir development. In this study, we propose a discrete optimization approach to increase oil production from thin oil rim reservoirs by smart horizontal wells under waterflooding. The smart well was equipped with several on-off control valves that can be adjusted to reach optimum oil production by maximize sweep efficiency and delay water breakthrough. This bring into optimization problem that involves discrete possible choices with valves settings as decision variables. We perform Binary Integer Programming (BIP) in order to decide valves settings in the injection and production well. BIP is one of linear programming problem where variable required being 0 or 1. These variables correspond with on-off control valves. Preliminary results obtained with this methodology show a significant improvement in the oil recovery factor, and the water saturation at breakthrough is observed to be more uniformly distributed across the reservoir, when compared with the reference non-optimized case. In the second stage of this study we add uncertainty in the geological description of the reservoir (permeability distribution), and perform robust optimization. To this end, we consider statistics of the Net Present Value (NPV) in the optimization objective function. We maximize an average of the NPV, and we control the risk attitude by means of a penalty term that involves the standard deviation of that quantity.
A New Methodology to Safely Produce Sand Controlled Wells With Increasing Skin
Authors: Chitale Ashish A. , Stein Michael H. , Arias Brian J. , Narayanan Ram K. , Schott David W. 
Published: December 2009

Abstract
Monitoring Deep Water Gulf of Mexico (DW GoM) wells with gravel-pack and frac-pack completions is an increasingly challenging task. Wells often experience increasing skin, adding to the risk of completion failure. Historically, sand control completions have experienced a 15% rate of sand related completion failures (King 2003). The industry tends to qualitatively evaluate safe target rates as skin increases. Reducing the flow rate based entirely on an increase in global skin can be too conservative and over-restrict target rate. Thus, it is important to know which components of the increase in skin can cause the completion to fail. Furthermore, it is not well understood how to quantify a safe target rate with the increased skin.
This paper will present a new methodology to evaluate the components of skin increase which could cause sand control completions to fail. The failure mechanism we are addressing is perforations plugging by movement of fines and sand. Our new methodology helps quantify the risk and convert it into a safe target rate. This paper will also present case studies of oil and gas wells in the Na Kika Asset, in DW GoM where this methodology was successfully applied.
The well completions are monitored with BP's flux based approach, (Tiffin 2003; Stein, Chitale, et al. 2005; Keck, et al. 2005). In all cases, the wells experienced increased skin, causing the engineers to choke back the well. The analysis showed that some of the skin increase was due to multiphase effects as the reservoir pressure was below the saturation pressure. Accounting for multiphase flow effects resulted in a 30% higher safe operating rate limit than with a conventional analysis. We also determined which skin components likely caused perforations plugging, thereby increasing the completion flux. The results allowed the Na Kika Asset to produce these wells at their maximum allowable safe operating rate with the higher skin, while producing within the BP's flux based guidelines.
Development of Subsea Safety Systems to Allow Well Testing In European Frontier Areas
Authors: Garcia Soule' Virgilio , Mackenzie Colin 
Published: December 2009

Abstract
Offshore well testing operations in the North Sea have, for many years, been confined to the shallow areas of UK and Norwegian continental shelf with water depths ranging from 100 to 1,000ft. Rig selection of these operations has been primarily moored vessels. New discoveries in the Frontier areas have moved the operations into the deep water regions north of Ireland and west of Shetland where water depths range from 2,500 to 10,000ft. The under-explored regions of the Barents and Norwegian Seas also provide extreme weather conditions in addition to a wide range of water depths. The deeper water prospects have moved operators to the use of dynamically positioned vessels. The combination of high frequency and severity weather systems, deep water and the potential of rapid vessel movement create unique challenges for well testing subsea safety systems.
Subsea safety systems (or as often termed subsea landing strings) are critical to maintaining well integrity during any period were there is the potential to flow hydrocarbons. They typically consist of a lubricator valve to allow in-well tool deployment, a subsea test tree to provide dual-barrier well containment and a disconnect function, and a retainer valve to secure test string contents in the event of a disconnect or shear situation.
To ensure all functional goals are achieved in the conditions found in European Frontier regions, several features of available string types need to be taken into consideration. The key features that are desirable in these challenging operating environments are: Rapid disconnect capability through the use of electro-hydraulic controlsDisconnect capability under string tensionUmbilical protection systemMultiple disconnect methodsAt-tree and below-tree chemical injectionValves capable of cutting coil tubing
These features are not commonly available in landing strings provided for the shallower and more benign conditions found elsewhere in Europe. The technologies required can be developed from the experiences from other deep water regions (such as West Africa and Brazil) and the most extreme North Sea conditions
Accelerating the Commercailization of Exploration Success by the Application of Discovery Driven Development Planning
Authors: Hopper C. T. 
Published: December 2009

Abstract
Discovery driven development planning is a process that balances strategic and business drivers with the more conventional technical drivers of subsurface and facilities design to accelerate the transition of an exploration success to a sanctioned project. The conventional approach is to focus on the subsurface interpretation of the reservoir and to plan the appraisal program. However, the next generation of exploration discoveries are smaller and more complex than in the past, so that even after a full appraisal program many of these discoveries may turn out to be commercially sub economic. Applying a simple conventional linear process that progresses from exploration, to appraisal, to option evaluation, to project development will result in a significant number of stranded discoveries. By exploring in the strategic and business arenas in parallel to an appraisal program, commercial solutions can be discovered that will allow these discoveries to progress into sanctioned projects.
This paper describes a discovery driven planning process where commercial opportunities and business solutions are investigated in parallel to the subsurface work program to facilitate a rapid transition from appraisal to project sanction.
The Value of Well Testing—Optimisation of the West Brae Field
Authors: Tharagonnet Mike 
Published: December 2009

Abstract
The purpose of this paper is to increase the data in circulation regarding the value of well testing on established fields. The results of five phases of optimisation, resulting in a 17% increase in field production, following the change out of the multiphase flow meter (MPFM) are presented.
Background on the West Brae field and the uses of the original MPFM will be discussed. The challenges of monitoring and optimising a subsea field without any measurement at a well level, and the benefits associated with well testing are presented. The five phases used to optimise this six producer well system are detailed, along with the economic benefits seen. These economic benefits are compared to the economic case used to justify the replacement of the original MPFM.
Critical Data Needs for Design of Frac-Pack Completions in Today's Oilfield Environment
Authors: Moreno Bernardo , Haydell Garner , Landry Leigh 
Published: December 2009

Abstract
In an unconsolidated environment, operators often employ frac-packs to stimulate the reservoir as well as to provide sand control. If the frac-pack is designed and applied correctly, the stimulation will not only increase the recovery of reserves and reduce drawdown, but the sand control will remain effective for a long period of time. With rig costs presently as high as $600 thousand or more per day, reducing workover needs is a major consideration in today's oilfield environment.
This paper discusses the crucial design requirements for a frac-pack installation and why accurate reservoir data is critical to the effectiveness of both the pumping and completion aspects of the design.
In the past, assumptions on reservoir information for the frac-pack were often based on historical data and conventional fracturing theories because relevant reservoir information was not available. Following these design parameters often provided inconsistent results that did not meet the intended goals, especially in deeper, higher-pressure environments. Moreover, since frac-pack has now become one of the most common methods used in sand-control completions, and development has moved into deeper, more complicated environments, it is even more critical that the essential tools and data required to meet the operator's goals be used in order to design the frac-pack completion.
This paper will discuss the well parameters and other critical information that enables frac-pack completions to be designed to meet today's more critical reservoir, safety, and cost-efficiency needs.
Swellable Packers Provide a Brownfield Water Management Solution in Open and Cased Hole – Case Histories Including Straddles, Plugs, Slimhole Sidetracks and Testing In Corroded Casing
Authors: Al Douseri Khaled M. M. , Barnes Chris , Young Dustin , Smith Peter E. 
Published: December 2009

Abstract
More than two-thirds of the world's oil and gas is currently being produced from mature fields, and although new prospects continue to be discovered, the industry is realizing that the older finds, now mature, are significantly larger than originally thought. Therefore, much of the world's future oil and gas production will continue to depend on brownfield production. Traditionally, when wells in these fields started to show production declines, operators often chose to abandon them rather than consider rework operations, since most production declines resulted from difficult-to-remediate unwanted water or gas production. In addition to water and gas influx, many fields had less-than-ideal production environments that contained CO2 and H2S, causing corrosion of tubulars.
Realization of the need to revisit mature-field production has encouraged new technologies and remedial options to be developed. One of the recently proven technologies, swellable-elastomer packers, has enabled successful workovers, sidetracks, and re-drills that might otherwise have been too difficult, unreliable, or too expensive to be performed a few years ago. The packer uses the swelling properties of rubber in hydrocarbon or water to expand so that the annulus around the pipe is sealed.
This capability has proved to be a great advantage in older wells where corroded, pitted and otherwise irregular surfaces in addition to reduced wall thicknesses due to corrosion make setting and sealing of conventional packers very difficult.
This paper provides case histories and applications of swellable straddles and plugs in openhole and cased-hole scenarios that have enabled shut-in wells to be placed back into production. The discussion will include coiled-tubing tool and wireline deployment methods, wells in which swellable packers have been run as part of the completion string, and testing of swellable packers that provided seals in corroded casing. The principles and techniques involved are applicable to brownfield situations worldwide.
100% Gelled LPG Fracturing Process: An Alternative to Conventional Water-Based Fracturing Techniques
Authors: Tudor Eric H. , Nevison Grant W. , Allen Sean , Pike Blaine 
Published: December 2009

Abstract
A novel hydraulic fracturing process using 100% liquefied petroleum gas (LPG) has demonstrated quick and complete fracture fluid recovery, significant production improvements and dramatically longer effective fracture lengths. The process gels the LPG for efficient fracture creation and proppant transport. With that there is no compromise in the fracture treatment placed when compared to conventional treatments. However, once the fracture treatment is complete and the viscosity of the gelled LPG is broken, the unique properties of LPG create an ideal fluid for complete cleanup. Removal of this fluid from the invaded zone is easily achieved; relative permeability effects, irreducible saturation behaviour and capillary pressure demands are eliminated. Complete recovery of the LPG is consistently demonstrated.
Following conventional hydraulic fracture treatments, effective fracture lengths are frequently observed to be much less than antcipated fracture lengths. This is seen in lower than expected production or evidenced in pressure transient analysis results. A precursor to the poor fracture performance is poor recovery of the fracturing fluid; often less than 50% is recovered during clean-up. In many reservoirs this unrecovered fracturing fluid remains immobile within the formation creating an obstruction to flow. This significantly compromises effective frac length and results in decreased production.
During the fracturing process and subsequent closure of the fracture, the bulk of the fracturing fluid invades the reservoir matrix along the fracture face, referred to as the "invaded zone". This fluid is forced into the reservoir by the significant pressure differential between fracturing pressure and reservoir pressure. Once in the matrix, removal of fluid from the invaded zone can be very difficult as it is held by relative permeability, irreducible saturation, and/or capillary pressure effects.
Fracturing with 100% gelled LPG was first completed in January 2008. By June 2009 over 210 fracture treatments had been completed. This new process has been applied to a wide range of formations from depths of 750 ft through to 11,500 ft. In this paper, short term technical evaluations, such as post fracture pressure transient analysis, are used to demonstrate the rapid cleanup and effective fracture lengths that approach anticipated fracture lengths. Long term actual production comparisons will be a focus on future papers as results become available.
A Proven Methodology to Select and Validate Leading Process Safety Key Performance Indicators (KPIs)
Authors: Herbert Ian 
Published: December 2009

Abstract
This paper provides operators with a methodology for selecting and / or validating the leading Process Safety Key Performance Indicators related to the Plant Design for facilities or platforms.
The importance of Leading Process Safety KPIs is to provide assurance of barriers, also known as Risk Control Systems (RCSs) under HSG 254, ‘Developing process safety indicators’ (HSE, 2006) ahead of any incident. The majority of leading KPI indicators rely on Inspections, Tests and Maintenance to check the functionality of these barriers. However, validating that the design of the barrier is still appropriate is not covered by current leading KPI checks. Operational changes can introduce new requirements and creeping modifications can undermine the expected operations of aging safety barriers.
This paper provides an overview of the use of operational based hazard reviews as a means to identify where there may be design and/or operational failures in the design of safety barriers. Details are presented for the use of Asset Life reviews to determine potential future failures and replacement requirements of safety barriers. Examples of were safety barriers have been identified as insufficient through minor operational changes and potential future major safety barrier replacement issues are shown. This paper focuses on the Plant Design element of HSG 254 ‘Developing process safety indicators’, (HSE, 2006) which currently applies a leading indicator for the percentage of safety critical items of plant or equipment which comply with current design standards or codes, and where this may be undermined because of age and operational changes.
Maximising Recovery From Mature North Sea Assets by the Implementation of Production Optimisation Initiatives
Authors: Akhtar Masud J. 
Published: December 2009

AbstractOil was first discovered in the North Sea in the 1970's and some of platforms that were erected during that era are still producing albeit the production has dwindled significantly. With the technical costs on the rise oil & gas operators are constantly on the lookout for cheap and simple solutions. These help not only to increase the hydrocarbon production from a well but also helps in improving the overall field recovery factor. However, sometimes expensive well interventions are necessary in order to better understand the problems faced and then use the data acquired to study and then implement a more long-term/ permanent solution.The purpose of this paper is to present details on what kind of solutions that have been implemented within the Alwyn field (producing since 1987) in the Northern North Sea. These production enhancement measures relate to a number of different disciplines ranging from topsides modifications to well interventions to sub-surface. As these disciplines originate from different departments within the Company a well performance team was created with the objective of coordinating all production optimisation studies and their implementation on the field.During the course of this paper more details about the structure of the team would also be provided along with further justification outlining how the team has helped in increasing the production from a number of wells. A large variance in production gain has been observed from these operations dependent on the nature of the intervention this ranged from 50 boe/d to nearly 2,500 boe/d.
Process for Tracking the Evolving Perception of Risk During CO2 Storage Projects
Authors: Polson Debbie , Curtis Andrew , Vivalda Claudia , Saunier Stephanie 
Published: December 2009

Abstract
The paper describes a process for constructing a risk register to be used to track the evolving perception of risk during a CO2 storage project. A project-specific risk register is developed through a structured elicitation process to determine initial perception of risk and through discussion with experts. Regular updating of the register by experts is used to track changes in the assessment of risk as the project progresses and inform decision and actions during the project with the aim of reducing risk to an acceptable level.
Gryphon Field Development—Past, Present and Future
Authors: Templeton Gerhard , Konings Stijn , Wilkie Clare , Benton Paul , Marcas Gabriel , McInally Alan , Ings Rob 
Published: December 2009

Abstract
Gryphon is an early Eocene age field located in block 9/18b and 9/18a-R of the UKCS North Sea. The field has been on production since October 1993 and comprises basin floor high-density turbidite sandstones within the Balder Formation. The thickly bedded Balder turbidite lobes of the Gryphon Field were remobilized during the early Eocene, probably by a catastrophic event such as an earthquake. This resulted in large-scale modification of the original depositional geometries of the sand lobes and the development of seismic scale sand injection wings.
Initial field development was focused on the in-situ massive turbidite lobes. Since August 2004, production started from wells drilled into the injection wings.
Going forward, oil reserves in the Gryphon area will be developed by active oil rim management and drilling of additional development wells.
New development wells can be divided into two distinctive types: massive turbidite lobe targets and progressively more complex injection wing targets. Massive turbidite lobe targets are dynamic targets, generated through reservoir simulation. For this purpose, a completely new dynamic model has been built. Injection wing targets are less affected by existing production and are mainly driven by seismic observations. Given the complex nature of the remaining injection wing targets, technological developments are aimed at improving the seismic data quality.
The new dynamic model also provides a tool to evaluate the resources and the development strategy for the last phase of the Gryphon Field, gas blowdown.
Recent development drilling on the field and recognition of future potential, has allowed further facilities and topsides work to be carried out. This will allow the Gryphon Alpha FPSO to remain on station longer. It is the longest serving permanently moored FPSO in Europe and following the topsides work, the Vessel Class has been extended to early 2013.