bluuebunny/crossref_metadata_2025_split huggingface dataset:
Through-Tubing Inflatable Intervention Tools and Techniques in a Subsea Well Environment
Authors: Kelbie G. M. , Mackenzie G. 
Published: December 2007

Abstract
With the number of subsea wells increasing so has the requirement to be able to provide lower cost through-tubing live well intervention solutions to a number of well servicing problems. Through-tubing operations on subsea wells are routinely being conducted from a variety of vessels such as monohull or smaller semi-submersible vessels through to larger drilling based rig operations. Many times when performing said remedial or abandonment work on subsea wells the conditions can prove to be extremely challenging to both operator and service provider. Many of the older subsea wells have come to the operating company via a variety of mergers and/or acquisitions and may prove to have a limited history. Often the actual conditions and geometry of the wellbore can be unclear until the subsea well is actually re-entered. However, at this point, the intervention vessel is already on station and incurring daily costs to the operator. In this paper we are going to disseminate several case histories, highlighting the technical and economical advantages that have been achieved in subsea well interventions utilizing through-tubing inflatable intervention tools. Apart from the more recognizable feature of being able to be conveyed into the well on either electric wireline or coiled tubing allowing for live well intervention, the often less perceived advantage of the inflatable type packing element is in its ability to be able to be set in a broad range of both diameters and conditions. Having this ability allows for the operator to have on board the vessel the opportunity to cover many different types of scenarios that may be encountered. This philosophy can markedly reduce the amount of tools required on board to cover a multitude of operations minimizing logistical, storage and cost concerns. One of the presented case histories will highlight how a planned operation prior to load out to plug the completion tubular in order to repair a leaking flowline ended up with the same mobilized tool providing a barrier while being set in the actual subsea tree due to the tubing being found to be parted on entering the well.
Improving Volumetric Sweep Efficiency With Polymer Gels in the Cuyo Basin of Argentina
Authors: Norman C. , Lucia J. De , Turner B. 
Published: December 2007

Abstract
In December 2003, a pilot polymer gel treatment was implemented in the Vizcacheras Field located in Western Argentina's Cuyo Basin. The project included one injection well polymer treatment with the primary objective of improving volumetric sweep efficiency in the subject pattern and, consequently, improving oil recovery. A secondary goal was to reduce water production in the offset producers.
The Vizcacheras Field is a mature waterflood that was discovered in 1965. Upon implementation of the polymer gel pilot in December 2003, field production was 8635 BOPD from 162 producing wells with an average water cut of 96%. The production comes from two heterogeneous fluvial sandstone formations:Papagayos and Barrancas. Approximately 31% of the total oil production comes from the Barrancas formation, the target of this project.
This conformance improvement project began in 2002 with laboratory studies, initial polymer gel treatment design, tracer studies and numerical simulation. The gel chemistry included a medium molecular weight, partially hydrolyzed anionic polyacrylamide polymer crosslinked with chromium acetate. After a monitoring period, positive results were observed in five of twelve offset producers and an expansion project was designed.
The following paragraphs will describe the petrophysical characteristics of the Barrancas formation, including an overview of the field production and waterflood history, as well as the design, implementation, and evaluation of the polymer gel pilot project.
How Reliable Is Fluid Gradient in Gas/Condensate Reservoirs?
Authors: Kabir C. S. , Pop J. J. 
Published: December 2007

Abstract
Collection and analysis of gas/condensate fluid samples present considerable challenges. That is because downhole sampling of a gas/condensate fluid, unlike its oil counterpart, does not guarantee retrieval of single-phase fluid. The same is true for surface sampling because of incomplete surface and/or downhole separation. Given this reality, the PVT analysis of any fluid sample with an equation-of-state (EOS) model demands that the results are verified with independent measurements.
Our analyses of many samples show that a good correspondence exists between the PVT-derived gradient and that obtained from wellbore-flow modeling of production-test data. Older generation formation testers, those prior to 1990, although yielding comparable results, had larger error bars owing to system limitations in repeatability of both pressure and depth measurements.
We developed a yield-temperature correlation to fill in the information void for reservoirs that fall within the bounds of measured data over a large geographic area. Correlating CO2 with formation temperature was a stepping stone to the yield/temperature relationship. This approach is applicable for the analysis of both single-reservoir and multi-reservoir samples, which is particularly useful when rapid assessment is needed over large regions.
Field Application of Combined Kinetic Hydrate and Corrosion Inhibitors in the Southern North Sea: Case Studies
Authors: MacDonald A. W. R. , Petrie M. , Wylde J. J. , Chalmers A. J. , Arjmandi M. 
Published: December 2007

Abstract
This paper details three field applications of combined low dose hydrate (LDHI) and corrosion inhibitor (CI) chemicals in different assets in the Southern North Sea (UKCS) gas producing area. The design and application philosophy is discussed as well as the criteria necessary to manage a safe and efficient chemical transition. The three fields all displayed mid-level degrees of sub-cooling (4 – 8 °C) with operating pressures up to 70 bar with variable water breakthrough. Corrosion was severe in some cases with over 700 ppm of H2S production combined with 1.1 mol % CO2 in the produced gas.
The paper goes onto describe the cost benefits of such applications including increased equipment efficiency, logistical savings of single chemical deployment and lower maintenance costs. In addition improved hydrate and corrosion control was achieved over the incumbent chemical. This approach achieved cost savings, including a saving of $3 million in the first year of application on one of the fields. Environmental benefits have also been realised with reduced chemical usage and discharge and improved environmental profile of the combined products when compared to the originally selected single application chemicals.
From Reservoir to Well: Using Technology for World-Class Results in Trinidad and Tobago
Authors: Samsundar K. , Chung R. 
Published: December 2007

Abstract
The Mahogany field in Trinidad and Tobago was developed as a dedicated gas field with reserves of 2.6 TCF to supply gas to the Atlantic LNG Plant in 1999. At that time the field was the sole provider of gas to the ALNG project. The vision was to ensure that the field was a world class producer that met the demands on the LNG Train 1 market. It was clear from the onset that the only way to deliver this vision was through the use of technology. Even more so since the field is a highly faulted, complex reservoir, that has a thin oil rim.
With over 1TCF of gas already produced, the Mahogany Team is on its way to delivering this result. Technology has been the backbone of the Mahogany field development, with new technology being used from inception through drilling, reservoir monitoring and production. This intimate surveillance of the wells through new technology has generated a wealth of information. Updated simulation models have been generated using this data, which have led to a deeper understanding of the dynamic fluid distribution in the complicated reservoirs. This in turn has been the critical factor in the successful infill development of the field. It is clear that one of the critical success factors in managing the development and exploitation of the field was the use of technology.
This paper will discuss the use of technology along the value chain of first drill to present and will highlight the real benefits of using technology along the way, primarily highlighting the successful use of fiber optic flowmeters, distributed temperature system, acoustic sand detectors and permanent downhole gauges.
A New Approach to Hydraulic Fracturing Modeling—Fully Coupled with Geomechanical and Reservoir Simulation
Authors: Ji L. , Settari A. , Sullivan R. B. 
Published: December 2007

Abstract
Fracturing modeling methods developed for conventional hydraulic fracturing are now being used for unconventional fracturing in waterfracs, water or steam flooding, produced water reinjection, etc. A common feature of these unconventional fracturing processes is the strong interaction among fracture propagation (often with high 3D fluid leakoff), reservoir flow, changes in stresses (poroelastic and thermoelastic effects), and permeability and porosity changes (geomechanical effects) around the fracture. Conventional fracturing models are inadequate under such conditions; moreover, they are also disconnected from well performance forecasting, which makes integrated data analysis difficult.
Therefore, it is necessary to seek a new modeling concept including all these mechanisms and their mutual influences.
This paper describes a method to model hydraulic fracturing with dynamic transmissibility multipliers based on coupled reservoir and geomechanics simulation. The method is the first step in developing a fracturing model fully coupled into reservoir and geomechanics simulation, where the fracture geometry will be also internally calculated from the fracture face displacements in the coupled FEM geomechanical module. The method described here ignores fracture volume but focuses on the effect of fracture on fluid flow and geomechanics in reservoir by introducing pressure/stress dependent dynamic transmissibility multipliers and treating them as a property of the matrix. This approach allows modeling fracture propagation, dynamical multiphase fracture conductivity, clean-up, and pre- and post-frac well performance in a changing stress, pressure and temperature environment, all in a unified manner.
This paper also discusses the strategy of coupling hydraulic fracture propagation, reservoir and geomchanics simulation, resulting in a method to improve the stability of the dynamic hydraulic fracture propagation in coupled reservoir and geomechanics simulation.
The case studies in this paper confirm that the strategy and the method to model dynamic hydraulic fracture propagation coupled with reservoir and geomechanics simulation is feasible, flexible and reliable. It is easy and convenient to implement in conventional reservoir simulators and coupled reservoir and geomechanics simulators (such as GEOSIM).
The Effects of Temperature and Potential Determining Ions Present in Seawater on Oil Recovery From Fractured Carbonates
Authors: Tweheyo M. T. , Zhang P. , Austad T. 
Published: December 2007

Abstract
This paper is one among others on IOR studies in carbonates regarding the effects of potential determining ions on the wettability alteration, and the subsequent effect on oil recovery by spontaneous imbibition. Besides the oil properties, water-composition and rock properties are also important to wettability. It has been documented in previous related work that SO42- and Ca2+ are strong potential determining ions and greatly influence the surface charge of carbonate rocks.
This work concentrates on evaluating the effect of various ratios of the two ions on wettability alteration and spontaneous imbibition at various temperatures. The ionic concentrations were varied both in the initial and imbibing brines. Imbibition tests were performed at 40, 70, 100 and 130°C using out-crop chalk samples, which were aged for 4-6 weeks at 90°C in a modified crude oil with an acid number of 2.0 mgKOH/g. Additional tests were carried out to evaluate SO42- as a wettability modifier without the presence of Ca2+ and/or Mg2+.
The results show that the three divalent ions Ca2+, Mg2+, and SO42-, which are naturally present in seawater, are important in changing the surface charge of chalk and are more effective when they are all present in solution in favourable ratios. They seem to play different roles in the two processes: wettability alteration and spontaneous imbibition, both of which are temperature-dependant. Sulfate adsorption is the key factor in the wettability alteration, but Ca2+ and Mg2+ seem to play a promotional role apparently by lowering the characteristic temperature for the wettability shift from neutral to moderate water-wet.
Wettability alteration and improved oil recovery have also been linked to the stability of the wetting film, attraction forces and activation energy of the process in relation to the [Ca2+]/[SO42-] ratio, and temperature through measurement of contact angles on calcite crystals. Imbibing brines with higher ratios seem to require lower activation energy to establish a liquid-rock equilibrium interface to initiate spontaneous imbibition. The brines also have stronger attraction forces to calcite and require less work of adhesion than brines with low ratios, or completely depleted in Ca2+ and Mg2+. Brines with higher [SO42-] seem to possess more wetting effects and increased potential to spread as the temperature increases.
Numerical Investigation on Hydraulic Fracture Cleanup and Its Impact on the Productivity of a Gas Well With a Non-Newtonian Fluid Model
Authors: Friedel T. 
Published: December 2007

Abstract
To exploit the substantial tight-gas resources worldwide, hydraulic fracturing is, for many cases, economically a viable option. However, despite the state of the art techniques such as multiple fracturing of horizontal wellbores, the gas recovery from these reservoirs is frequently unsatisfactory. Poor reservoir rock quality, strong stress dependency in permeability, hydraulic and mechanical damage caused by the fracturing process and inertial non-Darcy flow effects were considered to be key parameters for poor performance in previous studies. A further one, related to the cleanup of the cross-linked fracturing fluid with its non-Newtonian characteristics, was rarely taken into account before and is the subject of the current paper.
For this purpose, an enhanced three-phase cleanup numerical model is developed. A generalised non-Newtonian fluid flow model for porous media is derived and implemented in a reservoir simulator, capturing the yield stress of common polymer gel.
The model is applied to typical cleanup scenarios. Using the model, it can be shown that the residing, non-recoverable gel (typically 50%) decreases the fracture conductivity and, hence, the production potential of a fractured gas well. This coincides with experiences in the field where these parameters are frequently lower than anticipated. Results of the study further indicate that within the fracture, gel saturations gradually increase towards the fracture tips. Contrary to the assumption made in analytical studies, there is no sharp interface between the residual gel and the reservoir fluids after the cleanup. The new non-Newtonian fluid flow implementation allows for more detailed investigations of fracture cleanup processes and, hence, an improved understanding of formation damage processes in fractured wells. Furthermore, the model enables the design of more successful fracture treatments in tight-gas reservoirs.
Real-Time Production Optimization of Offshore Oil and Gas Production Systems: A Technology Survey
Authors: Bieker H. P. , Slupphaug O. , Johansen T. A. 
Published: December 2007

Abstract
The information flow used for optimization of an offshore oil production plant is described. The elements in this description include data acquisition, data storage, processing facility model updating, well model updating, reservoir model updating, production planning, reservoir planning, and strategic planning. Methods for well allocation, gas lift and gas/water injection optimization and updating of the models are reviewed in relationship with the information flow described. Challenges of real time optimization are discussed.
Applications of Fiber-Optic Real-Time Distributed Temperature Sensing in a Heavy-Oil-Production Environment
Authors: Goiffon J. , Gualtieri D. 
Published: December 2007

Abstract
Advances have been made to temperature monitoring with the application of distributed temperature sensing with fiber optics over the length of the wellbore to provide data for analysis of the well conditions. With this method, an optical fiber to monitor temperature over the entire length of a well is installed. Custom visualization and analysis software then uses the distributed temperature sensing data that is retrieved to perform analysis of well conditions in environments in which heat management is needed.
The capability to retrieve real-time data allows use of visualization and analytical software to provide rapid qualitative analysis prior to obtaining final quantitative results. This process enables improvement of heat management in heavy oil wells by detection of problem areas within the well. The improvements are provided by the capability to compare a large number of data sets.
The fiber-optic technology was initially deployed in a steamflood well in Bakersfield, California over ten years ago.1 Since that time, the technology has been applied in many different producing environments and has proven that monitoring of downhole conditions can provide valuable information for production assessment.
This paper will discuss the significant benefits gained from using this technology in heavy-oil monitoring scenarios.
Advanced Drilling Using a Dual-Bit System
Authors: Gopalsing P. M. 
Published: December 2007

Abstract
In conventional drilling a majority of drilling problems occur during tripping such as key seating and wall sticking. This leads to increase in rig time hence cost is unnecessarily high, especially in deep sea drilling.
Conventional drilling techniques use rotary drill bits which need to be replaced depending on the formations encountered. If the formation is very hard, the bit has to be replaced by a diamond bit. This change of bit requires unnecessary increase in trip time and hence rigs cost. This trip time which can even take a day especially for deep wells and can be eliminated by using a novel method of a drill bit called a "Piggy Back Dual Bit" system.
This paper deals with the design and operation of such a novel Piggy Back Dual Bit system.
This new drill bit system has a tricone bit on the outside and a PDC or diamond studded bit inside. Both the tricone bit and PDC bit are expandable. When hard formations are encountered, the tricone bit is expanded by applied pressure to the mud which engages a latching mechanism in the BHA. By this action also the expandable PDC bit is forced out. The entire expansion mechanism is hydraulically actuated, by the pressure from fluid flowing through the bit. The drilling activity is now controlled by the PDC drill bit doing the drilling through the hard formation, while the tricone bit is now piggy back on the PDC drill bit doing no work at all, other than reaming a bigger hole.
Thus an entire hole can be drilled conveniently without frequent tripping operation to change the bit. Maximum efficiency can be achieved by this mechanism during drilling.
In petroleum industry rig time plays very vital role. By adopting such innovative method as mentioned above tripping time can be substantially reduced.
Improving the Quality and Efficiency of Subsurface Workflows
Authors: Peterson R. D. , Yawanarajah S. , Neisch D. , James S. 
Published: December 2007

Abstract
The authors will show how a unique combination of real-time R&D coupled with strong asset team project alignment has the potential to result in significant improvements in the execution of Shell's Hydrocarbon Development (HD) and Integrated Reservoir Management (IRM) global processes in Shell's Deepwater Gulf of Mexico fields. The solution embodies technology enablers (Scenario and Options Evaluation, Decision Support Systems, Collaborative Environments), and organizational change (Intelligent Workflows, Research and Development, and new Business Models)
The solution consists of a Smart WorkFlow System (SWS), an Uncertainty Management Tool (UMT) and a Smart Collaborative Environment (SCE), all applied in the context of new collaborative work practices. The authors will elaborate how this integrated solution enables the asset teams to optimize their expenditure of scarce resources on the right reservoir scenarios and most relevant sources of risk, such as reservoir continuity or channel sand/shale geometries, all driven by group consensus. The collaborative environment improves execution of the HD and IRM processes through establishment of a common real-time team view. This view increases transparency of technical work, allows for real-time updates on progression of the risk mitigation plan, and allows for playback and critique of decisions in the context of an evolving shared earth framework. Rework is minimized, the efficiency and effectiveness of technical and business reviews are improved, and best practices are captured for global re-use.
The business model establishes a foundation for both Shell and Schlumberger to share the project risk and reward as the solution progresses from sandbox to prototype to commercialization. The authors will also elaborate on critical success factors in such a new collaborative R&D setting.
Towards a Framework for Better Decision Making Under Subsurface Uncertainty
Authors: Peterson R. D. , Yawanarajah S. , Neisch D. , Tabanou E. , James S. 
Published: December 2007

Abstract
The Smart Fields collaboration between Shell and Schlumberger is developing an Uncertainty Management Framework aimed at reducing both Hydrocarbon Development Planning cycle time and improving the quality of decisions made under uncertainty. The objective is to better manage the impact of the full range of project uncertainties on key development decisions.
Schlumberger, working closely with Shell, have developed an Uncertainty Management Tool (UMT) for the purpose of capturing uncertainties, their ranges, additional qualitative and contextual information, and associated risks and action plans. Uncertainty assessments are typically made during the course of discipline and application specific technical work. Whilst not performing uncertainty analysis itself, the UMT aims to maintain an internally consitent view of uncertainties throughout the multi-disciplinary reservoir modeling workflow, which is input to the field development decision making process. Teams would continue to use existing techniques and applications for uncertainty analyis (monte carlo simulation, experimental design etc) but use the UMT for tracking the reduction of uncertainty and risk over time. The UMT tool provides a central repository where this information can be collected, monitored and managed throughout the life of the asset, and archived for future analysis.
Another challenge faced by the asset team is in managing the large numbers of realizations that may be required in order to address the full range of uncertainty. This can be a laborious and time-consuming process, if it is attempted at all. The prototype has the ability to interactively create and edit a realization tree using captured uncertainty information.
The realization tree serves as a guide to the team as they construct their reservoir models. It also allows the team to conveniently track their progress, capture decisions made along the way, and work toward a final concept selection.
In addition to the prototype tool, a model-building workflow using Petrel was developed to assist in ranking and screening static model realizations prior to full dynamic simulation.