bluuebunny/crossref_metadata_2025_split huggingface dataset:
Acid-Etched Channels in Heterogeneous Carbonates—a Newly Discovered Mechanism for Creating Acid-Fracture Conductivity
Authors: Mou Jianye , Zhu D.. , Hill A.D.. D. 
Published: June 2010

Summary
In the acid-fracturing process, the fracture conductivity created by acid etching of the fracture walls is because of the surface roughness created by the acid's nonuniform dissolution of the fracture surfaces. The acid-fracture conductivity is dependent on surface etching patterns, which are determined by permeability and mineralogy distributions. That is, the spatial distribution of fracture roughness affects the fracture conductivity, which cannot be considered in laboratory measurements of acid-fracture conductivity, which use core samples that are too small to observe such macroscale heterogeneities, or in typical acid-fracture simulators, in which the gridblock size is much larger than the scale of local heterogeneities.
An accurate prediction of acid-fracture conductivity necessitates the detailed description of the acid etching profiles on the fracture surfaces, which depend on acid transport in the fracture, leakoff because of local permeability, and acid/rock reactions. In this paper, we developed a 3D intermediate-scale acid-fracture model with gridblock sizes small enough (gridblock sizes comparable to the core-sample size in experiments) and total dimensions large enough (the total dimensions comparable to a gridblock size in an acid-fracture simulator) to capture local and macroscale heterogeneity characteristics. The model predicts the pressure field, the flow field, acid concentration profiles, and fracture-surface profiles as functions of acid injection volume. In the model, we use a front-fixing method (Crank 1984) to handle the irregular, moving boundaries in numerical simulation. Spatially correlated permeability and mineralogy distributions were generated by using a semivariogram model.
The model was validated by comparing simulation results with experimental results from an acid-fracture conductivity cell. With the model, by extensive numerical simulation, we analyzed the relationship among fracture-surface-etching patterns, conductivities, and the distributions of permeability and mineralogy. We also illustrated the formation characteristics necessary for acid to create channel-caused high acid-fracture conductivity. We found that a fracture segment with channels extending from the inlet to the outlet of the segment has high conductivity because fluid flow in deep channels causes a very small pressure drop. Such long and highly conductive channels can be created by acids if the formation has heterogeneities in either permeability or mineralogy or both, with high correlation length in the main flow direction, which is the case in laminated formations.
Model-Based Integration and Optimization—Gas-Cycling Benchmark
Authors: Juell Aleksander , Whitson Curtis H. , Hoda Mohammad Faizul 
Published: June 2010

Summary
A benchmark for computational integration of petroleum operations has been constructed. The benchmark consists of two gas/ condensate reservoirs producing to a common process facility. A fraction of the processed gas is distributed between the two reservoirs for gas injection. Total project economics is calculated from the produced streams and process-related costs. This benchmark may be used to compare different computational integration frameworks and optimization strategies. Even though this benchmark aims to integrate all parts of a petroleum operation, from upstream to downstream, certain simplifications are made. For example, pipe flow from reservoir to process facility is not included in the integrated model.
The methods of model integration and optimization discussed in this paper are applicable to complex petroleum operations where it is difficult to quantify cause and effect without comprehensive model-based integration. A framework for integration of models describing petroleum operations has been developed. An example test problem is described and studied in detail. Substantial gains in full-field development may be achieved by optimizing over the entire production system.
All models and data in the benchmark problem are made available so that different software platforms can study the effects of alternative integration methods and optimization solver strategy. The project itself can, and probably should, be extended by others to add more complexity (realism) to the reservoir, process, and economics modeling.
Surfactant-Assisted Synthesis of Metal-Phosphonate Inhibitor Nanoparticles and Transport in Porous Media
Authors: Zhang Ping , Shen Dong , Fan Chunfang , Kan Amy T. , Tomson Mason B. 
Published: June 2010

Summary
A surfactant-assisted synthesis route was developed to form nanometer-size metal-phosphonate particles. The purpose is to develop a new treatment method for scale control. Aqueous solutions of calcium chloride and zinc chloride were mixed with a basic solution of either diethylenetriamine-penta (methylene phosphonate) (DTPMP) or bis-hexamethylenetriamine penta (methylene phosphonate) (BHPMP) in the presence of tetradodecylammonium bromide (TTAB) or sodium dodecyl sulfate (SDS) surfactant to form nanometer-size particles. The physical and chemical properties of the fabricated nanoparticles have been evaluated carefully. A large number of fabrication procedures are screened, and only those that yield metal-phosphonate particles of 50–200 nm in diameter are evaluated further. Furthermore, these nanoparticles should meet the criteria of forming stable suspension for more than 1 week at 70°C in 2% KCl solution. The nanoparticles can travel through the porous media and be deposited into the formation during a shut-in period. When production resumes, the inhibitor nanoparticles are dissolved into the produced fluid to prevent scale formation. The potential application of synthesized nanoparticles in scale treatment in oil fields has been tested by laboratory squeeze simulations, in which the nanoparticles were placed a distance away from the injection port, retained by the porous media, and returned slowly during flow-back with synthetic brine. The retention and long-term-flowback performance of metal-phosphonate particles is reported.
Development of a Methodology for the Optimization of Dehydration of Extraheavy-Oil Emulsions
Authors: Dalmazzone C. , Noik C. , Glénat P. , Dang F. 
Published: June 2010

Summary
With the increasing development of heavy- and extraheavy-oil (EHO) fields, separation operations are becoming increasingly challenging compared to separation for conventional oil fields. For in-situ bitumen, EHOs produced by thermal-process dehydration require solvent addition, injection of a large amount of demulsifier additives, relatively high operating temperature, and long retention times inside the separators. So, in order to respect specifications on crude oil and water quality at lower cost, an optimization of the different parameters involved in the whole process of separation becomes necessary.
In the case of EHOs, the presence of polar heavy components, such as asphaltenes, structured as a rigid film at the water/oil interface, limits the coalescence phenomena and, consequently, limits the efficiency of separation by gravity or by using conventional electrocoalescence.
The paper presents a methodology that permits the optimization of water and oil separation in the case of an in-situ EHO (produced by thermal process). The crude oil was first characterized in terms of rheological behavior and interfacial properties. The dilatational viscoelastic properties of the interface were determined from measurements performed with an oscillating oil-drop tensiometer. Properties of emulsification were also investigated by using a specific device called a dispersion rig that allows the reconstitution of crude-oil emulsions under controlled hydrodynamic conditions. Then, a laboratory procedure based on electrical stability tests (ESTs) was applied to optimize the concentration of demulsifier required for effective water separation.
Finally, the optimal electrical parameters were determined in an electrocoalescer device in the presence of the selected concentration of additive. The efficiency of coalescence was measured by following the growth of dispersed water droplets inside the emulsion using differential scanning calorimetry (DSC).
This methodology may be used advantageously as a useful base for further scaleup studies concerning field separation facilities.
How To Apply the Flow Velocity as a Design Criterion in RPM Treatments
Authors: Stavland Arne 
Published: June 2010

SummaryThe effect of water control using relative permeability modification (RPM) depends strongly on the well's flow rate because the permeability reduction decreases as the flow velocity increases. This will affect the volume and the properties of the injected RPM fluid. This paper discusses how the velocity-dependent permeability reduction can be accounted for in the job design. The approach is to introduce a velocity-dependent permeability reduction and to solve the Darcy law for non-Newtonian flow.Coreflood experiments report permeability reduction as residual resistance factors (RRFw and RRFo). In scaling up to field situations, the reduction in productivity is a better measure. Designing an RPM treatment to a fixed reduction in water productivity demonstrated that low-volume, high permeability reduction is better than larger volumes with lower permeability reduction. In highly productive wells, there may be situations where certain RPM systems fail to reduce the water productivity adequately. By including pressure constraints on the injection of the RPM fluid, the planned pumping schedule is derived.The criteria for increased oil production are reported as a balance between (1) increased drawdown based on the water-cut reduction and improved lift and (2) reduction in oil productivity. The critical oil productivity depends on the water productivity, initial water cut, density difference between the water and the hydrocarbon phases, and true vertical depth (TVD). It is clearly demonstrated that the potential for increased oil production increases by increasing the ratio between the oil- and the water-productivity reduction (M). In addition, M increases as RRFw increases and the treatment volume decreases.The time to restore the productivity from the oil zone, the cleanup time, can be understood through the fractional-flow theory. In theory, the cleanup time can be derived from relative permeability curves or the saturation profiles during the oil back production. Also, the cleanup time was reduced by the use of low-volume, high water-permeability reduction.
Milling of Permanent Bridge Plug Performed Successfully on Wireline
Authors: Stragiotti Stephen , Andersen Øyvind , Karlsen Ole Eddie 
Published: June 2010

Summary
A technological breakthrough within the application of wireline technology has been achieved. In August 2008 on an offshore platform on the Norwegian continental shelf, a wireline tractor and a new wireline milling system were used to mill and remove a permanent bridge plug at 4,147 ft measured depth (MD).
The operator decided to mill out the plug on electric wireline and worked closely with the service company to develop this novel solution. Having developed and tested several bits and milling tools, results showed that by combining the wireline miller with hydraulically provided weight on bit (WOB), it would be possible to mill out the retaining rings of the plug, which would cause the plug to collapse. The milling-control unit allows the WOB to be adjusted for each application and also controls the reactive torque—the force generated when the milling bit engages the plug.
The service company was able to develop the solution within the client's parameters and in accordance with the timeline set out for this project. The offshore operation was completed in 3 days, to the operator's satisfaction.
In another platform well, a permanent bridge plug had been set in 2003 in the sealbore between two screen sections [3-ft seal- bore, 67° well angle, 4.75-in. inner diameter (ID)]. The plug was set in order to isolate the somewhat higher water cut in the lower reservoir zone to prolong oil production from the well. In 2006, the well drowned after a 2-week-maintenance period. Two years later, a coiled-tubing (CT) gas lift operation was carried out with good results. It was then decided to remove the permanent bridge plug to reopen for production before another CT gas lift operation was carried out. A method for milling the permanent bridge plug was developed on the basis of lessons learned from the other plugmilling operation and by extensive testing at the service company's facilities. The operation was completed successfully in 13 days.
This new application for milling completion hardware and other wellbore obstructions offers a cost-efficient alternative to existing methods. The success of the milling operation is a significant achievement and has pushed the limits for what is possible on electric wireline.
This paper will examine two cases of milling bridge plugs on electric wireline and the technical challenges that had to be overcome in offshore operations.The first case used the well stroker as WOB, and the second cased used the well tractor as WOB.
Pore-Network Modeling Dedicated to the Determination of the Petrophysical-Property Changes in the Presence of Reactive Fluid
Authors: Algive Lionnel , Bekri Samir , Vizika Olga 
Published: June 2010

Summary
A pore-network model (PNM) is an efficient tool to account for phenomena occurring at the pore scale. Its explicit 3D network of pores interconnected by throats represents an easy way to consider the topology and geometry effects on upscaled and homogenized petrophysical parameters. In particular, this modeling approach is appropriate to study the rock/fluid interactions. It can provide quantitative information both on the effective transport property modifications caused by the reactions and on the structure evolution resulting from dissolution/precipitation mechanisms.
The model developed is based on the resolution of the macroscopic reactive transport equation between the nodes of the network. By upscaling the results, we then determined the effective transport properties at the core scale. A sensitivity study on reactive and flow regimes has been conducted in the case of single-phase flow in the limit of long times.
It has been observed that the mean reactive solute velocity and dispersion can vary up to one order of magnitude compared with the tracer values because of the concentration-profile heterogeneity at the pore scale resulting from the surface reactions. As for the reactive apparent coefficient, when the kinetics is limited by the mass transfer, it can decrease by several orders of magnitude with regard to that calculated by the usual perfect-mixing assumption. That is why scale factors should be added to the classical macroscopic transport equation implemented in reservoir simulators to predict accurately the reactive flow effects. For each study case, we also obtained the permeability variation vs. the porosity evolution in a physical way that accounts for reactive transport conditions. It appears that the wall-deformation pattern and its effect on petrophysical properties must be explained by considering both microscopic and macroscopic scales of the reactive transport, each one governed by a dimensionless number comparing reaction and transport characteristic times.
This work helps improve the understanding of surface-reactions effects on reactive flow on the one hand and on permeability and porosity modifications on the other. Using the PNM approach, scale-factor parameters and permeability-vs.-porosity relations can be determined for various rock types and reactive flow regimes. Once integrated as inputs in a reservoir simulator, these relations form a powerful and convenient means of enhancing the modeling accuracy of the change in petrophysical properties during injection of a reactive fluid, such as brine rich in carbon dioxide (CO2).
A Placement Model for Matrix Acidizing of Vertically Extensive, Heterogeneous Gas Reservoirs
Authors: Nozaki M.. , Hill A.D.. D. 
Published: June 2010

Summary
A critical issue in matrix acidizing of vertically extensive carbonate reservoirs is the acid distribution along the wellbore. This estimation is very important, especially for the case where the reservoir properties (permeability and damage distribution) vary along the wellbore. Several acid-placement models for oil reservoirs have been developed and applied in the field successfully. However, when evaluating acidizing in a gas well, the models are not adequate because of the viscosity contrast between the reservoir fluid (gas) and the injected fluid (acid) and because of relative permeability effects. We have developed an acid-placement model for acid injection into vertically extensive gas wells in heterogeneous carbonate reservoirs that includes gravity segregation in the wellbore, viscosity contrast, relative permeability effects, and a wormhole model. The effects of all these factors on the local injectivity during acid injection are incorporated into a dynamic-skin-factor model.
To test this new model, we analyzed coreflooding data in the literature. The analysis showed that differential pressure across a gas-saturated core did not linearly drop during acidizing, but instead increased during a large part of the acid-injection period. From this analysis, we determined that the pressure drop in a spent-acid zone ahead of the wormholes dominates the overall pressure-drop behavior.
Applying this model to typical field conditions, we find that a natural viscous diversion takes place in heterogeneous gas reservoirs because of the viscosity contrast between the gas and the injected acid. In particular, we have modeled thick carbonate gas reservoirs having a few thin, very-high-permeability thief zones. Before worm-holes break through the damage zone in the high-permeability parts of the reservoir, this viscous-diversion effect distributes acid more uniformly than expected. However, after wormholes break through the damaged zone, thief zones will take a large portion of the injected acid. Another important prediction with this model is that the injection pressure often increases during acid injection into gas wells. Without an understanding of the role of mobility contrast in the injection-pressure response, operators may conclude incorrectly that the injected acid is not stimulating the formation.
Three-Phase Flash in Compositional Simulation Using a Reduced Method
Authors: Okuno R.. , Johns R.T.. T. , Sepehrnoori K.. 
Published: June 2010

Summary
CO2 flooding at low temperatures often results in three or more hydrocarbon phases. Multiphase compositional simulation must simulate such gasfloods accurately. Drawbacks of modeling three hydrocarbon phases are the increased computational time and convergence problems associated with flash calculations. Use of a reduced method is a potential solution to these problems.
We first demonstrate the importance of using three-phase flash calculations in compositional simulation by investigating difficulties with two-phase equilibrium approximations proposed in the literature. We then extend an algorithm for reduced two-phase flash calculations to three-phase calculations and show the efficiency and robustness of our algorithm. The reduced three-phase flash algorithm is implemented in a multiphase compositional simulator to demonstrate the speed-up and increased robustness of simulations in various case studies.
Results show that use of a two-phase equilibrium approximation in reservoir simulation can result in a complete failure or erroneous simulation results. Simulation case studies show that our reduced method can decrease computational time significantly without loss of accuracy. Computational time is reduced using our reduced method because of the smaller number of equations to be solved and increased timestep sizes. We show that a failure of a flash calculation leads directly to reduced timestep sizes using the UTCOMP simulator.
FPSO Environmental-Risk Management
Authors: Metzger B.H.. H. , Salmond D.. , Tilstone A.. 
Published: June 2010

Summary
Oil companies planning to locate floating production storage, and offloading vessels (FPSOs) [or floating storage and offloading vessels (FSOs)] in shallow water need to consider the performance of such operations relative to environmentally sensitive coastal habitats. This paper is based on a global study Battelle performed on FPSO safety performance and, in particular, with respect to risk management of nearshore operations. The study provides environmental best-practices benchmarks. It examines the international safety performance of FPSOs operating in various geographies and environmental conditions. To this end, it reviews risk analyses published over the past 10 years on the subject of FPSO failure hazards, such as collision, offloading failure, equipment failure, and tanker spills. The study then examines eight cases of FPSOs operating in nearshore locations around the globe identifying proven risk-mitigation and -management practices and lessons learned that might benefit future FPSO projects.
The study confirms that there is a strong safety record available on more than 1,000 years of FPSO operation around the globe. Extensive research conducted by agencies and researchers in the UK, Norway, the US, and elsewhere on FPSO design, operation, and performance offers a rich body of information on FPSO safety guidance. In addition, detailed review of the eight case studies confirms what the literature suggests: The FPSOs that have been operated to date have had a strong safety record. Very few incidents of consequence have been reported. No major incident or loss of cargo has occurred. None of the minor touches and collisions has resulted in the release of cargo. Virtually all recorded and reported releases have been small, and most of them were less than 1 bbl. Robust management systems combined with strong design and operating practices are capable of avoiding theoretical failure risks, or reducing them to very low and acceptable levels.
The results of this study suggest that there is an arsenal of measures operators can consider to ensure high safety performance of any planned FPSO. Failure and spill risks summarized in this study may be extrapolated for planned systems and proven risk reduction and mitigation measures adopted.