bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pore Space Characterisation and Permeability Prediction Using Fast Network Extraction and Pore Throat Conductance Calculation
Authors: Schena G. , Favretto S. , Piller M. , Radaelli F. , Rossi E. 
Published: June 2014

Abstract
State of the art X-ray micro-computed tomography (micro-CT) of reservoir rock samples and cuttings allows reconstruction of the pore network with a micrometric spatial resolution that is suitable for petrophysical and fluid flow property evaluation.
Synchrotron beamlines dedicated to tomography, compared to conventional micro-CT systems, allow better 3D representation of the pore space that helps segmentation of the digital-rock volume used for medial axis extraction and for pore space morphological characterization (i.e. connectivity, pore-body/throat size, shape factors, tortuosity of the throats etc.).
The pore-space medial axis is generally derived by computed intensive digital-thinning operations for skeletonization. The alternative method we describe in this work allows the extraction of the 3D centered and ‘shortest’ paths to follow in order to go through the pore space from any given point to another, using simple and well-established mathematical methods. Even if we do not consider explicitly fluid flow, one path can be viewed as the fastest streamline for laminar flow through the pore space from an intrusion point to an exiting point of the digital sample.
The method is computationally efficient and it is also amenable to parallelization.
The conductance of the irregular cross-sections of the throats is calculated with a finite element method (f.e.m.) that assumes fully developed laminar flow in the axial direction.
The network associated with the pore space is solved as a linear system and the absolute permeability of the sample is derived.
This paper reports the results of applications to real oil reservoir sandstone samples and shows the potential of the method to predict petrophysical properties from rock material not suitable for conventional analyses (i.e. drilling cuttings or crushed side wall cores).
HTHP In-Situ Mechanical Test Rig and Test Method for High-Temperature Polymers and Composites
Authors: Yuan Yusheng , Goodson Jim 
Published: June 2014

Abstract
High-temperature polymers and their composites have been used extensively in critical industrial applications, including composite drill pipes, tubing and casing, logging tools, and various drillable tools for oilfield downhole operations. However, when a wet condition is combined with high temperature, most high-temperature polymers and their composites behave very differently from their original dry state because of severe hygrothermal or hydrolytic degradation. In many cases, oilfield service tools are required to perform in a hot-wet fluid condition at temperatures above 204°C and pressures above 70 MPa. These conditions present significant challenges to applications of polymers and composites downhole. Properly characterizing and fully understanding the HTHP hot-wet thermomechanical properties of various high-temperature polymers and composites based on an accurate, environmentally simulated HTHP mechanical test method is extremely important for successful applications.
This paper will present a newly developed HTHP in-situ mechanical test rig and the associated test method for high-temperature polymers and composites. The in-situ mechanical test rig has been performed successfully in a fluid and gas environment up to 204°C and 34.5 MPa. For the first time, true HTHP hot-wet tensile and compressive strengths of a high-temperature epoxy neat resin and selected high-temperature polymer composites have been determined in a real HTHP hot-wet environment in the HTHP in-situ test rig immediately after a period of the HTHP hot-wet exposure. These results are found to be very different from those determined by conventional environmental-mechanical test methods. The authors will briefly review the conventional environmental-mechanical test methods for polymers and composites based on current literature and test standards and will discuss how the new HTHP in-situ mechanical test methods can eliminate the problems with the conventional test methods and procedures.
Local Update of Object-Based Geomodels
Authors: Georgsen F. , Syversveen A. R. , Hauge R. , Tollefsrud J. I. , Fismen M. 
Published: June 2014

Abstract
A method for local updating of object-based facies models by further development of already existing software is presented. An existing facies realization is adjusted to match new well observations by changing objects locally or adding/removing objects if required. Parts of the realization which is not influenced by the new wells are not changed. Local update of a specified region of the reservoir can be performed, leaving the rest of the reservoir unchanged or with minimum change due to new wells.
The main focus in the method is on the algorithm implemented to fulfill well conditioning. The effect of this algorithm on different object models is presented through several case studies. These studies show how the local update consistently includes new information while leaving the rest of the realization unperturbed and thereby preserves the good history match.
Performance Enhancements of Viscoelastic Surfactant Stimulation Fluids with Nanoparticles
Authors: Crews James B. , Huang Tianping 
Published: June 2014

Abstract
High-molecular-weight crosslinked polymer fluids have been used to stimulate oil and gas wells for decades. These fluids exhibit exceptional viscosity, thermal stability, proppant transportability, and fluid leak-off control. However, a major drawback of crosslinked polymer fluids is the amount of polymer residue they leave behind. Polymer residue has been shown to significantly damage formation permeability and fracture conductivity. 1-3 Recently, viscoelastic surfactant (VES) fluids composed of low-molecular-weight surfactants have been used as hydraulic fracturing and frac-packing fluids. The surfactants structurally arrange in brine to form rod-like micelles that exhibit viscoelastic fluid behavior. VES fluids, once broken, leave very little residue or production damage. However, excessive fluid leak-off and poor thermal stability has significantly limited their use.
This paper will introduce newly developed, select nano-size crystals with unique surface charges and will explain how nanoparticle technology pseudo-crosslinks VES rod-like micelles together to improve the fluid loss control and proppant transport of VES fluids to a performance level similar to that of crosslinked polymer fluid. The nanoparticle pseudo-crosslinked VES micelle fluid develops a wall-building pseudo-filtercake on the face of porous media to control fluid loss. When internal breakers are used to degrade the VES micelle structures the leaked-off VES fluid and the pseudo-filtercake breaks into brine water and nanoparticles. Since the nanoparticles are very small and readily pass through the pores of greater than 0.1 md formations, they are flowed back with the produced fluids, and no internal or external "solids" damage is generated.
This paper will present laboratory data that shows how uniquely charged nanoparticles improve VES fluid rheology, leak-off control, and proppant suspension. Also presented are test results comparing nanoparticle enhanced VES to borate crosslinked guar polymer fluids. The mechanisms that enhance the performance of these fluids also will be discussed.
Parallel Streamline Simulation
Authors: Löf Henrik , Gerritsen Margot , Thiele Marco 
Published: June 2014

Abstract
We present an efficient strategy for parallelizing streamline (SL) simulators using shared-memory programming models and evaluate its performance. This is the first work to extensively address parallelization of streamline solvers. We consider shared-memory programming models because of their suitability for SL simulation and because of the need to sustain peak performance on the multi-core processor platforms of the future. We test our implementation on a 8-way Sun Opteron server, representative of the state-of-the-art shared memory systems in use in the industry, as well as the very recently released Sun Niagara II multi-core machine that has 8 floating point compute units on the chip.
We consider both static and dynamic load-balancing algorithms and take into account associated communication overhead and data locality issues. We apply our experimental parallel SL simulator to two examples: the first test case is taken from the 10th SPE comparative solutions project, and the second is representative of large industrial reservoir applications. We use simple, single-phase, linear flow physics in order to clearly distinguish between system-related and physics-related run time performance.
We found that by using a large amount of streamlines per thread the dynamic load balancing strategies built-in to OpenMP performed well as the average workload per thread is not very sensitive to workload variations between individual streamlines. On the Opteron system, we find parallel efficiencies ranging between 60 and 75 %. The sublinear speedup is mostly due to a low degree of data locality in the tracing stage and communication overhead in the mapping stage. In applications with more complex physics, the relative contributions of these stages will decrease. Thus we expect the parallel performance, which is already attractive, to be higher in most industrial applications. On the Niagara II, we obtain almost perfect linear scalability thanks to the lowered communication costs on these architectures. This result is all the more satisfactory considering that future server designs will be akin to this system.
Real Time Well Placement above a Tar Mat, Leveraging Formation Pressure While Drilling and Pyrolytic Oil-Productivity Index Technologies
Authors: Al-Salem Khalid M. , Al-Malki Said S. , Ahyed Rabea A. , Jones Peter J. , Neumann Peter M. 
Published: June 2014

Abstract
Recent development of a large oil field in the Eastern Province of Saudi Arabia achieved real time well placement above a tar mat by utilizing Formation Pressure While Drilling (FPWD) and Saudi Aramco's Pyrolytic Oil-Productivity Index (POPI). Placement of 6 ⅛ in. horizontal power water injector wells in close proximity above an impermeable, undulating, tar layer posed a unique geosteering challenge. Additionally, a heavy oil layer of varying thickness exists above the tar. The uncertainty was to determine at what vertical depth fluid mobility stopped and heavy oil and/or tar began in the high porosity/permeability reservoir.
The heavy oil/tar layer is undetectable with conventional real-time logging while drilling (LWD) measurements. Furthermore, new technology devices such as the 6 ⅛ in. NMR While Drilling tool were not available when the field was developed. A technique of combining FPWD with POPI provided a solution to identify and steer away from the immobile fluids, minimizing the risk of completing an injection well in an interval with low or no injectivity.
POPI collectively refers to pyrolytic methods developed by Saudi Aramco to identify and quantify tar from residual hydrocarbon staining on drill cuttings. Pyrolytic Oil-Productivity Index provides a direct assessment of the residual hydrocarbons present on rock samples and allows an accurate determination of the volume of tar over a wide range of concentrations. The business impact is to assist with geosteering horizontal injector wells in real time. Formation pressure while drilling and POPI results were integrated to confirm favorable fluid mobility and well paths were placed to take advantage of this knowledge. Initial tests showed high injectivity in all wells, which indicates that they were placed in the desired zone. This paper includes selected case studies demonstrating both entry into and steering away from impermeable tar layers.
Production Optimization for Second Stage Field Development Using ICD and Advanced Well Placement Technology
Authors: Maggs D. , Raffn A. G. , Porturas Francisco , Murison J. , Tay F. , Suwarlan W. , Samsudin N. B. , Yusmar W. Z. A. , Yusof B. W. , Imran T. N. O. M. , Abdullah N. A. , Mat Reffin M. Z. B. 
Published: June 2014

Abstract
The paper covers the application of new technology drilling and completions equipment in horizontal wells to maximize production and recovery in a thin oil rim reservoir. The parallel process applied to the engineering design, drilling and completion operations, real-time decisions, and results are presented.
As part of the second stage development of a mature oil field offshore Malaysia, a shallow target was identified. Initial engineering and reservoir studies suggested that three deviated wells or two horizontal wells would be required to develop the area. While the horizontal wells option was expected to have lower costs, the well construction was far more technically challenging. To ensure maximum production and recovery a 2,000ft lateral section was required, further detailed studies indicated that for the long lateral to be successful, well placement with respect to reservoir boundaries and fluid contacts, and open-hole sand screens of a high mechanical integrity would be critical. Additionally, in order to ensure even oil production and limit early water and gas production In-flow Control Devices (ICD) would be required as part of the completion.
The well was actively steered using a Rotary Steerable System (RSS), and Logging While Drilling (LWD) measurements including a deep azimuthal resistivity distance to boundary device. Drilling was very efficient with the well placed close to the top of the sand, avoiding shale contact that could cause screen plugging, and the required distance from fluid contacts. The Real-Time (RT) logs were used to select optimum settings for the adjustable ICD completion prior to running in hole. The completion was run without incident and when the well was placed on line, produced without water breakthrough and without requiring gas lift due to effective clean-up of the entire horizontal section. Production from the well has exceeded expectations and is currently over double that of traditional wells.
The application of advanced well placement technology and field adjustable ICD completions has enabled the economic development a small area of remaining hydrocarbon in a mature field, while maximizing production and recoverable reserves. Even with the increased technology cost, the overall project cost was 15% less than if standard well construction techniques had been applied. The accurate placement of the wellbore close to the upper shale and even production along the lateral due to the ICD completion has resulted in a more efficient reservoir sweep increasing recoverable reserves by ~100 MSTB.
The Kitina Mature Offshore Field Rejuvenation: Massive Multistage Hydraulic Fracturing, Long Reach Wells, Improved Oil Recovery Techniques
Authors: Tealdi L. , Obondoko G. , Isella D. , Baldini D. , Baioni A. , Okassa F. , Pace G. , Itoua-Konga F. , Rampoldi M. 
Published: June 2014

Abstract
Many West Africa Offshore Fields are maturing and operators are completing secondary targets in their wells to maintain the economic operation of their valuable assets. However, off-shore environment makes the capital expenditure associated to this kind of interventions of critical importance. It follows that the selection of the right and most remunerative activities is crucial.
In the Kitina Field, offshore Congo, deeper sands have been produced to economic depletion and reservoir studies allowed the determination of alternative production intervals for production maintenance. Large quantities of reserves can be found in low permeability, consolidated, formations as well as in very deep and remote culminations.
During the first semester of 2007, the Kitina field production increased of 160% reaching a production level lost since early 2004. This was achieved with a variegate set of actions on different reservoirs: 1st) infilling the Kitina South culmination with the long reach and ultra deep well KTM-SM5, 2nd) a massive multistage hydraulic fracturing campaign carried out on the three wells draining the low permeability 3A reservoir and 3rd) with the sweep optimization of the reservoir 1A.
Eight propped hydraulic fractures were placed in three re-completed, cased-hole wells with very significant production improvements. These represented the first applications in Congo of different technologies opening a wide range of further applications in similar environments.
The paper describes the 2007 and 2008 Kitina rejuvenation campaign with an eye to all the disciplines involved, from reservoir engineering and modeling, to operation geology, drilling and completion, production.
The papers focuses with more detail on the successful multi-stage hydraulic fracture campaign from the preliminary design and production forecast pre-job to the reservoir model history match and forecast phase post-job. Interesting reservoir engineering overviews of the future development of the field via improved and enhanced oil recovery techniques are also presented.
Real Option Theory Complements the Stage and Gate Process: the Value of Information
Authors: Azzarone D. , Bruni T. 
Published: June 2014

Abstract
Phased project management processes, also known as stage and gate management processes (SGMP), are widely used to macro and micro-manage projects from early evaluation, to sanctioning and close out. These tools tend to disassemble by discipline the activities and decisions disseminated along the life of a project and re-bundle them into standardized sequential phases, with the underlying intention to narrow down uncertainties and multiply the project value.
By virtue of the implicit set of routines and checks, SGMPs have successfully brought a great deal of discipline in the allocation of human and financial capital among competing prospects – albeit not enough. Uncertainty is the scapegoat our industry too often resorts to to justify otherwise inexplicable failures. The variability embedded in the oil and gas business (nature, raw materials prices, etc.) undeniably plays to the detriment of our industry's bottom line but it is not the only delinquent in the game. Ultimately, opportunities are passed over on account of inappropriate assessment of the value of uncertainty and of acquiring the information (Value of Information, VOI) necessary to narrow it down.
Finance-derived Real Options have long been proposed to guide investment decisions and overcome the limitations of NPV-based approaches. However, Real Options have failed to win proselytes because of undeniable mathematical complication and an ill-fated fame to be too volatile a concept to fit into 150-year old oil and gas industry.
A novel approach is presented that complements the structured framework of SGMPs with VOI evaluation. The result is a project management tool that preserves the merits of SGMPs while warranting improved financial discipline.
Coupled Well and Reservoir Simulation Models to Optimize Completion Design and Operations for Subsurface Control
Authors: Wan Jing , Dale Bruce A. , Ellison Tim K. , Benish Tim G. , Grubert Marcel A. 
Published: June 2014

Abstract
Ensuring long-term optimum completion performance is important for the economic development of any field. As fields are now developed with fewer wells and in more technically challenging environment, new technologies are required to provide guidance and quantify the impact of completion design. This paper presents a new methodology in coupling ExxonMobil's reservoir simulator and a detailed well hydraulics simulator that simulates reservoir, wellbore tubing and wellbore annulus flow simultaneously. Case studies indicate that unique completions opportunities in optimizing completions options, especially inflow control devices, are captured by using the modeling capabilities
Completion strategies frequently include provisions to 1) maintain a uniform production profile along the wellbore, 2) manage future risks (early water or gas breakthrough) and mitigate the potential for sand production, and 3) improve reservoir recovery. Completion options include open hole, cased hole, inflow regulation devices (inflow/flow control devices and inflow valves), sand screens, or pre-drilled liners. Different from nodal based wellbore simulation in a conventional reservoir simulator, the proposed coupled well and reservoir simulation provides not only detailed information on the tubing and annulus flow and associated pressure drops in and throughout all completion types, but also the impact of completions on short and long term reservoir flow and recovery. Studies have shown the importance in utilizing the coupled model in both history matching and model prediction when advanced completions are applied. The significance of this new coupled approach is its ability to capture both flow dynamics through various completion options and reservoir performance
Control-Relevant Upscaling
Authors: Vakili-Ghahani S. A. , Jansen J. D. 
Published: June 2014

Abstract
The conventional reason for upscaling in reservoir simulation is the computational limit of the simulator. However, we argue that, from a system-theoretical point of view, a more fundamental reason is that there is only a limited amount of information (output) that can be observed from production data, while there is also a limited amount of control (input) that can be exercised by adjusting the well parameters; in other words, the input-output behavior is usually of much lower dynamical order than the number of grid blocks in the model. Therefore, we propose an upscaling approach to find a coarse model that optimally describes the input-output behavior of a reservoir system. In this control-relevant method, the coarse-scale model parameters are calculated as the solution of an optimization problem that minimizes the distance between the input-output behavior of the fine- and coarse-scale models. This distance is measured with the aid of the Hankel- or energy norms, where Hankel singular values are used as a measure of the combined controllability and observability of the system. The method is particularly attractive to scale up simulation models in flooding optimization and/or history matching studies for a given configuration of wells. An advantage of our upscaling method is that it intrinsically relies most heavily on those parameter values that directly influence the input-output behavior. It is a global method, in the sense that it relies on the system properties of the entire reservoir. It does not, however, require any forward simulation, neither of the full nor of the upscaled model. it also does not depends on a particular control strategy, but instead uses the dynamical system equations directly. A drawback, however, is its dependency on well positions, which implies that it should be (partially) repeated when those positions are changed. We tested the method on several examples and for nearly all cases obtained coarse scale models with a superior input-output behavior compared to common upscaling algorithms.