bluuebunny/crossref_metadata_2025_split huggingface dataset:
Atlantis Batch Setting: Operational Performance Close to Perfection
Authors: Valdez H. , Fleece T. 
Published: December 2007

Abstract
Near perfect operational performance may sound a bit presumptuous, but when we look at the statistics around the Atlantis batch setting job performed by BP and the Transocean semisubmersible rig Deepwater Horizon, there is no doubt about the outstanding level of operational excellence reached by the people involved in the project and the reliability of the equipment utilized.
Planning and execution personnel strove to maximize utilization of rig multi-activity capabilities. The application of lessons learned from one location to another in order to improve the efficiency of subsequent operations was a major focus during execution.
As a result, the Atlantis batch set installed 60,239 ft of pipe in 24 subsea locations in an area of 2.4 acres in 91 days with no LTI's, no recordables, no incidents and an overall operational efficiency above 98%. See figure A1 for basic well schematic. Average installation time of the 36 in. x 26 in. x 20 in. casing strings in 6820 ft of water was 5.2 days per well.
Depressurization-Induced Gas Production From Class-1 Hydrate Deposits
Authors: Moridis G. J. , Kowalsky M. B. , Pruess K. 
Published: December 2007

Abstract
Class 1 hydrate deposits are characterized by a hydrate-bearing layer underlain by a two-phase zone involving mobile gas. Two kinds of deposits are investigated. The first involves water and hydrate in the hydrate zone (Class 1W), while the second involves gas and hydrate (Class 1G). We introduce new models to describe the effect of the presence of hydrates on the wettability properties of porous media. We determine that large volumes of gas can be readily produced at high rates for long times from Class 1 gas hydrate accumulations by means of depressurization-induced dissociation using conventional technology. Dissociation in Class 1W deposits proceeds in distinct stages, while it is continuous in Class 1G deposits. To avoid blockage caused by hydrate formation in the vicinity of the well, wellbore heating is a necessity in production from Class 1 hydrates. Class 1W hydrates are shown to contribute up to 65% of the production rate and up to 45% of the cumulative volume of produced gas; the corresponding number for Class 1G hydrates is 75% and 54%. Production from both Class 1W and Class 1G deposits leads to the emergence of a second dissociation front (in addition to the original ascending hydrate interface) that forms at the top of the hydrate interval and advances downward. In both kinds of deposits, capillary pressure effects lead to hydrate lensing, i.e., the emergence of distinct banded structures of alternating high-low hydrate saturation, which form channels and shells and have a significant effect on production.
Optimizing Maintenance and Inspection for New Offshore Installations
Authors: Brandt H. 
Published: December 2007

Proposal
In recent years risk based approaches for planning and developing asset management strategies have emerged as effective means to prioritize spending on maintenance and inspection activities, whilst controlling the costs. Based on extensive experience from Risk Based Inspection (RBI) and Reliability Centered Maintenance (RCM) methodologies, a new integrated Risk Based Asset Management (RBAM) process has been developed in close cooperation with the industry. This integrated process is focused on effective prioritizing, screening and successfully implementing a maintenance and inspection program in order to effectively optimizing business performance.
Asset Operations is a complex process in which reliability, maintenance, safety and environmental issues all need to be addressed and related to business objectives and regulatory compliance requirements. The RBAM process acknowledges the fact that to improve overall profitability; maintenance, inspection and reliability must play a key role together with operations to assure understanding of the factors that affect asset (equipment) performance and availability. This allows development of a business driven asset management strategy that reflects not only the life cycle of the equipment, but also the specific financial targets of the operator.
This paper describes the framework of the Risk Based Asset Management (RBAM) process, and focuses on the methodology developed specifically for implementing a successful maintenance and inspection plan for new offshore installations and developments. The methodology will be illustrated by recent projects and lessons learned from real study cases, with focus on the importance of a successful implementation and the development of a continuous improvement process.
A Fully Adaptive Streamline Framework for the Challenging Simulation of Gas-Injection Processes
Authors: Gerritsen M. G. , Jessen K. , Mallison B. T. , Lambers J. 
Published: December 2007

Abstract
We propose a novel fully adaptive computational framework for the efficient simulation of gas injection processes. For flow, we employ a Cartesian Cell-based Anisotropically Refined (CCAR) grid method together with single-phase Multi-Level Local-Global (MLLG) upscaling. The combination of adaptivity and MLLG reduces process-dependency because it ensures that high permeability paths are well resolved. For transport, we use the Compositional Streamline Simulator (CSLS) that was designed for compositional processes. CSLS incorporates mesh adaptivity along streamlines. It adapts the streamline coverage to concentrate streamlines where needed to resolve transport, e.g. near solution fronts, and to reduce errors introduced by the mappings between the pressure grid and the streamlines.
These mappings are the primary sources of error if streamlines are updated sufficiently frequently and appropriate higher-order schemes are used for propagation of components along streamlines. We reduce the smoothing errors introduced by the mappings by a higher order mapping from pressure grid to streamlines. We use a Kriging algorithm to map from the streamlines to the background grid. Mass balance errors resulting from the mappings are effectively controlled by increasing the streamline density based on a local error indicator. The flexibility of Kriging allows us to include partially traced streamlines that are not required to begin and end at wells. This is not possible with the commonly used mappings that are based on flux weighting.
To reduce errors associated with fixing the pressure field between pressure updates, we developed a higher order global time-stepping method.
We demonstrate the potential of the framework with several calculation examples including 2D continuous CO2 injection, water alternating gas (WAG) displacements, and 3D field scale CO2 injection into a saline aquifer.
Context-Adaptive Project Management: A Scoring Model for Assessing Project Complexity and Uncertainty
Authors: Rahi A. 
Published: December 2007

Abstract
Oil & Gas service companies have used project management techniques to ensure that they can effectively deliver increased value to their customers. The success with these techniques can lead to a philosophy that if a few project management processes are good, then more must be better; or that what worked on one project should work on another. This can lead to frustration and inefficiencies where overly bureaucratic processes are dictated, or result in chaos when the processes applied are insufficient for the job at hand.
This paper analyzes key characteristics of several types of service company projects (integrated field rehabilitation, production, drilling, etc.) and commercial models (turnkey/lumpsum, joint ventures, performance, reimbursable (price book), etc.) to develop a scoring model that classifies projects by Uncertainty and Complexity. The model plots projects in this two-dimensional space and it is shown that projects within a quadrant benefit from similar project management approaches. This provides an adaptive and consistent means by which to calibrate the type and level of project management required to the context of the project. The model also highlights uncertainty and complexity "spikes" in a project's profile that can be addressed proactively in the proposal development and project planning stages. This approach was previously applied successfully in the software development arena1 and has been adapted and extended for the oil & gas industry.
Early applications of this approach have been promising in two case studies that we present. The first is a 2.5–year 350-well turnkey drilling project in the Burgos Basin of Mexico. The second case study is a 10-year integrated field rehabilitation (brownfield) project in the Casabe Field, located in the central part of the Middle Magdalena Valley basin, Colombia. The paper concludes with a discussion of this context-adaptive approach as a key input to overall project portfolio management.
Expandable Sand Screens Selection, Performance, and Reliability: A Review of the First 340 Installations
Authors: Jones C. , Tollefsen M. , Metcalfe P. , Cameron J. , Hillis D. , Morgan Q. 
Published: December 2007

Abstract
Expandable sand screens (ESS®) are a relatively new sand control system, which combines many of the properties of gravel packs with the ease of installation of a stand-alone screen. Although they have been used in a wide variety of applications, they are not considered a panacea and have an operational envelope, which is becoming clearer with time.
Weatherford's ESS system currently (June 2005) has 340 installations and over 700 years of combined production. A recent survey of the installations was analyzed in terms of performance and reliability.
The productivity performance of the ESS has been shown to be very good, with an average skin of 0.3 being achieved in recent openhole applications. ESS completions generally perform better than the baseline models. Where field comparisons were possible, they also performed better than alternative sand control completions.
Over the 340 ESS wells, ESS has a reliability comparable with other sand control systems, with initial failures less than 5% and a production failure rate of 0.021 failures/well.year. This gives a projected survival rate at 20 years of greater than 90%. This rate is expected to get better with improving operations, designs, systems and application selection.
Dealing With H2S in Heavy-Oil Thermal Projects
Authors: Monnery W. 
Published: December 2007

Abstract
There is an abundance of natural gas being discovered and produced that is slightly sour. According to a US Department of the Environment (DOE) survey that includes Canada, about 80% of current and new gas has a hydrogen sulphide (H2S) concentration of 1% or less. Of course, this must be treated to remove the H2S to meet sales gas specifications. For small scale (less than 50 – 100 kg) and large scale (greater than 20 tonne/d) of equivalent sulphur, current technologies appear reasonable. Conversely, for intermediate range (0.1 – 20 tonne/d) equivalent sulphur, current technology has proven to have high capital and/or operating costs and some processes are difficult to operate. Therefore, there is a need for an intermediate scale (0.1 to 20 tonne/d) process with lower capital and operating cost than those currently available. The applications of such a process range from the removal of H2S from acid gas at low pressure produced from the amine process to high pressure raw sour gas. There are additional challenges from sour gas associated with heavy oil thermal projects in that it is at low pressure and contains substantial C7+. The elemental sulphur produced should be of sales grade quality such that the handling of the product can fit into the existing sulphur infrastructure and sold into existing markets. Otherwise, disposal of the product becomes costly and in some cases becomes another environmental problem.
In answer to this need, Xergy Processing Inc. has developed a gas phase direct oxidation process for the above applications as well as treating heavy oil off-gas, fuel gas, power generation gas. The process has relatively low capital and operating costs and is easy to operate, with no equipment that is unfamiliar to the petroleum industry. Conversion to sulphur depends on the process configuration and pressure but ranges from 80% to 99.9+% based on lab and field data.
Run-and-Forget Completions for Optimal Inflow in Heavy Oil
Authors: Freyer R. 
Published: December 2007

Abstract
Heavy oil reservoirs generally suffer from low recovery factors and high operating cost. To optimize recovery and minimize operating cost, experience and insights should be collected to enable shift changes in development costs. Different options for enabling these developments are proven or suggested in this paper. Horizontal or deviated wells are considered the base case.
Heavy oil reservoirs often suffer from: Unconsolidation and sand production due to immature rockemulsions and annular solids transport causing plugging of screens and sand control failuresserious water or steam breakthrough due to mobility ratios preferentially producing unintended fluidsmarginal production rates due to high viscosity and low reservoir pressure.
In addition, steam floods are challenged by high completion costs due to extreme temperatures encountered, and high energy consumption due to production of high temperature fluids.
All of these factors contribute to reduced ultimate recovery and well life.
The paper describes case studies and concepts for the optimization of such heavy oil production systems, including uncemented completions which are very often beneficial to minimize well cost, minimize sand control challenges and maximize recovery.
Laboratory and Field Validation of a Sealant System for Critical Plug and Abandon Situations
Authors: Nagelhout A. C. G. , Bosma M. G. R. , Mul P. J. , Krol G. G. , van Velzen J. F. G. , Joldersma J. S. , James S. G. , Dargaud B. , Schreuder G. J. R. , Théry F. 
Published: December 2007

Abstract
This paper presents case histories and discusses the laboratory validation of a sealant system for plug-and-abandon (P&A) operations in critical gas wells close to habitations. To ensure long-term isolation both inside and outside the original casing, the plan was to mill out the casing and cement and to place the plug from rock-face to rock-face. The milled-out section was planned so that in the worst-case scenario the differential gas pressure would have to be supported by 25 m of cement plug, even though a greater height of cement would be placed inside the original casing above the milled-out section.
Two cement systems were designated as candidates for the plugging operation with slurry properties suitable for the application. The gas-sealing ability of the selected systems was validated with both small-scale and large-scale tests. One system, exhibiting both high flexibility and expansion, met the stringent specifications and did not leak until a differential pressure of more than four times the specification was applied. The paper will discuss the parameters of the selected system, thus providing guidelines for system selection for critical plugging operations. A detailed case history of one well (two plugs) is given along with the results from four other wells.
First Medium Radius Horizontal Well in Marrat Formation in Kuwait: Case History of Umm Gudair 56
Authors: Al-Saeedi M. , Al-Mutairi B. , Al-Enezi D. , Mahesh V. S. 
Published: December 2007

Abstract
Kuwait has been drilling and producing from the deep, sour Jurassic reservoirs during the past 20 years. These vertical wells penetrate heavily fractured, highly pressured reservoirs and produce high quality light oil. There are an increasing number of wells in which depletion, low reservoir pressures and poor reservoir rock quality have meant that they can no longer flow at commercial rates. Horizontal well technology can provide a means to increase reservoir section length and intersect possible oil bearing fractures, thereby enhancing well productivity.
This paper will discuss the challenges of designing and drilling the first deep, medium radius, high pressure well bore sidetrack, from an existing production well, into the Jurassic HPHT reservoirs.
These challenges include the necessity to mill up the existing liner hanger and 80 ft. of casing to allow for any future re-completion, the restricted drill string size of 3 ½″ due to the well being completed with 7 5/8″ casing to surface, the directional target constraints, the hole cleaning difficulties due to the restricted pump rates, hard formations with low drilling rates, drill pipe buckling, the ability to slide in the lateral, and to drill the well without gains, losses or differential sticking.
All these difficulties were tackled using optimized drill string designs, advanced milling and directional technologies including; medium radius build profile, lateral drilling with PDC/insert bits on motors equipped with ABI (at bit inclination) for enhanced steering capabilities and LWD tools. Using these technologies plus recommended practices developed by the operator and service companies enabled the establishment of record performances in Kuwait for this type of well.
The results of the drilling will be presented along with conclusions drawn on the overall operation which will then provide the basis for future optimization in the design and drilling of these types of wells.
Expandable Tubular Successfully Scab Off Severe Casing Leaks
Authors: Bargawi R. A. , Zhou S. , Al-Umran M. I. , Aghnim W. 
Published: December 2007

Abstract
The number of old wells completed with uphole packers showed a dramatic increase in casing leaks. The leaks were dumping aquifer fluid directly to the reservoir and vice versa. Many wells experienced this kind of problem.
The conventional practice to isolate these kinds of leaks was to run and cement a scab off liner. This resulted in running smaller production strings and consequently resulted in a dramatically reduction in the production rate and choking wells with high pressure it also limits future remedial workovers of developed future leaks.
Saudi Aramco launched a campaign to recover and salvage wells that had been affected by severe casing leaks and hot spot corroded sections. The solid expandable liner was introduced in two sizes of casing. Introduction and usage of this new technical application will have a maximum ID after setting the solid expandable to run the maximum tubing size, to achieve the highest production rate.
This paper will describe the successful application of this technology and its comparative advantages, including reduced cost and salvaging wells without the need to sidetrack as had been done before. The paper also includes some review of recently applied casing repair results in several wells.
Evaluation of Drillstring and Casing Instrumentation Needed for Reservoir Characterization During Drilling Operations
Authors: Nygaard G. , Fjelde K. -K. , Nævdal G. , Lorentzen R. J. , Vefring E. H. 
Published: December 2007

Abstract
New technology for transferring downhole data to the surface during drilling operations gives new possibilities for identifying reservoir parameters. More accurate data and higher data transfer rates from the drill bit will be available. In addition, new sensors might be introduced between the drill bit and the surface. Data from these sensors can be transmitted on-line to the surface.
When using a detailed dynamic model of the well and reservoir, the model can be calibrated using available real-time measurements. Improving the data transfer methodology provides measurements with higher accuracy. There are also possibilities of placing sensors along the drill string and incorporate these measurements into the model.
This paper evaluates methods for performing on-line reservoir characterization using available instrumentation. In addition, new sensor positions along the drillstring and along the casing are introduced and evaluated with respect to improvement of reservoir characterization.
A Unique Experience of Using Hydraulic Workover Unit (HWU) for Re-Entry and Drilling Operation Onshore Gabon
Authors: Yunus F. , Dufour J. , Ripayre A. , Mercier M. , Suro C. , Sredensek E. 
Published: December 2007

Abstract
Enhancing oil recovery in onshore mature fields is one of the important aspects of Total Gabon's activity. This involves workover or horizontal sidetracks on existing wells located on Total's various fields within Gabon.
For these operations, Total Gabon faces several challenges. Economical: these operations usually target relatively small oil reserves, therefore the drilling unit choice is a key factor in the operational economics.
Technical: variety of the well candidates is considerable with reservoir TVD ranging between 800 to 2500 meters.
Rig availability: over the past few years, increasingly fewer onshore drilling units were available in Gabon and none of them could fulfill both the economical and technical criteria.
The use of Hydraulic Workover Unit (HWU) was considered as a possible alternative. Fewer and lighter loads would have to be moved between locations. These units have a smaller foot print requiring less civil works and have almost similar capabilities as a light drilling unit.
A feasibility study was carried out and preliminary technical discussions were held with various contractors. It was concluded that this approach was indeed feasible, provided that some modifications were done to existing units: installation of an adequate mud system, improvement on existing rotary heads, reinforcement of the hydraulic power supply to allow 24 hours operations instead of the usual 12 hours.
The HWU campaign started in February 2004 and included three workovers plus four re-entries (horizontal sidetrack after milling casing).
Beside the increase in oil production potential of about 14000 bbls/day, the potential cost saving is about 3.5 Million US$ for the entire campaign compared to a conventional rig operation.
The project provided a valuable learning experience. The use of HWU for re-entry operations is now regarded as a proven technique
Slotted Completion for Sand Management: A Novel Screenless Completion Technique
Authors: Addis M. A. , Khodaverdian M. , Lee C. , Fehler D. 
Published: December 2007

Abstract
Three novel concepts have been identified which realise the benefits of screenless completions. The most developed of the techniques, the slotted completion for sand management, is described along with the underlying mechanism by which it is able to defer or avoid sand production.
The investigation of this novel completion is based on a laboratory testing programme centred around polyaxial cubical samples of Castlegate sandstone, subjected to a 3-d stress regime. The design of these block tests was based, in part, on numerical analyses, using in-house modelling capabilities for simulating Castlegate sandstone. The analysis assisted in defining the borehole and slot dimensions. The pretesting numerical analyses are presented, along with the laboratory block test results. Both the analysis and test results provide ‘proof of concept’ for the mechanisms underlying this novel completion technique.