bluuebunny/crossref_metadata_2025_split huggingface dataset:
Delivering Value for Tracking Coiled-Tubing Failure Statistics
Authors: Burgos Rex , Mattos Rafael Fernando , Bulloch Scott 
Published: December 2007

Abstract
The concept of tracking coiled tubing (CT) failure statistics for use in developing performance indicators is not new. It has been covered extensively as the subject of previous abstracts. Tracking relies on an established process for reporting and investigation of pipe-related failures allowing the collection of data from CT operations of a leading service provider, which has global representation.
The primary aim of the process is the identification of the immediate cause of the failure and, more importantly, the failure mechanism for the incident. Only with a good understanding of prevailing trends, if any, can remedial action addressing the root cause(s) of the problem be enacted. This is particularly important for an organization with more than 200 CT units and more than 750 CT strings in service over a wide geographic landscape. In an environment of high CT activity, which has been the experience of the last two years, the value of this process cannot be overstated.
The value to overall CT operations is demonstrated in two examples in which the identified failure trends became the focus of separate service delivery improvement initiatives. The first issue resulted in a change in the organization's policy for reel storage and maintenance, while the second caused a modification in the CT unit controls to properly address the root cause. An in-depth discussion of the issues and their mitigation is the subject of this paper.
The most recent paper on this subject presented information covering the period 1995 to 2000. This paper provides updated information on these CT performance indicators, presenting material from activities during the five-year period 2001 to 2005. The evolution of pipe failure trends is covered and contrasted against the changes that have taken place in the CT industry as a whole over the last decade.
Metal-to-Metal Sealing Technology: Bridging the Gap Between Conventional and High-Expansion Zonal Isolation Applications
Authors: Garfield Garry , Mackenzie Gordon 
Published: December 2007

Abstract
Metal-to-metal sealing technology is an innovative type of medium to high expansion seal that uses compliant metal as a pressure barrier and incorporates an extraordinary seal performance envelope that cannot be achieved by conventional elastomeric seals. Zonal isolation tools, including bridge plugs and straddle systems, using metal-to-metal sealing technology in place of conventional elastomers may radically challenge existing engineering philosophies by providing a pressure sealing system capable of exceeding the limitations of other existing sealing technologies and eliminating many traditional elastomeric failure modes.
The metal-to-metal seal has the potential to change the way downhole equipment provides pressure integrity during pressure pumping operations by utilizing a controlled application of load to expand the metal seal to achieve a fully formed pressure barrier which allows for the metal-to-metal seal in bores of up to 160% of the original seal diameter.
In the well servicing market, recent applications of the metal-to-metal seal and the latest lab testing have suggested the prospective of the technology for products for not only the conventional markets but also in the hostile HPHT arena. Metal-to-metal sealing technology could make well suspensions and intervention possible in hostile HPHT wells that were previously deemed inoperable by the complete removal of elastomers from the design. Demonstrating versatility in applications on land to deepwater locations, metal-to-metal sealing devices can be easily deployed on slickline, electric wireline, coiled tubing, or drill pipe to save operator rig time in areas where cost savings are critical.
Case studies of the high performance characteristics of the metal-to-metal sealing technology in terms of design, testing, and implementation will recognize its alignment in regards to conventional elastomeric sealing technologies as well as high-expansion inflatable technology.
Achievements of Smart Well Operations: Completion Case Studies for Hydro
Authors: Raw I. , Tenold E. 
Published: December 2007

AbstractHydro and Schlumberger have worked closely since 1998 to develop and install intelligent completions with increasing functionality in the Norwegian North Sea. This paper will provide and discuss several case histories in the region. These include:Installation of a natural gas lift application to enhance oil production at Troll field, which used a single control line to surface to operate a six-position gas lift valve to regulate flow from the gas cap. Installation of multizone monobore completions in the Oseberg field to offset production decline, in which several highly deviated and long-reach wells were successfully completed in two to three zones with established zonal isolation and flow control.Other case histories include the creation of innovative intelligent completions for multilateral wells with lateral flow control and natural gas lift with the gas cap perforated by tubing-conveyed perforating guns side-mounted on the production tubing.Among the observations made is that implementation of reliable pressure, temperature, and flow monitoring in the industry has not kept pace with the complexity of the flow control capability. The ongoing challenge is to create intelligent wells with reliable monitoring technologies to fully capitalize on the benefits and opportunities of zonal flow control. Innovative completion designs and state-of-the-art reservoir monitoring and control technologies are critical to intelligent well development.
An Imperative Workflow for Modeling of Naturally Fractured Reservoirs on Different Scales
Authors: Heinemann Gabor F. , Bashiri Gholamreza , Harrer Andreas W. , Keramati R. Mohamad , Mittermeir George M. 
Published: December 2007

AbstractMost of the recently discovered giant oil reservoirs are naturally fractured which necessitate dealing with high level of complexity during development. Consequently, negotiation between field owners (government, National Oil Company (NOC)) and the potential International Operating Companies (IOC) are time consuming and may lead to unnecessary loss of business opportunities. The IOC's objective is to maximize the profit using their capital and know how anywhere in the world, whereas the NOC's goal is to generate as much value as possible from their assets. The different key objectives lead compulsorily to different reservoir evaluation workflows.To meet the IOC's needs the BP's Top Down Reservoir Modeling (TDRM) approach may be most suitable, where the most simple appropriate models are used. Details and complexity are only added, if the previous investigations show favorable economics; i.e. in the TDRM approach unprofitable projects - in IOC's point of view - are not analyzed in detail.TDRM is not applicable for NOC's offering oil fields in bidding process, requiring deepest possible understanding of the reservoir's geology, physics, production potential and ultimate recovery as basis for their negotiations.The workflow presented herein aims to achieve the owner's (NOC) objectives in the most efficient way; i.e. asses and minimize uncertainty, reduce project turnaround time and finally end up with a reliable and consistent full field model. The approach is neither "top down" nor "bottom up" but it is rather a "MultiLevel Reservoir Modeling" (MLRM), performing investigations in parallel on different scales in an iterative loop. MLRM requires consistent high sophisticated simulation tools with special options for gridding, upscaling/downscaling and well management.The modeling approach was developed and applied to giant, natural fractured, dual porosity carbonate reservoirs with sparse data and hardly existing production history. The reservoirs have a large lateral extend with varying oil column thickness and bottom water drive. The applicability of the approach to other reservoir types is not topic of this paper.
Enabling Workover Applications With Coiled-Tubing-Deployed Inflatable Packers
Authors: Carrillo J. , Paz A. , Franco E. , Nájera R. , Perez J. , Cabrera J. , Zamarron A. 
Published: December 2007

Abstract
Cantarell field produces a significant portion of the total oil production of PEMEX. Over the past few years, Cantarell oil production has been declining, mainly because of the maturity of the field. Sustaining oil production at current levels is a constant challenge for PEMEX, which is also attempting to increase exploration. One of the main challenges involves an increase in water production, which has led to wells being temporarily shut in until a workover rig becomes available. This waiting time could be years. Meanwhile, PEMEX is investigating alternative solutions to optimize rig utilization and offshore rigless workover options.
Recently, coiled-tubing-conveyed inflatable packers have become a key enabler when performing workover operations while the production tubing remains in place, which enhances timely and cost-effective intervention solutions. Through-tubing inflatable packers have successfully isolated zones during water-control treatments, cementing operations through coiled tubing (CT), and permanent zonal abandonment, thus enabling the operator to perforate the upper oil-bearing zones. The use of through-tubing inflatable packers for zonal isolation is now featured in the rigless workover plan for several wells, which is expected to deliver a significant increase in oil production.
This paper examines these recent applications of through-tubing inflatable packers in the region and presents the relevant well conditions and the criteria used for selection. It provides case histories and best practices from several through-tubing applications. Recommendations for job design, auxiliary equipment, and personnel competency are thoroughly discussed.
First Subrigfloor HWO Intervention System for a Floating Vessel
Authors: Pollock Tim , Armagost Ken , Andersen David , Oser Michael , Besly Jason 
Published: December 2007

Abstract
Current capabilities with coiled tubing and slickline are insufficient to provide complete well intervention support to deep, high-pressure wells drilled from a floating vessel in a deepwater Gulf of Mexico (GOM) field. These intervention technologies limit the allowable departure of proposed wells to 8,500 ft and often restrict intervention scope to "dead well" operations.
A hydraulic workover (HWO) system is being developed to support a deepwater GOM field. The system will be located under the rig floor with heave compensation provided by the rig's riser tensioning system. HWO control will be achieved using a remote panel and operations will be observed from the driller's cabin on closed-circuit television (CCTV). To keep the stack-up height as short as possible, the surface pressure control equipment (PCE) will utilize special unitized body valves. The PCE will be stored on a purpose-built fixture where it can be pressure and function tested prior to rig up. The surface and subsea PCE will include shearing and sealing capability for the largest diameter pipe to be used.
The HWO solution provides a high-strength conveyance method to intervene and operate under pressure from a floating vessel in deep, high-pressure reservoirs. The customized HWO extends intervention capabilities to a departure of 15,000 ft (28,800 ft MD) under 8,800-psi wellhead pressure.
The HWO provides features that enhance personnel safety and economic efficiency. The advantages of a sub-floor HWO include: (1) improved safety by removing personnel from an elevated workbasket exposed to pressure and erratic movement, (2) more efficient operation through use of the rig's regular hoisting equipment, (3) elimination of the need to pull production tubing when extending existing wells, and (4) complete reservoir accessability without the need for satellite wells.
4th-Generation Coiled-Tubing Manufacturing Technology
Authors: DuBois Jon D. , Atwood Martin P. 
Published: December 2007

Abstract
Innovative new technologies in coiled tubing (CT) manufacturing will present new opportunities in the industry. The new technology represents a 4th generation CT manufacturing process known as the Continuous Variable Reduction (CVR) process. A brief overview of current manufacturing technology will be presented followed by key elements of the new CVR 4th generation manufacturing technology. Then, the advantages of the CVR technology will be presented along with examples of new products to come from CVR.
Continuous Variable Reduction (CVR) technology has application in the manufacture of variable outside diameter, variable wall thickness, and variable strength all within the same CT string. There is also application in the manufacturing of small diameter, heavy-wall, high-pressure strings. The CVR process will produce CT without internal weld beads.
The significance of the ability to manufacture coiled tubing with variable OD, variable wall thickness, and varying strength levels without the typical ring or "butt" welds now required to join multiple diameters represents a significant advance in coiled tubing manufacturing technology.
Use of Self-Lubricated Plungers in Sucker Rod Pumps Producing Oil From Wells in North Santa Cruz
Authors: Bertomeu F. , Rodrigues N. , Dottore E. J. 
Published: December 2007

Abstract
Every standard down hole sucker rod pump slips fluid between the plunger and the barrel. This is necessary because they all look to the formation fluid for lubrication to enable the plunger to move up and down in the barrel. Slipping fluids causes several problems. In addition to poor pump efficiencies, if there are solids in the formation fluid, such as formation sand, frac sand, iron sulfide and scale, the pump may experience premature failure. The solids cut the plunger and the barrel increasing the clearance between them, further reducing the pump efficiency. Even more, in certain conditions, the plunger may stick and not pump at all.
Self lubricated plungers are equipped with seals on each end. The seals perform two vital functions. They trap a Teflon based liquid lubricant, and they prevent the formation fluid and whatever solids may be in the fluid from getting between the plunger and barrel. Consequently, the pump is self lubricated with the barrel coated with its own lubricant on every up and down stroke. In addition, formation fluid is not allowed to travel between the plunger and barrel, thereby avoiding wear, pump sticking and accumulation of deposits.
The purpose of this paper is to present to oil producers the advantages experienced with sucker rod pumps equipped with self lubricated plungers in the oilfields of "Pico Truncado", "El Cordón" and "Cañadón León", all located in the north of Santa Cruz, Argentina.
Initial UBD-Reservoir Candidate Screening Prevents Applying the Technology to the Wrong Reservoirs: Case Study
Authors: Babajan Salar , Qutob Hani 
Published: December 2007

Abstract
The Petroleum Development of Oman, PDO has been considering adapting new technologies to ensure that strategic resources are optimally explored, developed and produced during the life cycle of their fields. Among the various options available to achieve these objectives, Underbalanced Drilling technology is considered to evaluatthe benefits over traditional drilling and completion methodologies in terms of reservoir performance.
Accordingly, an Underbalanced Drilling reservoir candidate screening process was initiated to examine the suitability of the technology for seven gas reservoirs in PDO.
The screening process began by taking basic reservoir and drilling data and processing it through expert system software. The software rated the candidacy of the reservoir to help determine the likelihood of achieving success with underbalanced vs overbalanced drilling and completion techniques, to identify the best potential underbalanced candidates from the given portfolio and proceed with a detailed analysis.
The expert system score for underbalanced candidacy is calculated by considering different modules. Each module includes a comparison of the key differentiators between overbalanced and UB techniques that impact the UB candidacy of a reservoir. To make these comparisons, the expert system assumes a well is drilled overbalancedand assesses the potential effect on reservoir performance and then estimates the potential benefit of underbalanced drilled wells with minimal damage.
In this paper, the results of the screening process for the gas reservoirs examined are presented and discussed. The study confirmed that candidate selection is a critical first step before initiating any underbalanced drilling project. It also explains why when correct candidates are chosen, UBD significantly improves productivity compared with conventional overbalanced drilling practices.
Phase Behavior Study in the Deep Gas-Condensate Reservoir With Low Permeability
Authors: Qi Zhilin , Liang Baosheng , Deng Ruijian , Du Zhimin , Wang Shouping , Zhao Wei 
Published: December 2007

Abstract
Recently, more and more deep reservoirs are developed due to the appearances of new technologies. Among them, gas-condensate reservoirs, with high temperature, high pressure, and low permeability, account for a high proportion. As a result, not only gaseous formation water is needed to be considered, reservoir deformation and interfacial phenomena should also be included. It is a big challenge for conventional PVT analysis to acquire real phase behavior.
In this paper, we considered the characteristics of reservoir formation and fluids under the conditions of high temperature, high pressure, and low permeability. Then, two models were developed: dew point prediction model for the oil-gas system, and the prediction model for retrograde liquid saturation during the constant volume depletion development. On the basis of hydrocarbon PVT experimental test with rich gaseous formation water, reservoir deformation and interfacial phenomena are further investigated. The models were applied to a deep gas-condensate reservoir with low permeability in Zhongyuan Oilfield, China. The results demonstrated that interfacial phenomena and reservoir deformation not only increased dew point, made the retrograde process earlier, but also aggravated the effects of retrograde condensation.
Closing the Gap Between Reservoir Simulation and Production Optimization
Authors: Awasthi Ankur , Sankaran Sathish , Nikolaou Michael , Saputelli Luigi , Mijares Gerardo 
Published: December 2007

Abstract
The operation of oil and gas fields requires that a multilevel decision hierarchy is used to address field optimization at all timescales. These decisions affect production volumes and costs, not only in their short-term outcomes but also over the life of the field. Depending on the time scale, several models with varying degrees of complexity and detail are typically used to characterize the reservoir (e.g. material balance, full-physics model, and decline curve). However, the strategy to integrate and maintain these separate reservoir models (describing the same field) is often ad hoc and inconsistent.
To make predictions suitable for short-term decisions, proxy-models (e.g. neural networks, response surface) have been proposed. However, these black-box models do not consider the underlying physics of the reservoir phenomena and are limited to the effects captured in the training data set.
In this paper, we build upon our earlier work [1] on integration of full-field strategic models (physics-based) and short range operational models based on the moving-horizon, parametric identification approach for reservoir simulation. A short-range, reduced-order model structure is developed, and the model parameters are obtained from production history data. Because the model structure is motivated by the decomposition of a full-physics model, it is expected to be feasible to extrapolate outside the range of history data. The reduced-order model also increases the computational efficiency and effectiveness in carrying out the simulation objectives. The benefit of the proposed model is to assist in the short-term decision making in production operations. This paper provides a discussion of the methodology for identifying such physics-based parametric models for production operation workflows. It also presents case studies to illustrate the benefits of this method for real time production operations and closed-loop reservoir management.
Utilization of Artificial Neural Networks in the Optimization of History Matching
Authors: Ramgulam Asha , Ertekin Turgay , Flemings Peter B. 
Published: December 2007

Abstract
Artificial neural networks are becoming increasingly popular in the oil and gas industry. In the past, studies have been done on the use of artificial neural networks in reservoir characterization, field development and formation damage prediction, to name a few. The aim of this study is to provide guidelines to successfully develop and train an artificial neural network (ANN) that will predict reservoir properties that can give an improved history match when input into a reservoir simulation model. An ANN was developed to improve the history match with a "small" number of simulation runs for a reservoir that produced oil, gas and water for a period of ten years. Due to a lack of specific protocols for this type of study, the trial and error process was utilized to establish guidelines and suggestions.
The neural network was developed by using an inverse solution method to formulate the training and testing data. Normalization of the data simplified the neural network, improved its effectiveness and enhanced its performance. The feed-forward network with back-propagation and the hyperbolic tangent sigmoid function (tansig) in the hidden layers of the network proved to be most effective in the training/learning process.
Results indicated that functional links and eigenvalues of various system related matrices were effective in the training/learning process. These provided the network with the necessary connections that linked the inputs to the required outputs. It was necessary to input production differences between the historical and simulated performances at specific times to successfully train the network and predict realistic property values for the reservoir. Data structure and production time intervals influenced the training time as well as the accuracy of the predictions. If time intervals were too short, training times were longer, memorization occurred, and the network could not accurately predict the reservoir's properties. Most of the effective functional links that were successful in the training/learning process included relationships between permeability and other factors such as porosity, areas of the regions in the reservoir and the distances from the producer to the boundaries of the reservoir.