bluuebunny/crossref_metadata_2025 huggingface dataset:
Deep Conformance Control by a Novel Thermally Activated Particle System to Improve Sweep Efficiency in Mature Waterfloods of the San Jorge Basin
Authors: Mustoni J. L. , Norman C. A. , Denyer P.
Published: July 2010

This paper shows the results of the six pilot applications of a novel thermally activated particle system in mature water floods operated by Pan American Energy, at the San Jorge Basin (SJB), Argentina. These were injected between 2006 and 2008 and after up to three years of response, the evaluation is presented with notes on the well and reservoir character, treatment application and observed responses including incremental oil recovery. Field logistics, candidate selection, treatment design, operational aspects and pre and post application monitoring will also be described in detail.

SJB's water floods are characterized by low recovery efficiency due to an adverse mobility ratio as well as spatial reservoir rock anisotropy. This heterogeneity is typical of fluvial systems with high rock property contrasts inside the same channel body. A permeability contrast of 5 to 1 between the center and the edge of the channel is very typical. Therefore, injected water preferentially flows along the center of the channel, becomes a "thief zone", and breaks through to the producers prematurely, leaving behind unswept oil not contacted by the injection water.

In the last decade, many conformance trials failed to improve recovery efficiency. The main reasons for this failure were the utilization of an inappropriate chemical and / or ineffective placement of the application. However, since that time, this new particle technology has shown successful results by blocking thief zones deep in the reservoir. This blocking creates a new pressure gradient that promotes the diversion of injected water toward zones with high oil saturation. A confirmed success rate of around 80 percent seen in these pilots, with no apparent technical failures, has paved the way for a widespread deployment of the technology. In conclusion, the paper discusses treatment selection criteria for field scale application and feasibility for optimization.
The Use of Non-Intrusive Ultrasonic Intelligent Sensors for Corrosion and Erosion Monitoring
Authors: Instanes Geir , Toppe Mads , Kristiansen Sindre Halse , Nagy Peter B.
Published: July 2010

Corrosion and erosion detection and monitoring are essential prognostic means of preserving material integrity and reducing the life-cycle cost of industrial infrastructure, ships, aircraft, ground vehicles, pipelines, oil installations, etc. Spatially dynamic pipeline monitoring systems have to necessarily face extremely hostile conditions of operation including surface roughness, fluid loading issues, temperature variations, and a host of other factors that make development of a robust wall thickness assessment tool a challenging task. This paper describes the working of Corrosion-Erosion Monitor (CEM) - an online, real-time path based thickness assessment tool that deploys a set of transducers over a given pipe area, and utilizes a dispersion based principle to assess wall thickness loss. This instrument was developed keeping the needs of the oil, gas and petrochemical industry in mind, both upstream and downstream, but because it essentially monitors reductions in wall loss, it can find applications in many other industries. Experimental work and field trials provide very promising results pertaining to the functionality of the CEM system, and some of these results have been discussed in this paper. The CEM can be used as a permanent installation or as a relocatable instrument, a result of the development of so called "dry contact" transducers. It is installed on the outer pipe wall to produce real- time pipe wall thickness information, not as a spot measurement, but as a unique average path wall thickness.
Modeling and Assessment of Wettability Alteration Processes in Fractured Carbonates using Dual Porosity and Discrete Fracture Approaches
Authors: Farhadinia M. A. , Delshad M.
Published: July 2010

Naturally fractured reservoirs (NFR) with significant oil reserves consist of highly conductive fractures and low permeable matrix media. The matrix rock is usually oil or mixed wet and cause a large amount of the oil remain stagnant after primary and secondary oil recovery processes. Recent laboratory studies have revealed that the injection of chemicals such as surfactant and alkali can change the wettability of the matrix to more water wet and help to mobilize and produce the remaining oil from matrix. Despite numerous publications on successful laboratory experiments, research on simulation and accurate modeling of the process is still very scarce. This paper focuses on the mechanistic modeling of the wettability alteration by chemical injection in NFRs using dual porosity MINC (multiple interacting continua) method.

Oil recovery from NFRs is a large target in the oil industry but requires new technologies including more advanced simulation tools to produce it cost effectively. Applications of the new technologies require numerical simulators capable of modeling the interaction between fractures and matrix in transport of the injected and produced materials. Inclusion of the wettability alteration due to surfactant injection in dual porosity model allows for the extension of the laboratory results to the field scale. This work opens up an area to mechanistic simulation of the oil recovery from NFRs in field scale using dual porosity multiple interacting continua, MINC, method.

We present the wettability alteration model in NFR carbonates using surfactants with a dual porosity model including matrix subgrid capabilities. The model is tested against both published fractured block experiment and a discrete fracture model. The impact on oil recovery of key process parameters such as surfactant concentration and phase behavior, injection/production rate, fracture-matrix permeability ratios, fracture intensity and initial water saturation are investigated.

To the best of our knowledge this is the first time that wettability alteration is coupled with a dual porosity model to estimate the oil recovery from NFRs. Both advantages and limitations of the dual porosity and discrete fracture in the context of wettability modification with chemicals are discussed to provide guidelines and insights for future research.
History Matching of a Realistic Stochastic Fault Model Using Fractal Geometry and the Gradual Deformation Method
Authors: Verscheure Marius , Fourno André , Chilès Jean-Paul
Published: July 2010

Subseismic faults, which strongly influence the hydrodynamic behavior of fractured reservoirs, are inadequately handled in most studies. First, simulation methods were developed to generate fractured models respecting geological observations and static data. Then, history matching methods were introduced to make these models consistent with dynamic data too. However, these fracture models were too simple to accurately describe geology. In this work, we go one step further and develop a methodology to calibrate a realistic stochastic fault model to both static and dynamic data.

We first propose a fractal methodology to generate the faults. The model parameters (length distribution, clustering properties, and orientation) are derived from the analysis of the seismic faults. A stochastic algorithm is used to randomly draw 3D object based sub-seismic fault realizations. Then, these realizations are constrained to the faults identified from seismic. This results in geologically consistent static fault models.

The fracture network is then discretized on a dual porosity simulation grid. Equivalent flow parameters are computed using an analytical method, which makes it possible to account for large-scale fractures. Last, full field simulations are performed using a commercial multiphase flow simulator.

Then, we introduce a method to gradually change the locations of faults while preserving geological consistency. The changes in locations are driven from a reduced number of parameters. During the history-matching process, these parameters are gradually perturbed to compel the initial fault model to reproduce as well as possible the hydrodynamic data collected on the field. As the resulting fault displacement is continuous, common optimization algorithms can be used.

The potential of the methodology is stressed from a 3D case study. A sub-seismic fault network is generated and constrained to seismic faults. Equivalent parameters are computed on a complex CPG grid. Then, the model is calibrated to water-cut levels and well pressures by varying fault locations.
Modeling Formation Damage and Wettability Alteration Induced by Asphaltene Precipitation and Their Effects on Percolation Performances During Oil Production
Authors: Ju Binshan , Qin Jishun , Chen Xinglong , Fan Tailiang , Wu Yushu
Published: July 2010

Asphaltene, which exists in crude oil, is a high molecular weight, polar component. It is widely believed that asphaltene may precipitate and plug pores of reservoir rock and induce wettability alteration for the changes in oil composition, reservoir pressure and temperature. Therefore, alphaltene precipitation in the pores of oil formation definitely leads to formation damage and wettability alteration. The mechanisms caused asphaltene precipitation have been researched in labs and the key factors to effect the precipitation have been well understood, but prediction for its quantitative damages for oil formation, wettability alteration and their effects on percolation performance are still uncertain. In this work, a mathematical model considering asphaltene precipitation and wettability alteration is presented and an oil field scaled numerical simulator is developed to predict for asphaltene precipitation problems in the development of oil field. The simulation results show that the porosity and permeability in the vicinity of production wellbore decrease dramatically for asphaltene precipitation. The water-cut increases for the increase in the effective permeability of oil phase and the decrease in the effective permeability of water for the wettability alteration induced by asphaltene deposition onto the pore surfaces.
Mechanisms for High Displacement Efficiency of Low-Temperature CO2 Floods
Authors: Okuno R. , Johns R. T. , Sepehrnoori K.
Published: July 2010

CO2 floods at temperatures typically below 120°F can involve complex phase behavior, where a third CO2-rich liquid (L2) phase coexists with the oleic (L1) and gaseous (V) phases. Results of slim-tube measurements in the literature show that an oil displacement by CO2 can achieve high displacement efficiency of more than 90% when three hydrocarbon-phases coexist during the displacement. However, the mechanism for the high displacement efficiency is uncertain because the complex interaction of phase behavior with flow during the displacement is not fully understood.

In this paper, we present the first detailed study of three-phase behavior predictions and displacement efficiency for low-temperature CO2 floods. Four-component EOS models are initially used to investigate systematically the effects of pressure, temperature, and oil properties on development of three-phase regions and displacement efficiency. Multicomponent oil displacements by CO2 are then considered. We use a compositional reservoir simulator capable of robust three-phase equilibrium calculations.

Results show that high displacement efficiency of low-temperature CO2 floods is a consequence of both condensing and vaporizing behavior. The L2 phase serves as a buffer between the immiscible V and L1 phases within the three-phase region. Components in the L1 phase first transfer efficiently to the L2 phase near a lower critical endpoint (LCEP). These oil components then transfer to the V phase near an upper critical endpoint (UCEP) at the trailing edge of the three-phase region. The CEPs are defined where two of the three coexisting phases merge in the presence of the other immiscible phase. Unlike two-phase displacements, condensation and vaporization of intermediate components occur simultaneously within the three-phase region. The simultaneous condensing/vaporizing behavior involving the CEPs is also confirmed for simulations of several west Texas oil displacements. Quaternary fluid models can predict qualitatively the complex displacements because four is the minimum number of components to develop CEP behavior in composition space at a fixed temperature and pressure.
Single-Well Simulation Study of Foam EOR in Gas-Cap Oil of the Naturally-Fractured Cantarell Field
Authors: Abbaszadeh Maghsood , Rodriguez-de la Garza Fernando , Yuan Chengwu , Pope Gary A.
Published: July 2010

This paper presents results of a simulation study to investigate foam-assisted chemical EOR surfactants that target recovery of oil from the vast volumes of bypassed oil in the tight and oil-wet matrix in the gas cap of the naturally fractured Akal field of Cantarell complex. First, gravity drainage in a 1D column of stacked matrix blocks of Akal gas cap is simulated with both fine-scale single-porosity and coarse-scale dual-continuum media under the conditions of capillary continuity and discontinuity. This establishes that a combined dual-porosity and dual-permeability coarse scheme is appropriate as the representative modeling method. Next, 2D cylindrical and 3D Cartesian single-well models with fluid and rock properties of Akal field are constructed and aqueous solutions of foaming and EOR-surfactants are co-injected in the nitrogen gas stream through vertical or limited-entry side-tracked horizontal wells. Simulation approaches are developed that formulate the impact of foam on fluid flow within fractures, wettability alteration and subsequent imbibition of EOR surfactant solutions into matrix for accelerated gravity induced EOR of matrix oil. Sensitivity studies with respect to foam quality, foam strength, processes of wettability alteration and ultra-low tension EOR and well geometry configurations are conducted. Use of horizontal injector and producer help better confine the released oil within the testing interval and aid in assessing the efficiency of foam-EOR method for gas cap matrix oil.
How to Get the Best Out of Hydrophobically Associative Polymers for IOR? New experimental Insights
Authors: Guillaume Dupuis , David Rousseau , René Tabary , Bruno Grassl
Published: July 2010

The specific molecular structure of Hydrophobically Modified Water Soluble Polymers (HMWSP, also called hydrophobically associative polymers) gives them both superior thickening and surface adsorption abilities as compared to classical Water Soluble Polymers (WSP) and makes them attractive for both polymer flooding and well treatment operations (water shutoff, conformance control). However, their strong adsorption can obviously impair their injectivity and, conversely, the shear-sensitivity of their gels can be detrimental to well treatments. Determining for which IOR application HMWSP are best suited remains therefore difficult. The aim of this work was to bring new insights regarding the interaction mechanisms between HMWSP and rock matrix and their consequences concerning their propagation in reservoirs.

A consistent set of HMWSP with sulfonated polyacrylamide backbones and alkyl hydrophobic side-chains together with an equivalent WSP were synthesized and fully characterized. HMWSP and WSP solutions were then injected in model granular packs. As expected, with HMWSP, high resistance factors (or mobility reductions, Rm) were observed. Yet, no core-plugging occurred, since stabilization trends in the Rm curves and no loss of viscosity in the effluents were observed. A first significant outcome concerns the specificities of the Rm curves during HMWSP injections. Rm increases took place in two steps: the first corresponded to the propagation of the viscous front, as observed with WSP, whereas the second was markedly delayed, occurring several pore volumes after the breakthrough. This result is not compatible with the classical picture of multilayers adsorption of HMWSP, but suggests that injectivity is controlled by the sole adsorption of minority polymeric species. This hypothesis was confirmed by re-injecting the collected effluents into fresh cores: no second-step Rm increases were observed.

Brine injections in HMWSP treated cores revealed high residual resistance factors (or irreversible permeability reductions, Rk) which can be attributed to the presence of thick polymer adsorbed layers on the pore surface. Nevertheless, Rk values strongly decreased when increasing the brine flow rate. This second significant outcome shows that the adsorbed layers thickness is shear-controlled.

These new results should lead to proposing new adapted filtration and injection procedures for HMWSP, aimed in particular at improving their injectivity.
Transport and Retention of Aqueous Dispersions of Paramagnetic Nanoparticles in Reservoir Rocks
Authors: Yu H. , Kotsmar C. , Yoon K. Y. , Ingram D. R. , Johnston K. P. , Bryant S. L. , Huh C.
Published: July 2010

Paramagnetic nanoparticles have potential applications for enhanced oil recovery (by imposing an external field to control the behavior of injected fluids) and especially for evaluating oil saturations and other properties of an EOR target formation (by imposing a magnetic field near the wellbore after injecting fluid and measuring the response). However, the first requirement for these applications is the ability to place the particles a desired distance from the injection well. This means the particles should exhibit little retention in sedimentary rock and minimal formation damage. The ability to predict and control the degree of retention will be valuable for designing field trials and applications of such particles.

We evaluate the transport of surface-treated paramagnetic iron-oxide nanoparticles in sedimentary rocks by injecting aqueous dispersions of the particles into core plugs of different lithologies. The nanoparticle loading ranges from concentrated (10 wt %) to dilute (0.1 wt %). The dispersions are prepared with a range of ionic strengths and pH. Several different surface treatments yield stable dispersions of these particles, but provide very different transport characteristics. Effluent concentration histories are measured for particles that undergo little retention. The results are interpreted in terms of surface charges, zeta potential, and van der Waals interaction between particles and rock.

Our experiments indicate paramagnetic nanoparticles stabilized with small negatively-charged citrate ligands can significantly reduce retention in sedimentary rocks and incur little reduction in permeability. Little retention (<5 % of particles injected over several pore volumes) can be achieved even at very large injected concentration (10 wt %). Citrate-stabilized dispersions were stable even at high salinity (3 wt% NaCl) and the citrate provided electrostatic repulsion between particles and the negatively-charged sandstone and carbonate lithologies tested here. On the other hand polyvinylpyrrolidone (PVP), tetramethylammonium hydroxide (TMAOH) and oleic acid bilayer coatings also stabilized particle dispersions, but the attraction between polymer and rock surface led to high or near-total retention of injected particles.
Analytical Formulae for In-Situ Combustion
Authors: Mailybaev A. A. , Bruining J. , Marchesin D.
Published: July 2010

There is a renewed interest in using combustion to recover difficult oil. In spite of numerous experimental, numerical and analytical studies, the mechanisms for incomplete fuel combustion or oxygen consumption are not fully understood. Incomplete fuel combustion or oxygen consumption are indicators of sub-optimal process conditions and hazardous oxygen breakthrough in the production wells. This paper shows that these features emerge in a relatively simple 1-D model, where air is injected in a porous medium filled with inert gas, water and an oil mixture consisting of precoke, medium and light oil. Precoke is a component that is dissolved in the oil, but has essentially the same composition as coke. At high temperatures, precoke is converted to coke, which participates in high-temperature oxidation. At high temperatures, medium oil components are cracked releasing gaseous oil. Light oil components and water are vaporized. The model possesses an analytical solution, which was obtained by a method introduced by Zeldovich. This method entails that reaction can only occur in a very small temperature range, due to the highly non-linear nature of the Arrhenius factor. For a temperature below this range the reaction rate is too slow and for temperatures above this range the reacton rate is so fast that either the fuel or oxygen concentrations become zero. The model results show that there are two combustion regimes in which coke or oxygen is partially consumed. In one regime the reaction zone moves in front of the heat wave, whereas in the other regime the order of the waves is reversed. There are also two combustion regimes in which the coke and oxygen are completely consumed. Also here the reaction zone can move in front or at the back of the heat wave. Each combustion regime is described by a sequence of waves; we derive formulae for parameters in these waves. We analyse our formulae for typical in-situ combustion data and compare the results with numerical simulation.
Pore-network Prediction of Residual Oil Saturation Based on Oil Layer Drainage in Mixed-wet Systems
Authors: Ryazanov A. V. , van Dijke M. I. , Sorbie K. S.
Published: July 2010

Since EOR methods mobilize oil trapped by capillary and viscosity forces during waterflooding, prediction of residual oil saturation (Sor) after waterflooding is very important before carrying out any EOR process. The mechanism through which a particular EOR method, such as gas displacement, actually works to reduce residual oil depends in turn on how that oil is trapped at the pore scale. In this respect, pore-scale network modelling can be used to estimate both the nature of the trapped residual oil and the relevant flow parameters in its subsequent mobilization, if the correct physics of oil drainage are properly included.

During water flooding of mixed-wet systems, oil may drain down to relatively low residual saturations. A number of studies have indicated that such low saturations can only be reached when oil layers in pore corners are included in the pore-scale modelling. van Dijke and Sorbie (2006) obtained accurate thermodynamically derived criteria for oil layers existence in pores with non-uniform wettability caused by ageing, which is more restrictive than the previously used geometrical layer existence criteria. Recently, Ryazanov at el. (2009) have included these thermodynamic criteria in a two-phase pore network model, which takes as input geometrically and topologically representative networks, to calculate realistic Sor values for mixed-wet and oil-wet sandstones.

In this work, the network model has been validated through modelling of experimental data for water-wet and mixed-wet systems. A very good match has been obtained between experimental and simulated relative permeabilities for strongly water-wet Berea sandstone and oil-wet sandstone. Comparison with a range of mixed-wet core waterflooding experiments (Jadhunandan and Morrow 1995) showed good agreement with experimental residual oil and oil recovery efficiency.

This paper introduces the correct thermodynamically based physics of how residual oil is trapped in systems of arbitrary wettability. It is extremely important to understand this process, since the residual oil is the "target oil" for most EOR processes.
Upstream Oil and Gas Project Development Timing
Authors: Feng Shuqiang
Published: July 2010

Delays of project development have become one of the major concerns in the upstream oil and gas industry. An accurate projection of project timing is very important in production forecasting and project economics.

Statistical analysis shows that Time from Discovery to Production (TDP) has lognormal distribution, and thus, behaves like a random variable (Hattis and Burmaster, 1994). Using the historical average TDP to predict TDP of a new discovery is the same as predicting stock prices with history price data, and therefore, is not reliable, based on the random walking theory (Malkiel 1973), which states that the past movement or direction of the price of a stock or overall market cannot be used to predict its future movement. Operators have optimistic bias in their own project development timing estimation, and this becomes one of the major causes of project delays. The random nature of TDP and the operator's optimistic bias regarding project timing could mislead both investors in project economic valuation and contractors in market planning.

In order to increase the accuracy and objectivity of the project timing estimation and to predict project delays, this paper analyzes the First Production Time (FPT) estimation of oil and gas upstream projects by introducing a stage based multi-factor model in a dynamic environment. In this model, projects will be divided into seven different stages in the field development life cycle, which include Exploration and Discovery, Appraisal, Conceptual, FEED, EPC Bidding, EPC, and Producing. Then, the model will allocate estimated time to each stage including the gaps in between stages based on historical records and a set of factors. These factors include discovery commerciality, development feasibility, geopolitics, global economy, water depth, operators/partners strategy, project financing, contractor capacity constraints, etc, which would affect the project timing in specific stages.
Pore-Level Investigation of Heavy Oil and Bitumen Recovery Using Hybrid SAGD Process
Authors: Mohammadzadeh O. , Rezaei N. , Chatzis I.
Published: July 2010

Attempts have been made to reduce the energy requirements of a Steam Assisted Gravity Drainage (SAGD) project through coupled thermal-solvent processes such as hybrid SAGD, ES-SAGD, SAP and SAS. The augmented process brings superior features to the SAGD process in terms of reduced energy requirement, enhanced quality of produced oil and also improved oil recoveries. The pore-level recovery mechanisms of the hybrid SAGD process have not been investigated yet. The main objective of this paper is to visually investigate and to document the pore-scale events of the hybrid SAGD process using glass micromodel type of porous media. Different additives (n-pentane and n-hexane solvents) were added to steam prior to injecting into the model. Experiments were conducted in an inverted-bell vacuum chamber to reduce the excessive heat loss to surrounding. The results indicate that the gravity drainage process takes place through a thick layer of pores, in the direction perpendicular to the nominal oil-gaseous mixture interface, within the mobilized region. The interplay between gravity and capillarity forces results in the drainage of mobilized oil. The visualization results demonstrated coexistence of water-in-oil and solvent-in-water emulsification at the interface, due to the local condensation of both the steam and the vaporized solvent. The extent of emulsification depends directly to the temperature gradient between the gaseous mixture and the cold bitumen. Asphaltene precipitation was also observed when the condensed solvent reached to the bitumen interface. As the nature of the process tends towards being partially miscible, the extent of film-flow drainage type of mobilized oil was also significant. Other pore-scale phenomena such as localized entrapment of steam and vaporized solvent followed by condensation, steam and gaseous solvent condensation at the interface due to temperature gradient, capillary instabilities, and snap-off of liquid films were also illustrated using these pore-level visualization experiments.
New Analytic Solutions for Pipe Helical Buckling Problems
Authors: Teymoorishamasbi M. , Mohammadsalehi M. , Rashed G. , Salahshoor K.
Published: July 2010

There are some numerical solutions(4,5) for pipe buckling problems in vertical and horizontal wells, but, we need exact analytic solutions for precise analysis of pipe buckling problems. The first analytic solution for pipe buckling in a vertical well was presented by Lubinski and Woods in 1962(2). When the non-linear differential equation describing buckling behavior of pipes in vertical and horizontal wells was developed by R.F. Mitchell(6), this solution was found to be an exact analytic solution for this differential equation. No other analytic solution has been discovered until 2002(8), when, Mitchell himself developed three new analytic solutions for the vertical well buckling problems and two new analytic solutions for the horizontal well problems.

In this paper, these five solutions are described and modified to some extent, and the development and evaluation technique are presented. Some results of interest such as buckling contact force and critical force limits for pipe buckling also are developed. These analytic solutions are valuable both for predicting previously unanticipated buckling behavior and for providing guidance in further numerical evaluations of this problem.
Mechanical Alteration of Near Wellbore Mineralogy for Improved Squeeze Performance
Authors: Fleming N. , Ramstad K. , Wichers Hoeth L. , Kidd S.
Published: July 2010

Squeezing of clean, high permeability reservoirs frequently results in relatively short treatment lifetimes due to the low inhibitor adsorption rates achieved. One of the main controls on inhibitor retention is near wellbore mineralogy. Clay-rich reservoirs that contain abundant kaolinite, for example, often have long squeeze lifetimes as enhanced inhibitor adsorption can occur on the clay surface. The occurrence of CaCO3 cement in the near wellbore can also enhance inhibitor retention by forming a Ca2+/inhibitor complex.

Previously published research (Fleming et al., 2009a) demonstrated the potential to mechanically alter the near wellbore through incorporation of low concentrations of kaolinite and organosilane. The data presented in the present work shows that the additional incorporation of calcium carbonate provides a step change in the potential squeeze lifetimes achieved. This paper will present the results of utilising low, non-damaging concentrations of kaolinite and calcium carbonate particles in the preflush followed by scale inhibitor and organosilane in the main treatment. The kaolinite particles are retained in the near wellbore by the organosilane and enhance the number of potential sites for inhibitor adorption. At the same time, dissolution of the calcium carbonate particles by the acidic scale inhibitor forms a Ca2+/inhibitor complex that further enhances inhibitor retention.

A review of the technology performance envelope has been made through coreflooding that includes optimising the concentration of injection particles versus permeability, the ratio of injected kaolinite to carbonate particles, performance at elevated temperature (175°C) and an assessment of how often a well would require retreatment with particles. The latter has involved successive coreflooding of the same plug with the full treatment package followed by brine flowback and retreatment with scale inhibitor alone or with organosilane. This information can be used by the assets in their evaluation on potential use of the technology.
Field Implementation of a Novel Solids-Free System to Minimize Fluid Loss during Overbalanced Workover Operations
Authors: Vasquez Julio , Waltman Bart , Eoff Larry
Published: July 2010

Controlling fluid loss into the formation is of critical importance during overbalanced workover operations to minimized near-wellbore damage invasion by the completion fluid, which can yield problems associated with poor wellbore cleanout and loss of hydrocarbon reserves. In addition, fluid loss can increase costs associated with rig time and treatments devoted to restore the initial condition of the formation. Traditional techniques to minimize fluid loss use solids or viscous pills, although it has been amply documented that these systems can damage the formation if not properly removed after the treatment.

This paper presents the laboratory development and validation of a novel solids-free fluid-loss (SFFL) system used during overbalanced workover operations. This system relies on an ionic polymer that decreases matrix permeability to aqueous fluids, limiting leakoff into treated zones. This polymer immediately adsorbs to the surface of the rock, eliminating the need to shut the well in. In addition, this system does not require the use of breakers, which eliminates negative impact on post-stimulation well productivity. Laboratory test data show the capability of the material to control fluid leakoff and achieve high levels of regained permeability to hydrocarbons.

To date, about 60 jobs have been performed with this novel SFFL system. The paper discusses field results from the application of this system during overbalanced workover operations and other applications where maintenance of a hydrostatic column is necessary for well control. This system has been proposed for solving partial and total loss to full circulation in overbalanced operations such as: (1) lost-circulation events occurring during cementing, fracturing, and drilling, (2) well intervention cleanouts by coiled tubing (CT) and hydraulic workover (HWO), (3) gravel packing, (4) replacement of artificial lift equipment (i.e., electrical submersible pumps), and (5) overbalanced tubing-conveyed perforating (UTCP), among others.
Optimization, Uncertainty Analysis and Upscaling of Rock-Physics Models
Authors: Kazemi Alireza , Modin Dimitry
Published: July 2010

During the last years, geomodel to seismic 3D and 4D feed back loops are becoming a new industry standard in geoscience. These loops are basically suited for automatic geomodel updating and history matching where the discrepancies between seismic data and geomodel petrophysical infilling are detected. One of the most important components of this type of loops where the synthetic seismic data computation is a compulsary step is the Rock-Physics (RPM) or Petro-Elastic Model (PEM). RPMs are widely used in geoscience for different reasons: 1) modelling of the elastic logs to provide different fluid scenarii; 2) quantitative lithoseismic interpretation and supervised seismic facies classifications; 3) 3D and 4D loops.

In this paper we address several aspects: 1) different issues of RPM optimization at log scale; 2) uncertainty assessment of the RPM modelling results; 3) different approaches for RPM upscaling / recalibration at geological grid scale. The problem of RPM optimization and upscaling is an inverse nonlinear problem where around 20 of non-correlated coefficients in shale and sand compaction depth trend laws need to be found. Optimization is carried out with the means of global optimization tool based on simulated annealing algorithm. During the optimization the choice of the cost function is of a high importance. The uncertainty analysis is basically performed to assess the quality of the optimization and to establish some thresholds above which the results of modelling are qualified.

Our methodology was applied for a turbiditic West African offshore field. The result shows that such optimization methodology can reduce significantly the differences between observed P, S-impedances data and modelled ones from the optimized RPM compared to the base RPM. The results of forward modelling in elastic domain match better the 3D inverted seismic data with around 15% reduction of residuals due to only RPM recalibration.

From our observations, an upscaling of the RPM remains a delicate task which is of a second order importance compared to the fine tuning of the RPM at log scale. When the RPM is used for the forward seismic modelling, correct restitution of the elastic properties contrasts by the RPM is of high importance.
Interpretation of DFA Color Gradients in Oil Columns Using the Flory-Huggins Solubility Model
Authors: Zuo Julian Y. , Freed Denise , Mullins Oliver C. , Zhang Dan , Gisolf Adriaan
Published: July 2010

Downhole fluid analysis (DFA) has been successfully used to delineate reservoir attributes such as vertical and lateral connectivity and properties of the produced fluids. The new-generation DFA tools not only measure bulk fluid properties such as gas/oil ratio (GOR), density, and light-end compositions of CO2, C1, C2, C3–C5, and C6+ more accurately but also color (optical density) that is related to the heavy ends (asphaltenes and resins) in real time at downhole conditions. In addition, the color measurement is one of the most robust measurements in DFA. Therefore, color gradient analysis in oil columns becomes vital to discern reservoir complexities by means of integrating advanced asphaltene science with DFA Fluid Profiling.

In this paper, a thermodynamic asphaltene grading model was developed to describe equilibrium distributions of heavy ends in oil columns using the multicomponent Flory-Huggins regular solution model combined with a gravitational contribution. The variations of oil properties such as molar volume, molar mass, solubility parameter, and density with depth were calculated by the equation of state (EOS). A three-parameter Gamma distribution function was employed to characterize asphaltene components. The primary factors governing asphaltene distribution in reservoirs are the gravitational term, which is determined in part by the size of the asphaltene molecular or colloidal particle, and the solubility term, which is determined in large part by the GOR. Consequently, it is critical to accurately measure both the fluid coloration and the GOR to understand the asphaltene distribution. The two field case studies showed that colored resins (asphaltene-like heavy resins) were molecularly dissolved in condensate oil columns whereas asphaltenes were dispersed as nanoaggregates in crude oils. The heavy ends (resins or asphaltenes) have a preference of going to the bottom of the oil column both because of gravity and the variation of the liquid-phase (live oil mixture) solubility parameter. The results obtained in this work were in accord with the observations in recent advances in asphaltene science. The asphaltene distributions were consistent with an equilibrium distribution implying reservoir connectivity. In both cases, the subsequent production data proved the reservoir connectivity and the methods developed herein were validated. This methodology establishes a new powerful approach for conducting DFA color and GOR gradient analyses by coupling advanced asphaltene science with DFA Fluid Profiling to address reservoir connectivity.
Potential and Early Opportunity-Analysis on CO2 Geo-Sequestration in China
Authors: Xuan Zhao , He Shunli
Published: July 2010

CO2 geo-sequestration, as an effective method to reduce Green House Gas emissions, is a front subject in China. In order to identify the potentials of implementing large scale CO2 sequestration projects according to China's current development tendency, this paper analyzes the general formation conditions of the main oilfields in China, which are manifested in complex formation structure with strong heterogeneity, low or ultra-low permeability and low porosity.

In China, the main application mode of CO2 sequestration, also the most profitable method, is to inject CO2 into oil and gas reservoirs to enhance recovery. Meanwhile, 60%-80% of the injected CO2 could be stored into the formation. Jilin oilfield in northeast of China, the dominant test field for CO2 sequestration, has been listed into the National Key Program in 2006. Pilot tests reveals formation here is featured with well developed sand body, good connectivity, well defined cap rock, undeveloped fractures, and independent hydro-geological system, which contribute to a considerable and secured storage for CO2. Though still on the initial stage, studies here would shed light on the further researches in China.

Some unique advantages of conducting CO2 sequestration projects in China have been summarized and analyzed in this work too. Most of the new-found oil and gas reservoirs belong to low-permeability reservoirs, wherein CO2 flooding shows its superiority over conventional water injection in tight formations. Moreover, both main CO2 sources (coal-fired plants & power plants) and injecting sites(low-permeability reservoirs) locate in northern and eastern China, which would meet the demand of CO2-EOR and shorten the distance of transportation to reduce corrosion risk and operation cost. Although being not regulated by Kyoto Protocol, positive measures of CO2 sequestration in China possesses a significant and far-reaching meaning to releive the pressure of global environment.
Calcite Scale Prediction and Management in a Chalk Reservoir – Field Cases
Authors: Zhang Yuping , Samuelsen Eivind , Frederiksen Rene , Roberts David , Ginty Bill
Published: July 2010

This paper demonstrates a field case study where large volumes of deferred oil, due to calcite deposition, have been reduced by effective scale modeling and a strong focus on optimised well performance.

The South Arne field, operated by Hess Denmark, on behalf of the South Arne Partnership, is an oil field in the Danish sector of the North Sea. Production is from a chalk reservoir using de-sulphated seawater injection for pressure support. Calcite deposition has been problematic in some of the wells with a variety of mitigation and clean-up methods being employed. The deferred production peaked with 100,000 barrels of oil in 2006. Since then, the oil deferment has been reduced by 75 % by continuously improving the calcite scale prediction and prevention for the wells.

Modeling carbonate scale deposition is challenging and many scale prediction models can be over-conservative, leading to unnecessary chemical injection, excessive use of chemicals and sub-optimal oil production. A new methodology for predicting calcite scale has been applied to the South Arne field, becoming a successful tool for downhole scale management.

This new approach is based on scale kinetics as a function of temperature, integrated with detailed pressure-temperature traverse data derived from the interpretation of well tests and gas lift performance. Results have been used to guide well operation decisions and to support a new scale prevention strategy based on deep injection of large volumes of lift gas.

Accurate calcite scale prediction is sensitive to the carbonate alkalinity. The approach described here is based on simulating the calcite scaling kinetics from reservoir to wellbore. Model results show that produced water is close to calcite saturation from deep reservoir to the wellbore, and this has been used as the basis for calculating carbonate alkalinity in the produced water. Hence in this paper the calcite saturation index for the onset of scaling has been defined using calcite kinetics to give a fixed scaling rate rather than the more customary use of a fixed saturation index.

In addition, well performance models were completely re-worked to include observations from recent well interventions and new data input parameter validations.

The calcite scale prediction methodology described here has provided the South Arne field with benchmarked operating scale envelopes that on a regular basis are utilised to optimise well performance in terms of risk and reward.
Successful Water Shut-off Through Innovative Data Acquisition and Phased Planning
Authors: Samuelsen Eivind H. , Frederiksen Rene A. , Noer Jesper , Hartvig Sven K. , Haugan Are
Published: July 2010

This paper demonstrates how innovative data acquisition, phased planning and world class placement of filler material in a short circuit lead to a successful water shut-off restoring 477 m3/day (3,000 BOPD).

Hess operates the South Arne Field located offshore Denmark. Two flank horizontal wells, a producer and a water injector, started short-circuiting water via an abandoned sidetrack. High pressure (517 barg) water from the injector flowed directly into the producer (172 barg) killing the oil production.

The wells’ horizontal length is 3 km and is completed with a cemented liner. The liners are subdivided into 17 zones with production/injection tubing, iso-packers and sliding sleeve doors. Each zone has been stimulated with acid fractures.

The vital part of the data acquisition was multiple tracer tests from different zones at different production and injection ratios, which increased the tracer recovery from 15% to 100%. In addition, tracer data revealed transit time, sidetrack volume and number of paths; all crucial information for a successful water shut-off. A gel mimic test was performed to account for differences in rheology.

Pressure and temperature logging tools in the wells provided the pressure and temperature gradient along the sidetrack, which was crucial data for placement of the temperature sensitive filler material.

The decision was to approach the challenge in three phases; firstly, data acquisition; secondly, interpretation of data, filler material laboratory tests, design of job; thirdly, implementation of the water shut-off. This proved to be advantageous as it allowed time for appropriate adjustment and planning of the complex setup.

The 19 m3 (120 barrels) of filler material was mixed on the platform and pumped into the injection well tubing while producing from the production well at controlled condition with one optimal sliding sleeve door open in each well and an optimal production/injection ratio The temperature of the filler material increased as it travelled to its final destination in the sidetrack leaving a 450 m (1475 ft) solid isolation plug.

One year after the water shut-off, oil production has increased from 0 to 477 m3/day (3,000 BOPD) saving an expensive and challenging re-drill.

This project underlines the importance of spending time and money, upfront, on innovative acquisition and planning to increase a project's chance of success.
Utility Calculation Method of New Four-Parameter Rheological Model for Drilling Hydraulics
Authors: Wang Guo , Fan Hong H.
Published: July 2010

The prediction of pressure losses is very important in many oil-field operations, including drilling, completion, fracturing, acidizing, workover and production. In this study, a utility hydraulic calculation method has been developed that requires as input the raw fluid rehological data and relevant hydraulic parameters. This new method is based on three important developments.

First, this paper presents a new and powerful rheological model, named four-parameter model. A brief introduction was given to the determination of rheological parameters. Calculation model for rheological parameters was built based on regression method. Using a variety of data from literature, it is shown that four-parameter model could precise represent the rheogram of the time-independent fluids.

Second, a generalized hydraulic calculation model is developed based on power law extension method, which is independent of the form of the rheological model of choice. For laminar flow, pressure drop formula is derived based on characteristic method of pipe flow. And turbulent pressure loss is calculated by semi-empirical formulas. Flow regime determination method is established by quoting generalized flow behavior index.

Third, for pressure drop calculation precisely, the approach includes the additional pressure loss due to the effect of tool joints, accommodates drilling pipe rotation effects and accounts for the effects of annular eccentricity. Furthermore, simple, explicit and general formulations for approximation pressure losses over measurement while drilling tools are also presented to augment the suite of expression required for complex hydraulic calculation.

The predictions of the developed method have been compared with several sets of experimental hydraulic data from different sources. The tested cases include laminar and turbulent flow of various drilling fluids in both pipe and annular geometry. The generalized hydraulic calculation model is shown to be quite accurate and superior to those obtained by the currently available standard techniques.