bluuebunny/crossref_metadata_2025_split huggingface dataset:
Innovative Expandable Liner-Hanger Application Saves Time on Pinedale Anticline Drilling Operations: Two Case Studies
Authors: Nida Ron , Meijs Raymund , Reed Shawn , Arnold Bill 
Published: December 2007

Abstract
Across the globe, liner casing strings are sometimes required. The installation process leads to a variety of challenges from both cementing and tools aspects. Among the challenges are proper isolation of both formation and liner lap, placement of the liner in the desired position, and associated operational time required to return to drilling operations.
The use of the expandable liner hanger provides a way to better address each of these issues. Well conditions on the southeast Pinedale Anticline require drilling liners to be set at specific casing points to allow all of the productive strata to be penetrated. Because the strata behind the liner string is also gas productive and completed with multiple hydraulic-fracture stimulation treatments, proper isolation behind the liner is critical right up to the lap of the liner across the intermediate casing shoe. The mechanics of the expandable hanger system eliminate the potential for a premature set. The normal operating procedures require testing conventional liner tops and "dressing" cement left on top of the liner. These operations can require substantial investments of time and money. The new technology simplifies these processes and reduces the time required to return to drilling operations.
The cases investigated in this paper have similar wellbore conditions, but were cemented using different methodologies. The first was isolated using a foamed-cementing process, while the second used conventional slurries. Both cases exhibited good isolation, good bond performance across formation and lap, and a faster, more simplified operation compared to conventional mechanical liner-hanger applications.
Geomechanics-Based Automatic Well-Planning Software Provides Drilling Decision Support to Asset Teams
Authors: Givens K. , Luppens C. , Menon S. , Ritchie G. , Veeningen D. 
Published: December 2007

Abstract
Minimizing well costs and associated risks requires well construction planning techniques that account for the interdependencies involved in the well design. The inherent difficulty is that most design processes and systems exist as independent tools used for individual tasks by the various disciplines involved in the planning process. In an environment in which increasingly difficult wells of higher value are being drilled with fewer resources, there is now, more than ever, a need for a rapid well-planning, cost- and risk-assessment tool.
This paper presents an automated process for integrating the well construction planning workflow and accounting for process interdependencies. The process is based on a prototype drilling simulator developed with a consortium of major oil companies in 1999–2000 that first demonstrated the technical feasibility of such a tool. The highly interactive process is encompassed in a software system that
allows well construction practices to be tightly linked to geological and geomechanical models enables asset teams to plan realistic well trajectories by automatically generating cost estimates with a risk assessment, thereby allowing quick screening and economic evaluation of prospects enables asset teams to quantify the value of additional information by providing insight into the business impact of project uncertainties reduces the time required for drilling engineers to assess risks and create probabilistic time and cost estimates faithful to an engineered well design permits drilling engineers to immediately assess the business impact and associated risks of applying new technologies, new procedures, or different approaches to a well design.
Discussion of these points and field examples illustrate the application of the workflow and verify the value, speed, and accuracy of this integrated well planning and decision-support tool.
Modern Carbon/Oxygen Logging Methodologies: Comparing Hydrocarbon Saturation Determination Techniques
Authors: Eyvazzadeh Ramsin Y. , Kelder Oscar , Hajari A. A. , Ma Shouxiang , Behair Abdallah M. 
Published: December 2007

Abstract
Recent advances in Carbon/Oxygen (C/O) logging technology have provided measurements that have become more quantitatively robust in reservoir monitoring projects, especially in mixed salinity environments. Enhancements in tool design, characterization and interpretation algorithms have contributed to increases in precision and accuracy of fluid saturation measurements.
Even though these innovations have led to major improvements, fluid saturation profiles provided by different service companies are often varied. The variations are due to differences in tool designs and interpretation methodologies and thus, a unique solution is not always provided. The inconsistencies in answers are generally not understood due to characterization complexities of the formation and the borehole environment including cements, casing, fluid types, etc.
As a consequence, a study was conducted in a large Middle Eastern carbonate field to evaluate and compare accuracy and precision of different types of Pulsed Neutron Spectroscopy (PNS) tools in a controlled environment. Several open-hole wells were chosen and logged with the latest types of tools under identical conditions with well defined environmental parameters, thus enabling accurate correlations between tool responses and fluid saturations. The accuracy of the results was then evaluated based on a comparison to core, production logs, pulsed neutron sigma, resistivity and fluid sample data.
This paper presents the results of the study and illustrates how differences in service company tool designs, characterizations and interpretational methodologies affect fluid saturation computations in this field. In addition, recommendations are provided on job planning and utilization of this technology in large scale reservoir monitoring projects.
A Novel Technique to Acidize Horizontal Wells with Extended Reach
Authors: Nasr-El-Din H. A. , Al-Habib N. S. , Jemmali M. , Lahmadi A. , Samuel M. 
Published: December 2007

Abstract
Drilling horizontal wells with extended reach is intended to maximize reservoir drainage and minimize water production due to water coning. However, an inherent problem with these wells is poor acid distribution during matrix acidizing, especially in reservoirs with high permeability streaks. This paper discusses an innovative approach to treat horizontal wells with extended reach. This new technique comprises mechanical diversion in the wellbore, and chemical diversion in carbonate formations.
Coiled tubing has been used for years to better distribute the acid in vertical and horizontal wells. However, application of coiled tubing in long horizontal wells is a function of wellbore diameter and length. Coiled tubing cannot reach the total depth of the well if there is large washout, or if the length of the openhole is greater than what the CT can reach. The maximum length that CT can reach depends on the length of the reel, diameter of the coil and wellbore geometry. To extend this length, we have used a hydraulic tractor to pull the coiled tubing to the total depth of the well. This will ensure better acid distribution over the wellbore. To enhance acid diversion in the formation, a visco-elastic surfactant-based acid system was employed.
Wells selected are horizontal that were drilled in a carbonate reservoir in the oil fields (both land and offshore) that are present in the eastern part of Saudi Arabia. The total length of the target zone for the well "A" and well "B" is 13,543 and 20,304 ft, respectively. Typical coiled tubing (1¾-inch) cannot reach the total depth in these wells (CT lockup length is 10,300 ft for well "A" and 13,200 ft for well "B").
A special hydraulic tractor was used to pull the coiled tubing to the total depth of these two wells. A visco-elastic surfactant based-acid system was utilized to remove formation damage induced by the drilling fluid (water-based mud) and enhance the permeability of the formation in the critical wellbore area. Corrosion inhibitor and other acid additives were carefully selected to maintain the integrity of well tubulars, coiled tubing and the tractor (metallic parts, O-rings and seals of the tractor). Before attempting the stimulation of the extended reach well, a water jetting method was adopted to remove near well bore damage resulting from the drilling mud cake and mud invasion. Production logging tests were conducted after drilling the well, after the water jetting treatment, and after the matrix stimulation. The productivity index of the well decreased after the water jetting treatment. However, the acid matrix treatment delivered through the CT-tractor nearly doubled the productivity index of the treated well.
Installation and Application of an Intelligent Completion in the EA Field, Offshore Nigeria
Authors: Constantine Jesse 
Published: December 2007

Abstract
Traditional barriers to general industry acceptance of intelligent well technology have been cost, reliability, and integrated functionality; but, over the past decade, the number of operators that have started to recognize the value potential of intelligent wells has grown. The evolution of intelligent well technology that can now address initial barriers and user perceptions is responsible for this increasing acceptance.
An offshore completion recently installed for a major operator illustrates how two essential factors—correct technology selection and development and operational excellence in planning and installation—can lead to successful deployment of an intelligent well system. This paper discusses the challenges that the project presented, the benefits delivered, and the lessons learned.
Identification and Resolution of Water Treatment Performance Issues on the 135 D Platform
Authors: Yang Chiffon , Galbrun Michel , Frankiewicz Ted 
Published: December 2007

Abstract
The 135 D platform is located in the Campos Basin off the coast of Brazil. The platform functions as a central processing facility, receiving degassed liquids for treatment from four remote production platforms. Dry oil is sent via pipeline to Cabiunas, while water with &lt;20 mg/L total oil and grease (TOG) is discharged overboard. Upon startup, the ability of the systems on 135 D to clean produced water to the required TOG of &lt;20 mg/L was limited. This paper describes the means by which the fundamental causes of the water treatment performance problems were identified and resolved. Modifications to the original process design are discussed, and the impact of those modifications on the quality of discharged produced water is presented.
The root causes that limited water treatment performance on 135 D were identified as a combination of very high variations in arriving fluid flow rates, unexpected variations in solids concentration, process recycle streams, unexpectedly small oil droplets, and sludge generated by the mixing of excess chemicals with inlet fluids.
On-platform modifications to existing process vessels and to the process itself were required to successfully treat produced water whose character varied significantly from design specifications. Since completing modifications, the platform has routinely produced water with &lt;20 mg/L TOG at or above plant design capacity.
Production Profile Evaluation as an Element of Economic Viability and Expected Outcome
Authors: Haskett W. J. 
Published: December 2007

Abstract
Industry needs to move away from standard, volume based, assessment of the success case that only involves the establishment of sufficient recoverable product, within a container of sufficient size, to enable a critical volume of product to be commercialized. Volume based techniques at best, whether deterministic or parametric, serve only to calculate the mean case and as such are insufficient to provide adequate information regarding the true economic potential of an asset or any decision management capability. Frequently, an assumption is made that the recovery factor (bbls per acre foot), or the individual components that lead to the calculation of a recovery factor equivalent, provides a valid assessment of production rate. Economic analyses of prospects tend to be based on and constrained by detailed earth-models, assessments of risk and uncertainty coupled with cursory, deterministic, and biased assessments of rate and production profile. The result is a fairly good record of Chance; finding recoverable hydrocarbons, and an over-estimation of the Uncertainty; finding sufficient hydrocarbons that will produce at economic rates through time providing at least a minimally acceptable volume. This results in economic over-estimation.
We require a more rigorous, uncertainty ranged approach to rate and profile in order to provide a better assessment of the true potential and downside possibilities of exploratory and producing assets. Elements such as Initial Production Rate, Plateau Life, and Total Cumulative Production should be ranged as correlated elements to base reservoir properties such as porosity, saturation, and composition. For appraisal and development planning, the significance and extent of element correlation is assisted by links to an experimental design or other reservoir simulation process.
It is our view that this can only be accomplished via the stochastic approach. Economic outcome is sensitive to initial rate and profile, sometimes to a greater degree than volume. A stochastic approach enables assessment of viability as profile pathways, facility constrained yearly ranges, or "discounted production". This enables identification of valid minimum completion criteria, or at least illuminates risk potential, and establishes a fairer representation of the distribution of expected outcomes.
Intelligent Completions: Lessons Learned from 7 Years of Installation and Operational Experience
Authors: McLauchlan Alan , Nielsen Victoria Jackson 
Published: December 2007

Abstract
Since the first intelligent completion was installed in August 1997, over 200 such systems have been installed globally. The systems installed encompass a wide range of downhole and surface equipment, though some aspects are similar for all installations. This paper will address the lessons learned and best practices developed since the installation of the first system seven years ago.
Detailed project and operational planning is critical to the success of any project, but is of paramount importance to complex projects such as intelligent completions. Operational planning and execution begins before the equipment is manufactured and carries through to equipment testing, shipping, and surface checks prior to picking up the assemblies.
Installation and proper execution is critical for all projects - though specifically important in many of the intelligent completion installations which take place in applications with very high rig rates. To complement success, post-job reviews allow for lessons learned and best practices to be disseminated throughout the intelligent completion provider organization as well as the operating company.
The tangible results of this detailed planning and execution are realized as rig time savings without jeopardizing safety. Though more difficult to quantify, reliability improvements and an increase in customer satisfaction and confidence can be achieved by the incorporation of standardized, downhole components and installation equipment.
Design, Analysis, and Full-Scale Erosion Testing of a Downhole Flow Control Device for High Rate Water Injection Wells
Authors: Russell Ronnie , Barrilleaux Mark , Gai Huawen , Macrae Jonathan 
Published: December 2007

Abstract
There is an increased need for flow control devices that will operate at very high flow regimes in production and injection modes. The deepwater locations of these wells require that this equipment and the well casing operate reliably over the life of the well.
This paper presents the design and full-scale injection erosion flow testing of a new sliding sleeve port geometry. An improved flow port shape incorporates features contoured by Computational Fluid Dynamics (CFD) to dramatically lower erosion for high flow rates. Extensive material testing formed the basis of an erosion model used in the design and configuration of the port geometry. The erosion model and design work are compared and contrasted in a full-scale flow test. This test was run on the pumping vessel "HR Hughes" at the flow rates, sand content, and sand type expected at the reservoir.
This project demonstrates the ability of this flow control equipment to operate at downhole flow regimes higher than anything previously encountered. The full-scale testing of the sleeve port design verified aspects of the design analysis and confirmed the value of this type of testing to ensure design integrity and verify that these devices can operate reliably over the life of a given well. The flow control devices will enable producers to maximize production for a given size of tubing and expand operational flexibility.
Analyzing Well Performance in Hydraulically Fractured Gas Wells: Non-Ideal Cases
Authors: Cramer David D. 
Published: December 2007

Abstract
To facilitate timely solutions, practical gas-well performance analysis is based on ideal (simplifying) assumptions regarding the reservoir, completion and reliability of input data. Yet phenomena can exist in field situations that violate some of the ideal assumptions implicit within the analytic approaches. This paper investigates the impact of several known non-ideal cases on analytic solutions.
Cheap, Directional Wells Drilled Underbalanced With Coiled Tubing: An Experience in the Australian Outback
Authors: Portman Lance , Lan Nguyen , MacArthur Jim 
Published: December 2007

Abstract
Coiled tubing directional drilling can be an expensive operation, requiring a significant quantity of specialized equipment and personnel. This is particularly true of underbalanced drilling operations involving compressible fluids. The cost of using and mobilizing this equipment can be prohibitive.
In some circumstances, the equipment, personnel and engineering requirements can be greatly reduced, leading to a large reduction in the overall operation cost. Such savings are particularly beneficial for smaller campaigns of work in more remote locations. This paper describes many equipment and method simplifications made during a four-well underbalanced, directional drilling campaign conducted in Queensland, Australia.
Solvent / Acid Blend Provides Economic Single Step Matrix Acidizing Success for Fines and Organic Damage Removal in Sandstone Reservoirs: A Niger - Delta Case Study
Authors: Chike Uchendu , Awoleke Obadare , Linus Nwoke 
Published: December 2007

Abstract
The formation of petroleum residue and deposits is a recurrent problem in low API gravity or heavy oil reservoirs and reservoirs with significant pressure and temperature fluctuations. It is also a challenge in fields where recent well interventions has pushed pipe dope into the perforations resulting in severe loss of native formation permeability and productivity.
This paper discusses the application of a unique solvent acid dispersion that offers one step stimulation of reservoirs damaged with both plugging solids and organic deposits. Conventional acid systems including the numerous patented HF - HCl and organic acid blends dissolve the plugging solids and cementitious materials but cannot stimulate sandstone reservoirs damaged with organic deposits or a combination of plugging solids , fines migration and organic deposits. In fact, the formation of acid induced sludge is common.
However, this acid - solvent blend dissolves asphaltene and paraffin deposits, prevents the formation of wax crystals and removes organic residue and inorganic materials simultaneously. A special surfactant train acts synergistically with the acid blend, prevents acid induced sludge and leaves the rock surfaces strongly water wet. Overall treatment efficiency was increased especially in gravel packed intervals by using a rotating jetting tool although success has also been recorded using the bullheading option. Recent experience has shown the acid blend is particularly suitable as a spearhead for injection wells. Optimum solvent loading for effective stimulation is between (10 - 20) percent depending on reservoir temperature, suspected damage mechanism and the severity of relative permeability effects.
Unique experience detailing standard lab / field practice and exceptional results for several wells in the Niger Delta is the focus of this paper. Wells treated with this unique blend either as spearhead for other specialty acid systems or as a one step treatment show dramatic and sustained productivity increases of between (50 - 150) % relative to initial well data. The system has been proven to be successful in most types of completion architecture. Key technical and economic performance indicators including skin factors, production rates, specific productivity indices, payback time and treatment cost indicate this low viscosity acid blend is both technically proficient and cost effective.
Application of After-Closure Analysis Techniques to Determine Permeability in Tight Formation Gas Reservoirs
Authors: Britt Larry K. , Jones Jack R. , Heidt J. Harmon , Adil Imtiaz , Kelly Patrick , Sparkes Dan , Collin Bruce 
Published: December 2007

Abstract
The primary objective of hydraulic fracturing is to create a propped fracture with sufficient conductivity and length to maximize or at least optimize well performance. In permeable reservoirs where transient flow is short lived, a fracture with a Dimensionless Fracture Capacity, FCD, of 2 is required to meet the design objective. In low permeability formations where transient flow can be extensive and where fracture fluid cleanup requires additional conductivity, an FCD in excess of 10 is desired. As a result, reservoir permeability becomes/is a key fracture design and analysis parameter. In higher permeability applications, permeability is determined simply, inexpensively, and routinely through conventional well testing techniques. Conventional well testing in tight formation gas reservoirs has not been proven as effective, can be expensive (cost of lengthy tests and production deferment), and is quite simply not routinely utilized. These reservoirs are often non productive without fracture stimulation and post fracture stimulation testing requires extensive shut-in time as the time to pseudo radial flow is proportional to the square of the fracture half-length. As a result, the development and routine use of any technique to determine permeability in these tight formation gas reservoirs has great value.
In addition, without adequate well testing techniques and capabilities in tight gas reservoirs, the engineer is left with the use of log derived values of permeability which can often overstate in-situ permeability by factors of five to ten. Determination of in-situ permeability not only aids the well completion and stimulation but can be used to calibrate the log and core derived estimates of permeability improving performance predictions and field development. Prior papers have developed the use of After Closure Analysis techniques in permeable reservoirs, this paper will show the application of this technique to several tight gas formations in North America.
This paper will demonstrate the following: The effective application of this technique in tight gas formations in the U.S. and Canada,Develop a cost effective and operationally simple means of collecting and analyzing the data,Compare and contrast the technique to other methods of determining permeability in tight formation gas reservoirs, such as impulse, Perforation Inflow Diagnostic (PID), Closed Chamber Drill-Stem Tests (CCDST), post-frac build-up, production decline analysis, Modular Dynamic Formation Tester (MDT).Show the application and value of calibrating log and core-derived permeability with in-situ measurements for improved well performance predictions.