bluuebunny/crossref_metadata_2025_split huggingface dataset:
Efficient Displacement of Heavy Oil by Use of Three Hydrocarbon Phases
Authors: Okuno R.. , Xu Z.. 
Published: June 2014

Summary
Mixtures of oil with solvent gas can exhibit three-hydrocarbon-phase behavior at reservoir conditions, where the solvent-rich liquid (L2) phase coexists with the gaseous (V) and oleic (L1) phases. Three-hydrocarbon-phase behavior has been studied in the literature for carbon dioxide (CO2) floods and enriched-gas floods at relatively low temperatures. Prior research on heavy-oil displacement with enriched gas presented that displacement efficiency at a given throughput can be nonmonotonic with respect to gas enrichment. Slimtube experiments for such displacements showed that oil recovery increased first, then decreased, and increased again with increasing gas enrichment. An optimum displacement with a high efficiency of more than 90% was observed when three-hydrocarbon-phase flow was present. However, detailed mechanisms for such an optimum displacement with three phases have not been explained in the literature.
In this research, we investigate mass transfer on multiphase transitions between two and three phases for three-hydrocarbon-phase displacements. Simple conditions are derived for the multiphase transitions that yield high local displacement efficiency by three hydrocarbon phases. The derivation is based on the generalized mass conservation for a multiphase transition in 1D gas injection. The conditions derived are applied to explain nonmonotonic oil recovery in quaternary displacements and the West Sak oil displacements.
Oil recovery at a given throughput can be nonmonotonic with respect to pressure or gas enrichment. Such a nonmonotonic trend can occur when local oil displacement by three hydrocarbon phases becomes more efficient, but slower, with decreasing pressure or decreasing gas enrichment. An optimum pressure or enrichment can occur as a consequence of the balance between the local displacement efficiency and the propagation rate of three hydrocarbon phases. The West Sak oil displacement with enriched gas studied in this research yields a high displacement efficiency of more than 90% at 1.5 hydrocarbon pore volumes (PV) injected at 53% methane (C1) dilution.
A New and Practical Workflow for Large Multipad SAGD Simulation—An Oil-Sands Case Study
Authors: Card Colin C.H. , Kumar Anjani , Close Jason C. , Kjosavik Arnfinn , Agustsson Hafsteinn , Picone Matteo M. 
Published: June 2014

Summary
Every simulation engineer wishes to simulate large full-field models, but historically reservoir simulation of the steam-assisted-gravity- drainage (SAGD) process has been constrained to single-well models up to a single pad. Models of these sizes provide valuable information and have helped to assess the development potential of reservoirs. These models may be used for reservoir management and to support the decision-making process for the design of the initial completion, operating strategy, and multipad wind-down evaluations, and also qualitatively assess the uncertainty in the SAGD forecast under different geological settings. However, in many cases we are left with the question of how multiwell and multipad communications ultimately affect performance at the well-pair scale. Because of technological constraints with computer hardware and simulation technology, running extremely large multipad models has been until recently largely impractical, especially when trying to run multiple scenarios to better understand the impact of geological and operational uncertainty. In this paper, we present a new and practical workflow that makes running extremely large multipad, multimillion-grid-cell SAGD models a reality. The three major steps of the workflow are (1) generating simulation-friendly geomodels, (2) use of experimental design and 3D submodels on the basis of SAGD performance index (SPI) for numerical tuning, and (3) use of 2D cross sections and SPI to develop dynamic grid-refinement-parameter values for the full 3D model. All of these steps are intended to improve the numerical stability and run time of multipad SAGD simulation models. A 24-SAGD-well-pair model with 2.52 million gridblocks was simulated for 10 years of forecast. The reservoir is geologically complex and highly heterogeneous. We discuss some of the important aspects that need to be accounted for when simulating large-scale SAGD models. Using this new workflow, the simulation run time was reduced from 42 days to 7 days on eight central processing units (CPUs)—a six-time speedup. The resulting run time is short enough to facilitate multirealization simultaneous runs using eight CPUs, hence maximizing the throughput and minimizing the simulation cycle time. This new workflow can be easily replicated and, more importantly, automated to reduce engineering time requirements. While this paper focuses on the SAGD process, this methodology is completely generic in that it can be applied to any large data set for any process. Details will differ depending on the process, but the workflow will be the same.
Understanding the Thermo-Hydromechanical Pressurization in Two-Phase (Steam/Water) Flow and Its Application in Low-Permeability Caprock Formations in Steam-Assisted-Gravity-Drainage Projects
Authors: Ghannadi Sahar , Irani Mazda , Chalaturnyk Rick 
Published: June 2014

SummarySteam-assisted gravity drainage (SAGD) is one successful thermal-recovery technique applied in Alberta oil-sand reservoirs. When considering in-situ production from bitumen reservoirs, one must reduce viscosity for the bitumen to flow toward the production well. Steam injection is currently the most promising thermal-recovery method. Although steamflooding has proved to be a commercially viable way to extract bitumen from bitumen reservoirs, caprock integrity and the risk of losing steam containment can be challenging operational problems. Because permeability is low in Albertan thermal-project caprock formations, heating greatly increases the pressure on any water trapped in pores as a result of water thermal expansion. This water also sees a great increase in volume as it flashes to steam, causing a large effective-stress reduction. After this condition is established, pore-pressure increases can lead to caprock shear failure or tensile fracturing, and to subsequent caprock-integrity failure or potential casing failure. It is typically believed that low-permeability caprocks impede the transmission of pore pressure from reservoirs, making them more resistant to shear failure (Collins 2005, 2007). In considering the “thermo-hydromechanical pressurization” physics, low-permeability caprocks are not always more resistant. As the steam chamber rises into the caprock, the heated pore fluids may flash to steam. Consequently, there is a vapor region between the steam-chamber interface penetrated into the caprock and the water region within the caprock which is still at a subcritical state.This study develops equations for fluid-mass and thermal-energy conservation, evaluating the thermo-hydromechanical pressurization in low-permeability caprocks and the flow of steam and water after steam starts to be injected as part of the SAGD process. Calculations are made for both short-term and long-term responses, and evaluated thermal pressurization is compared for caprocks with different stiffness states and with different permeabilities. One can conclude that the stiffer and less permeable the caprock, the greater the thermo-hydromechanical pressurization; and that the application of SAGD can lead to high pore pressure and potentially to caprock shear, and to subsequent steam release to the surface or potential casing failure.
Application of Analytical Proxy Models in Reservoir Estimation for SAGD Process: UTF-Project Case Study
Authors: Azad Ali , Chalaturnyk Richard 
Published: June 2014

Summary
Steam-assisted gravity drainage (SAGD) has been used successfully for the last 25 years in Canada. SAGD is a thermal recovery process that was invented to extract highly viscous bitumen from deep Canadian oil-sands reservoirs. To date, the original idea of SAGD has not changed greatly since the first pilot test in 1987. However, field operation and reservoir management have been influenced by recent developments in technology. Advanced drilling techniques, automated production control, and real-time data monitoring are gradually transforming the SAGD process into smart fields. As such, improving current history-matching techniques would support fast decision-making requirements significantly in closed-loop reservoir management. This paper recommends analytical solutions for simulations with medium-to-high levels of uncertainty. This shows how an analytical simulator can be improved effectively to mimic the essential features of a SAGD field for fast history matching. Combined with the analytical model recently proposed by the authors, this paper investigates the methodology to apply uncomplicated analytical/mathematical solutions to practical cases. The two underground test-facility (UTF) pilot-test case studies covered in this paper provide a better understanding of the proposed methodology. History matching results show that the current analytical models are suitable to act as proxy models for optimization purposes.
Barnett Shale Production Outlook
Authors: Browning John , Ikonnikova Svetlana , Gülen Gürcan , Tinker Scott W. 
Published: June 2014

SummaryWe developed a production-outlook model on the basis of an interdisciplinary analysis of production data from more than 15,000 wells and geologic data on the Barnett play. The model is the most granular to date because it incorporates 10 tiers of varying productivity and well economics of average wells by tier; it covers close to 8,000 square-mile blocks across partly drained and undrilled acreage, divided between low-Btu and high-Btu segments, and uses drillwell potential by tier for the total area; and it is unique in its use of production profiles on the basis of transient linear drainage. Drilling pace is adjusted to changes in natural-gas price relative to well economics, historical attrition rates, and logistical constraints. We analyze scenarios and conduct a simulation analysis on the basis of reasonable ranges for natural-gas price, remaining acreage developable in partly drained and undrilled blocks, improvement in technology and well cost performance, and economic limit for shutting in a well. The Barnett is the most exploited shale play in the world; cumulative production to 2012 is 13 Tcf. Our analysis indicates remaining recovery of approximately 2.5 times of cumulative production in the base case, but this is subject to many uncertainties. Base case results are consistent with actual production in 2011 and 2012.
Advance Study of Top of Line Corrosion Risk: Methodology and Evaluation of Mitigation for New Pipeline
Authors: Santhyani Desy 
Published: June 2014

Abstract
Top of line corrosion (TLC) is experienced on the upper section of gas or multiphase pipelines operated in a stratified flow regime. TLC occurs when water vapor, contained in the gas phase, condenseson the internal upper pipe wall. The condensation may be caused by the cold wall effect generated by external cooling sources (river water, sea water or cold air) when the pipe is not properly heat insulated or buried. Both dissolved CO2 and possible presence of organic acids reduce the pH of condensedwater and enhance corrosiveness. Instantaneous high corrosion rates, up to 10 mm/y, can occur in the first production period, although worst corrosion rates averaged over a longer period of 2-3 years are rather in the range of 1 to 3 mm/y. In addition, as long as the flow regime is stratified, usual corrosion inhibitors cannot reach the upper surface of the pipeline.
This study covers TLC assessment on new 8 km pipeline that will transport multiphase hydrocarbon from a new platform to existing facilities. Expected production life of the field is quite short, less than 10 years, maximum wellhead flowing temperature is 105℃ and CO2 content is about 8%. Based on TLC assessment performed during conceptual study, TLC has been considered as a significant issue in case of water condensation rate (WCR) &gt; 0.05 gr/m2s. Being WCR far above such limit, the use of cladding pipe was proposed as the main mitigation measure to limit TLC consequences. However during the next stage of Project, TLC risk was re-assessed in more detail by using more accurate data in order to find the best solution in term of CAPEX and OPEX.
Following studies were performed: Water condensation rate studyWCR study is performed in order to identify the pipeline length where TLC will be occured and how long TLC risks will last. Such calculation is done by using OLGA software based on the data of wellhead flowing temperature (WHFT).Top of line corrosion rate studyTLC rate is calculated to assess the feasibility of the mitigation that consists in having a sufficient corrosion allowance to cover TLC risk and to evaluate the required corrosion allowanceSensitivity study of using thermal insulation and buried pipe
Performed to assess whether the used of thermal insulation and buried pipe can be an option to mitigate TLC
Result of these studies demonstrated that the utilization of carbon steel with extra corrosion allowance, combined with cold spot prevention as the best technical-economic option for TLC mitigation. It was also possible to conclude that thermal insulation or bury the pipe may not always be the most appropriate option due to the quality assurance along the years, the constructability constraint and the cost.
Geomodel Geometry Distorted by Seismic Velocity Uncertainties
Authors: Piquet G. , Pivot F. , Forge A. 
Published: June 2014

Abstract
Structure of the geomodel is always controlled by key depth horizons and faults coming from seismic interpretation. However, these geophysical surfaces carry uncertainties attached to seismic picking and seismic velocities. Some error done on estimation of such velocities can have a great impact on final volumes & on field development as it can change drastically the shape of the reservoirs.
We propose here a multi-realizations approach to manage properly these uncertainties during the geomodeling process, in order to estimate their impact and build alternative distorted geomodels for pessimistic and optimistic scenarios.
This method relies on the alternative velocity models built by the interpreters to depth convert the horizons at the origin of the geomodel grid. These velocity models reflect geophysical uncertainty through alternative hypothesis to the basecase velocity model. The stochastic approach presented mixes those models generating hundreds of intermediate scenarios for top & base reservoir horizons. For instance structure can be tilted, smaller or larger compared to the basecase.
This approach enables the user to decide how far from the basecase top & base reservoir realizations should vary (using confidence weights). So the user can maintain the possible realizations around the most likely one (??).
We propose here to expose & apply each step of this technique to an offshore West-Africa field. The objective of the study is triple: to get a dispersion of the possible GRV values, to get distorted versions of the geomodel according to optimistic or pessimistic GRV realizations so that extreme cases can be analyzed. And eventually to assess possible variations of the flanks of the structure.
This last point is crucial to take into account uncertainties in the producer/injector well development pattern.
Effects of Segmentation and Skeletonisation Algorithms on Pore Networks and Predicted Multiphase Transport Properties on Reservoir Rock Samples
Authors: Idowu N. A. , Nardi C.. , Long H.. , Varslot T.. , Øren P. E. 
Published: June 2014

Abstract
Networks of large pores connected by narrower throats (pore networks) are essential inputs into network models which are routinely used to predict transport properties from digital rock images. Extracting pore networks from micro-computed tomography (micro-CT) images of rocks involves a number of steps: filtering, segmentation, skeletonisation etc. Because of the amount of clay and their distribution, segmentation of micro-CT images is not trivial and different algorithms exist for doing this. Similarly, several methods are available for skeletonising the segmented images and for extracting the pore networks. The non-uniqueness of these processes raises questions about the predictive power of network models. In the present work, we evaluate the effects of these processes on the computed petrophysical and multiphase flow properties of reservoir rock samples.
Using micro-CT images of reservoir sandstones, we first apply three different segmentation algorithms and assess the impacts of the different algorithms on estimated porosity, amount of clay and their distribution. Single-phase properties are computed directly on the segmented images and compared with experimental data. Next, we extract skeletons from the segmented images using three different algorithms. On the generated pore networks, we simulate two-phase oil/water and three-phase gas/oil/water displacements using a quasi-static pore network model.
Analysis of the segmentation results show differences in the amount of clay, total porosity and computed single-phase properties. Simulated results show that there are differences in the network-predicted single-phase properties as well. However, predicted multiphase transport properties from the different networks are in good agreement. This indicates that the topology of the pore space is well preserved in the extracted skeleton. Comparison of the computed capillary pressure and relative permeability curves for all networks with available experimental data show good agreements.
By using a segmentation which captures porosity and microporosity, we show that the extracted networks can be used to reliably predict multiphase transport properties irrespective of the algorithms used.
Self-Adapting Bottom-Hole-Assembly Vibration Suppression
Authors: Hutchinson Mark , Burgess Dan , Thompson Fred , Kopfstein Allen 
Published: June 2014

Abstract
The state-of-the-art approach to downhole shock and vibration mitigation is to insert into the bottom-hole-assembly (BHA) a shock-sub or torque-limiter with response characteristics pre-configured prior to tripping into the borehole and then continuously monitor downhole vibrations with the driller making adjustments to surface control parameters whenever the downhole shock levels are excessive. Some top-drive control systems are also capable of mitigating the torsional stick-slip dysfunction. A novel approach is to use downhole shock and vibration measurements to actively adjust the damping characteristics of a downhole shock-absorber, thereby changing the axial (and optionally torsional) stiffness of the BHA itself, in response to transient downhole dysfunctions and without the inherent delay of transmitting data from downhole to the driller at the surface.
At the heart of this new adaptive shock-absorber is a magneto-rheological damping fluid whose viscosity is modified whenever excessive downhole vibrations are detected by adjusting the electro-magnetic field through which the damping fluid passes. This is similar technology to that used for protecting buildings during earthquakes and in high performance vehicles that have intelligent shock-absorbers that let the driver select a preferred stiffness for the vehicle's suspension.
This paper describes this innovative downhole self-adapting vibration damper and its autonomous control system that detects drilling dysfunctions and then iteratively adjusts the device's damping characteristics until the destructive downhole forces and motions are mitigated – potentially before the driller at the surface is even aware that there was a problem. Modeling of the magneto-rheological fluid response is presented together with some initial downhole test results demonstrating the tool's ability to control the stiffness and vibration characteristics of a bottom-hole-assembly. Comparisons of downhole shock levels and the amplitude of various types of vibrations at different frequencies illustrate how the self-adapting damper can suppress different modes of BHA dysfunction and thus also demonstrating the device's ability to extend bit life and drilling tool life and to improve overall drilling performance.
Automatically controlling drilling dysfunctions from within the BHA at their source is timelier and potentially more effective than the current approach of telemetering downhole vibration information to the driller at the surface after the bit and drill string components have already been damaged over some incremental time period. The more instantaneous response of a self-adapting tool has the ability to prevent drilling tool failures, reduce bit wear, sustain higher penetration rates with a sharper bit and extend the interval drilled during a single bit run. For certain drilling applications this can significantly reduce the number of bit runs per hole section as well as the related drilling time and cost.
Ceramic Screens - An Innovative Downhole Sand Control Solution for Old & Challenging Cased Hole Completions
Authors: Nadeem Asaf , Strazzi Alfonso , Justiniano Pablo , Lopez Mario , Wildhack Stefanie , Joly Samuel 
Published: June 2014

Abstract
Erosion in gas wells caused by sand producing formations can result in severe operational issues leading to the degradation of surface and downhole equipment and the shutdown of production facilities at surface.
Old cased hole wells in highly unconsolidated, poorly sorted sandstone formations require robust sand control. In such instances, conventional gravel packing methods are not always possible and the installation and maintenance of downhole sand control throughout the well life can be challenging. In gas wells where sand velocities are high, the supporting metallic material being used in, for example standalone sand control screens is subject to plugging and subsequent rapid wear because of its low resistance to erosion. Hence the longevity of metallic sand control equipment is poor and frequent expensive re-completions and workovers are required.
An innovative solution using ceramic screens was used in an existing gas well in Bolivia, South America. The well geometry included double casing with sub-optimal cement across the target zone and, due to the complexity of voids behind the casing, it was not possible to perform the initial option of a cased-hole gravel pack. In addition to sand control the completion required mechanical zonal isolation to prevent water ingress at a later stage. In summary the project involved removing the existing completion, isolating deeper lying depleted producing zones, clearing the casing of debris, re-perforating the casing, installing a new completion with ceramic screens and zonal isolation valves.
BG Group in conjunction with German ceramics manufacturer ESK developed over a period of 18 months a series of ceramic sand control screens and sliding sleeve protections that provided a downhole sand control completion solution complete with mechanical water isolation.
The successful project exceeded all expectations and to date the well has produced sand free. The operational time and re-completion costs were less than of a cased-hole gravel pack, the operation much simpler and safer.
BG are now working on a project to use this innovative technology as a thru-tubing sand control solution for existing high rate gas wells offshore worldwide where open hole or cased hole gravel packs have failed.