bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Critical Technologies Enabling Low Cost Development of Thin-Bedded Heterogeneous Gas Reservoirs in the North Malay Basin
Authors: Alessio L. , Howells C. , Chu J. , Abbas S. A. , Wade B. , Ball S. 
Published: December 2007

AbstractCS Mutiara Petroleum is a Petronas Carigali – Shell Malaysia joint operating company formed in 2001, operating since then the PM301 and PM302 exploration PSCs. The company enjoyed a 100% exploration success rate in the North Malay basin, and is now rapidly transitioning into a development venture.A total of six discoveries were made since 2002 within the PM301 block. The nature of these discoveries: modest size, stacked pay, fluvio-marine transitional geological setting, high heterogeneity, partially sub-seismic resolution, creates a range of technical and economical challenges. The application of a number of specific technologies, notably to reservoir characterization are seen key to unlock the potential of these discovered volumes.Technically, in the early stages, the seismic attribute-based prediction of gas sand, using a simultaneous inversion technique, was the key enabler for exploration success, allowing to map the presence of coal versus water and gas sands. Now, success through the development phase requires the application of the following technologies:Neural-net based seismic facies, aimed at resolving lateral heterogeneity at field scale and improving the understanding of the ranges of drainage areas for development wells Low resistivity pay analysis, geared towards understanding of both static (saturation, net-to-gross) and dynamic (permeability) parameters Multiple realisation 3D modelling, using stochastic simulation, guided by techniques borrowed from Experimental Design.In addition to technical challenges, critical to unlocking these volumes is the economical optimisation of the cluster development, within a consistent portfolio management framework. This is done by using modelling at various levels: 3D modelling at field level, testing different geological concepts and the associated key uncertainties; those are then scaled up into an integrated surface-subsurface nodal network model to optimise the development of the discoveries as well as the near field potential remaining prospects.
Enhancing Field Management in Siberia by Quantifying Production Uncertainties
Authors: Tipping D. E. , Deschenya M. N. , Deimbacher F. , Kovyazin D. 
Published: December 2007

Abstract
An analysis of production data from a Lower Cretaceous western Siberia oilfield operated by TNK-BP suggested that the final recovery factor would not exceed 15% with one of the waterflood development plans under consideration. Such a plan clearly left scope for improvement. However, since there were limited surveillance data to infer current depletion from the 8 oil bearing beds, considerable uncertainty existed in locating the remaining reserves. This prompted an examination of the reservoir and well characteristics to quantity these uncertainties in the reservoir potential and, hence, ensure the future strategies to increase recovery are viable. To determine the uncertainty in predictions, it was necessary to create multiple predictive models all matched to observed field data. This matching process is extremely time consuming when undertaken manually. Our experience shows that one model requires about 9 man-months. As a result, we tested a procedure to accelerate the matching using a program with an automated history matching algorithm linked to the dynamic simulator. Although implementation of this method is still ongoing, it has demonstrated the following: Uncertainties are an inherent part of reservoir predictions. For field management, it is important to quantify them so they can be managed.Major increases in work productivity are achievable. Within a period of a week, after determining the uncertainties to be addressed, we obtained 7 different history-matched models each yielding a unique production profile prediction.
Based on the quantification of the uncertainties, we are changing our field management practices. For example, additional surveillance is planned to monitor the depletion in each bed. A further benefit is that this uncertainty evaluation methodology gives us confidence in identifying areas that need additional injection support.
Drilling with Casing Reduces Cost and Risk
Authors: Tessari R. M. , Warren T. M. , Jo J. Y. 
Published: December 2007

Abstract
More than 1.2 million ft of hole has been drilled in over 260 wells with retrievable casing-while-drilling tools. These wells have been drilled with seven casing sizes ranging from 4-1/2" to 13-3/8". The drilling system is composed of downhole and surface components that provide the ability to use normal oil field casing as the drillstring so that the well is simultaneously drilled and cased. The casing is rotated from the surface for most operations
The experience gained while drilling these wells has led to a better understanding of the advantages of the process. It's most effective applications have been to reduce the cost and risks associated with wells which routinely experience lost circulation when drilled conventionally; wells in which well control is difficult for tripping drillpipe; wells where excessive fluid loss into low pressure reservoirs impairs the production and ultimate recovery; and wells where it is difficult to get the casing shoe as deep as needed.
Global Field Results of a Polymeric Gel System in Conformance Applications
Authors: Eoff Larry , Dalrymple Dwyann , Everett Don 
Published: December 2007

Abstract
Water production becomes a major problem as hydrocarbon-producing fields mature. Higher levels of water production result in increased levels of corrosion and scale, increased load on fluid-handling facilities, increased environmental concerns, and eventually, well shut-in (with associated workover costs). Consequently, producing zones are often abandoned in an attempt to avoid water contact, even when the intervals still retain large volumes of recoverable hydrocarbons. Many polymer systems have been applied over the years to control undesired water production from hydrocarbon wells, with varying degrees of success.
For approximately eight years, a polymer gel system based on an acrylamide/t-butyl acrylate copolymer (PAtBA) crosslinked with polyethyleneimine (PEI) has been used successfully for various water shutoff applications. This paper will describe results from a sampling of over 200 jobs performed throughout the world, including the average results from over 90 jobs performed in one geographic location alone. In addition to "standard" matrix treatments, results will be shown for other types of treatment, including a design to plug annular communication and a combination of sealant and temporary gel in an openhole horizontal completion. In addition, laboratory data pertaining to work aimed at increasing the temperature limit of the system will be presented. The original upper placement temperature of the system was approximately 260°F. Data presented in this paper indicates the development of a retarder system that allows the upper placement temperature to be raised to at least 350°F.
Pressure Transient and Production Data Analysis for Hydraulic Fracture Treatment Evaluation
Authors: Ehlig-Economides C. A. , Valko P. , Dyashev I. S. , Economides M. J. 
Published: December 2007

Abstract
The Unified Fracture Design (UFD) concept provides a mechanism to determine the optimal hydraulic fracture design for a given amount of a selected proppant, while modern hydraulic fracture treatment execution offers the potential to achieve the optimal design. The proppant number is a ratio of the proppant permeability and proppant volume product to the formation permeability and reservoir volume product. The cost of the hydraulic fracture treatment is directly related to quality and quantity of proppant injected, and successful achievement of the optimal fracture treatment easily offsets this cost when appropriate economics is considered in the job design. Pressure transient and production data analysis are described in terms of fracture length and conductivity and do not provide measures of UFD parameters. The subject of this paper is the use of post treatment analysis to evaluate the effectiveness of the treatment in terms of dimensionless productivity index, dimensionless fracture conductivity, and the proppant number.
Results of this analysis show that when conventional buildup tests cannot provide the desired post-treatment analysis, in most cases, production data analysis can, and vice versa. The analysis will address both single phase oil and gas primary production and oil production under pressure maintenance or waterflood. Also, non-ideal fractures with height growth beyond the producing formation thickness and fracture skin will be considered. Field examples will illustrate the analysis. The importance of this analysis is paramount for operators trying to optimize high value hydraulic fracture treatments.
Gate Valve Drilling/Milling Operation on the North Slope, Alaska
Authors: Ogundare T. M. , Noreen T. , Olsen C. , Schrupp B. , Smith T. W. 
Published: December 2007

Abstract
Maintaining well control is a key component of well integrity. Keeping all the valves on the wellhead working and "moving" is important for well control. But ever so often due to calcium carbonate build up, exposure to extreme weather conditions, stem breaking as a result of corrosion and other causes there have been reported cases of valve malfunctioning.
Milling out a gate valve is a very tedious operation and could be risky if the proper well control and procedures are not put in place. To date there are not many documentations on this procedure. Experience indicates there are two typical methods of milling out a faulty gate valve.–Using a gate valve drilling/milling machine–Using a coiled tubing unit
Well A and B are both producing wells on the North Slope, Alaska. In well A it was discovered that the master valve would not close fully and the swab valve could not open from the closed position. Well B had a master valve that was damaged in the closed position. Well A's gate valve was milled out using the milling machine and well B's faulty valve was mill out using the coiled tubing unit.
The objectives of this paper are to examine these two methods of gate valve milling and the procedures of the operations. After drilling out the valve, fluid can be pumped down hole to kill the well or wireline tools can be run in the well to set back pressure valves and plugs in order to well control.
The risks that would be typical in a gate valve drilling operations will be examined. The risk analysis should be reviewed prior to the start of the job and documented.
Understanding a Reservoir: 3D Geological Modelling Using Scenario-Based Approach and Conventional Geostatistics, Onshore, UAE
Authors: Al Muhairi Layla Saleh , Ribeiro Maria Teresa , Dharmawan Agung , Al Neaimi Mohamed , Rodriguez-Gonzalez Jose Gregorio 
Published: December 2007

Abstract
A Geological Model was built and an Uncertainty Assessment approach was used to better understand the reservoir behaviour. Conceptual models were used to constrain the number of realizations, all of which are equi-probable solutions that honour both hard and soft data.
The primary inputs were core and log data from the wells. A Neural Net Facies and Rock Typing analysis was also performed. The data went through a data analysis process where the major uncertainties and scenarios were defined, and uncertainty trees created.
Two kinds of trends from regional and local information were introduced into the modeling process:
Depositional regional trends were assumed based on regional geological knowledge of the Facies distribution. Structural trends identified and applied to porosity Modeling.
The uncertainties considered were the structure, the fluid contacts, the continuity of the facies & RRTs, petrophysical properties and variograms ranges. The variability intrinsic of the stochastic methods was also accounted. Many cases were built and pre-ranked using the geological knowledge translated in a set of parameters to cover the uncertainty range.
Ranking of models was done by progressively analyzing the cases/ scenarios considered. Initially, inconsistent scenarios/ cases were discarded. In other words, those that did not comply with the data distribution expected and/or the spatial distribution and consistency with the conceptual geological models are discarded. The weight of each criterion in the decision that leads to abandon a particular case or scenario varies according to the variable modeled.
The final phase involved ranking the different models using body connectivity and volumetrics. The ranking was divided in sets where one variable was considered and others added progressively until all the variables were taken into account, including structure and fluid contacts uncertainty. The selected scenarios were then dynamically evaluated for well and development placement.
Adco Well Casing Cathodic Protection Project
Authors: Al Marzouqi Abdulla 
Published: December 2007

Abstract
Well Casing Corrosion is a serious threat to well integrity, Safety and environment with loss of asset & production shutdowns. In addition to the direct costs that result from corrosion like repairing corrosion leaks, reconditioning or replacing all operations of the system, contingent costs may be incurred.
Average cost of drilling a well USD 2,000,000 Average casing repair cost per well USD 85,000 Average no. of casing repair candidates per year 54 Nos. Total average annual cost of casing repair USD 4,500,000
Integrated Management System—Implementing QHSE Into Projects From Beginning to End
Authors: Iyer Srijayan N. 
Published: December 2007

Abstract
Increasingly, customers, regulatory bodies and the community are demanding that organisations demonstrate responsible environmental performance, provide a safe working environment, quality products and services, and where relevant effective food safety practices. An integrated management system allows businesses to manage their quality, safety, and environmental issues while avoiding unnecessary duplication.
This saves your organisation time, money and resources.
This paper identifies how an organisation can develop a management system in order to avoid duplication of policies, procedures and records, while meeting the requirements of their customers, regulatory bodies and the requirements of ISO 29001:2003 (QMS for the Oil & Gas Industry), ISO14001:2004:, and OHSAS 18001:1999.
Application of Intelligent Completions To Optimize Waterflood Process on a Mature North Sea Field: A Case Study
Authors: Ajayi A. , Konopczynski M. , Tesaker Ø. 
Published: December 2007

Abstract
This paper describes a dynamic reservoir modeling study and recommendations on the field implementation of intelligent well technology (IWT) on a mature North Sea field to quantify the benefit of using the technology for the redevelopment of the field. The study examines the impact of applying intelligent well technology to multiple production and injection wells to accelerate production, reduce well count, extend production plateau period and reduce well intervention.
The field is located in the North Sea with characteristics similar to the Brent field. Major hydrocarbon accumulation exists in four horizons. The field is mature with over 10 years of historical production data from waterflood operations.
The paper discusses issues relating to identification of the best application of IWT in the field and quantification of the potential gains from such application when compared to conventional completion systems. These include assessing the capability of the IWT to maximize oil production while managing water breakthrough and to commingle production from multiple sands while minimizing impact on reserves.
The study highlights potential pre- and post- installation issues with regard to the recommended intelligent well systems. This includes challenges and issues related to integration with existing facilities, well installation, crew preparation, system reliability, etc. The paper also discusses post installation well controls and practical guidance on measuring the predicted benefits from using the IWT.
The paper provides an overview of the application of intelligent well technology on a mature offshore field. The study estimated potential increase in oil recovery factor ranging from 0.48% to 6.1% of STOIIP over field life.
Avon Mod 5020—Technology Infusion Offers Benefits for Workhorse Gas Turbine
Authors: Hillman Gordon , Kendig Bryan , Taylor Dave 
Published: December 2007

Abstract
There are over 200 Rolls-Royce Avon gas turbines operating in industrial service throughout the Middle East Region. They have reliably served the region's oil & gas industry in power generation and mechanical drive applications for nearly forty years. Some operators of the Avon gas turbine have expressed a desire to produce more electrical or shaft power. Others have expressed interests to improve the engine's efficiency to offset higher fuel costs, and/or to allow longer periods of operation between major overhauls.
Rolls-Royce Energy Systems Inc, seeking to address operator demands, has developed the Mod 5020 uprate kit for the Avon gas turbine. The uprate kit provides between 6-8.5% additional power and 3-4% less fuel burn. When operated in a suitable derated mode, the mean time between overhaul is expected to increase by 20%.
This paper is a technical description of the Avon Mod 5020 product, as well as its development program.
Ultra Long-Offset ‘Subsea to Beach’ Controls Technology—Case Study Snohvit
Authors: Acworth Will 
Published: December 2007

Abstract
The Snøhvit project in the Barents Sea is a milestone in subsea oil and gas development, with a record breaking offset and all subsea facilities tied-back to shore.
The key elements of technology required to implement such a new development with a subsea Production Controls System qualified to operate over a distance of 220km are: Long-range communications with no repeatersLong-range supply of power at 3 kVHigh data rate requirementsHV electrical and fibre-optic wet-mating connectorsA cost effective main umbilicalDiverse backup strategies
This paper will focus on the technical achievements in executing this ultra-long offset subsea-to-beach project which is now nearing completion. The implementation of fibre-optic communications, subsea data routing, high voltage and power distribution technologies.Back-up communications on Power "COPS" systemThe Backup Intervention Control System (BUICS) designed for use in the event of main umbilical non-availability.
Successful Deployment of a New Stimulation Chemical, Post-Horizontal-Openhole Gravel Pack in Wells Drilled With Both Water-Based and Oil-Based Drill-In Fluid
Authors: Davidson E. , McMillan D. N. , Martin F. , Morton K. , Lenz R. 
Published: December 2007

Abstract
The Alba field in the central North Sea is an unconsolidated sandstone reservoir with an average permeability of around three darcies. Maximising productivity and extending completion life has been an evolving process throughout the life of this field. Recent practice is to drill the horizontal reservoir section using a water-based drill-in fluid (DIF) and complete with a circulating open-hole gravel pack (OHGP). One current option employs an oil-based DIF prior to gravel packing in brine. Both of these procedures have allowed higher off-take rates from these wells than previous completion practices.
New advances in the nature of delayed stimulation chemicals and the introduction of more effective additives (generating acid in situ downhole) made it of considerable interest to determine whether productivity could be further enhanced. One major obstacle to overcome was the uncertainty associated with the placement and uniform distribution of the stimulation treatment in a horizontal well, allowing the entire filter cake to be contacted and broken down successfully. This paper describes how the deployment problems were successfully circumvented.
A dual density treatment was employed in which both the upper and lower zones of the horizontal well-bore were targeted so that the filter cake on both the upper and lower surface in the hole would be contacted and attacked. Evidence will be provided indicating the placement resulted in an enhanced productivity index compared to conventional, non-stimulated completions. The new stimulation treatment was effective in wells drilled with either a water-based DIF or an oil-based DIF.
Field Implementation of "Squeeze Matrix-Access Reservoir-Targeting" Water Reduction System
Authors: Dalrymple Dwyann , Eoff Larry , Vasquez Julio 
Published: December 2007

Abstract
For many years, bullhead systems to reduce water production have received a great deal of attention from the oil- and gas-production industry. Water production becomes a major problem as fields mature, leading to higher levels of scale, greater lift requirements, more load on fluid-handling facilities, and increased environmental concerns. Because of the completion techniques used in many wells, protecting the hydrocarbon producing interval effectively during a water-control treatment is not always practical or cost-effective. Bullhead systems offer treatments that do not require zonal isolation and are designed to reduce water production with little or no reduction in oil or gas production.
Previous papers have discussed the laboratory development of a new water reduction system based on the use of a hydrophobically modified polymer. This paper will outline the field implementation of this squeeze-matrix access reservoir-targeting (SMART) water reduction system and will describe some of the successes (and failures) in its implementation. Even though bullhead systems such as this do not seal off water zones and, therefore, do not have the capability to completely stop water production, it will be demonstrated that SMART treatments can be economically attractive. While field-wide, multiwell treatments are attractive from the viewpoint of fully assessing system capabilities, single-well treatments can be beneficial to small and large operators alike.
Effects of Formation Damage and High-Velocity Flow on the Productivity of Slotted-Liner Completed Horizontal Wells
Authors: Tang Yula , Yildiz Turhan , Ozkan Erdal , Kelkar Mohan 
Published: December 2007

Abstract
Slotted-liner is a relatively simple and cost-effective well completion technique for horizontal wells. However, fluid flow into a slotted-liner completion is quite complicated due to three dimensional flow convergence around slots and limited open-to-flow areas. Furthermore, the compounded effects of formation damage and non-Darcy flow on the fluid flow towards slotted-liners must be considered in well completion design process.
This paper presents a comprehensive semi-analytical model for estimating the productivity of horizontal wells completed with slotted liners. The semi-analytical model is obtained by coupling the reservoir flow and wellbore flow equations. The model includes the additional pressure drops due to mechanical skin and non-Darcy effect. Additionally, the model could handle non-uniform flux, non-uniform skin distribution, and selective completion with blank pipes. Both oil well and gas wells are evaluated. For gas wells, the standard pseudo-functions are used. Detailed discussion of the effects of formation damage and non-Darcy flow is provided.
Results indicate that the productivity reduction because of formation damage is more significant for slotted-liner completion than the openhole completion due to increased pressure drop with flow convergence in the region with reduced permeability. Control of drilling damage ratio is more important than control of drilling damage radius. High slot density with low phasing angle helps to reduce the non-Darcy flow effect.