bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comprehensive Mechanistic Modeling of Two-Phase Flow in Deviated Wells
Authors: Kaya A. S. , Sarica C. , Brill J. P. 
Published: December 2007

Abstract
A new comprehensive mechanistic model was developed to predict flow pattern and flow characteristics such as pressure drop and liquid holdup in vertical and deviated wells. The model includes five flow patterns: bubbly, dispersed bubble, slug, churn and annular flows.
Flow pattern prediction incorporates the transition models proposed by Barnea1 (or Taitel et al.2) for dispersed bubble flow, Ansari et al.3 for annular flow, Tengesdal et al.4 for churn flow, and a new bubbly flow transition model. For each predicted flow pattern, a separate hydrodynamic mechanistic model is proposed. A new hydrodynamic model for bubbly flow has been developed, and the Chokshi5 slug flow model has been modified significantly. The Tengesdal et al. and Ansari et al. models have been adopted for churn and annular flows, respectively.
The comprehensive model is evaluated using a well databank of 2,052 cases covering a broad range of field data. Pressure drop predictions with the model are also compared with those using the Ansari et al., Chokshi, Hasan and Kabir6, and Tengesdal mechanistic models, and the Aziz et al.8, and Hagedorn and Brown9 correlations. The results of the comparison study show that the proposed comprehensive mechanistic model performs the best and agrees with the data.
Acid Stimulation of Power Water Injectors and Saltwater Disposal Wells in a Carbonate Reservoir in Saudi Arabia: Laboratory Testing and Field Results
Authors: Mohamed S. K. , Nasr-El-Din H. A. , Al-Furaidan Y. A. 
Published: December 2007

Abstract
Seawater power injectors and saltwater disposal wells are used to maintain reservoir pressure in a carbonate reservoir in Saudi Arabia. Various forms of hydrochloric acid were used to stimulate damaged wells and restore the injectivity of these wells. The forms of the acid used were regular, emulsified, and in-situ gelled acids. Acid diversion was achieved by using a coiled tubing unit, nitrogen foam, in-situ gelation, emulsified acid or combinations of these methods.
A comprehensive investigation was undertaken to assess the effectiveness of acid treatments performed in the field and improve the outcome of the acid jobs. Laboratory and field investigations were conducted simultaneously to address formation damage and associated problems. These investigations included coreflood tests to screen various acid formulae, and analysis of field samples to identify the damaging mechanism.
More than 80 acid jobs were analyzed in this study. A new empirical coefficient was identified and used to evaluate these jobs. The coefficient was based on: 1) the ratio between the pre and post acid injectivity indices, 2) the rate of decline of normalized well injectivity index, and 3) the incremental cumulative injection from the Hall plot following the acid job and before the first change in the slope. In addition, chemical analysis of acid returns (spent acid) was used to assess the damaging mechanisms and determine the type and concentration of various acid additives.
Improper use of emulsified acid and in-situ gelled acid was found to result in poor field results. The outcome of acid jobs was found to be a function of the volume ratio of regular to in-situ gelled acid. Good field results were obtained when the volume of in-situ gelled acid was 15-30% of that of the regular acid (15 wt% HCl). Furthermore, the study confirmed that acid injection using coiled tubing enhanced the efficiency of the acid treatment.
This paper highlights the importance of conducting laboratory and field evaluation of acidizing treatments. The following new findings were obtained:
A new job index was developed and used to assess acid treatments in the field. Severe formation damage can result from the improper use of in-situ gelled acids. Analysis of spent acid was effectively used to optimize the concentration and type of various acid additives.
Design Approach to Sealant Selection for the Life of the Well
Authors: Bosma Martin , Ravi Kris , Driel Willem van , Schreppers Gerd Jan 
Published: December 2007

Abstract
Recent experience in the field has demonstrated that the mechanical properties of the annular sealant are a critical factor in the success of a well. A demanding operational regime such as High Pressure/High Temperature (HP/HT) and well interventions, e.g. pressure testing stimulation, place high demands on the mechanical design of a candidate sealant.
The following steps should be followed to determine the required mechanical properties of such well sealant candidates:
The stability of the bore hole should be evaluated prior to placing the sealant in the annulus. The stability is affected by the far field stresses, the weight (s.g.) of the drilling fluid and the mechanical properties of the formation. The integrity of the sealant should be investigated for the
operational envelope of the well. Finite Element models were used to determine the influence of wellbore stability aspects and the effects of loading on the integrity of the sealant. The mechanical properties of the sealant considered were elasticity, tensile strength, shear strength and bonding strength. In this way it was possible to examine aspects of non-linear material behavior of the sealant.
The following factors were investigated in this study:
What are the well parameters and its operating envelope? What are the total stresses on the formation and on the sealant under various HP/HT conditions? Which mechanical properties does the sealant have to possess in order to be able to withstand different types of stress?
The study indicated that there is a strong interaction between on the one hand the behavior of the sealant and on the other hand the formation in-situ stresses, the formation properties, the well completion parameters and its operating envelope. Depending on these input conditions, the sealant was observed to behave in one of the following manners.
The sealant remained intact without any damage. A micro annulus occurred between sealant and casing/formation. The sealant failed because of either tensile or shear deformation.
Calculations were performed for various wellbore stability scenarios, well completion characteristics, well loading envelopes and properties of the sealant. Typical oil well cement slurries, latex slurries, foam cements and cement hybrids were investigated. Typical results from the study are discussed and procedures for field application are given.
An Integrated Solution of Extended-Reach Drilling Problems in the Niakuk Field, Alaska: Part I - Wellbore Stability Assessment
Authors: Dowson S. L. , Willson S. M. , Wolfson L. , Ramos G. G. , Tare U. A. 
Published: December 2007

Abstract
The Extended Reach Drilling (ERD) program in the Niakuk Field, North Slope, Alaska was suspended in January 1998 due to hole problems in the 8.5" sections of two ERD wells. An integrated wellbore stability study was undertaken to identify and address the problems. The work undertaken involved detailed characterisation of the troublesome shales and calculation of mud weights required for acceptable hole quality and well stability.
This paper shows how instability in the two suspended wells was attributed to both compressive and tensile failure of the shale formations. The primary cause of well failures was drilling with too low a static mud weight, typically 0.5 ppg lower than recommended for acceptable hole quality. In addition, the wells used a viscous mud, possessing a high Equivalent Circulating Density (ECD) relative to its static mud weight. This resulted in a time-dependent, fatigue-induced extension mode of borehole instability. This mode of failure is not common but is highlighted as a mechanism requiring attention in ERD well planning.
The paper documents the back analysis of well failures, synthesis of geological information, the analysis approach adopted for assessing chemical and mechanical instability, and a forecast of required mud weights for future ERD wells. The paper then presents a summary of subsequent well drilling case histories which show improvements in hole quality due to decreased instability. This resulted in a reduction of non-productive time and large cost savings to the business. In particular, one of the suspended 8.5" hole sections has now been side-tracked with negligible hole enlargement over a 5730ft section through previously troublesome shales.
In conclusion the paper emphasises the need for a proper wellbore stability assessment prior to drilling challenging ERD wells.
Full field pressure simulations using a very accurate, yet inexpensive well model
Authors: Baumann C.E. , Price H.S. , Reddy M.P. , Thuren J.B. 
Published: December 2007

Abstract
The technique presented in this paper is aimed at solving the pressure equation in oil reservoir models containing a large number of wells. This technique is applicable to heterogeneous reservoirs and does not require computational meshes that conform to the wells. Typically, several perforated wells may appear within a single computational element (grid block), and horizontal/deviated wells are simulated with the same methodology as vertical wells.
The numerical technique used to simulate near-wellbore flows is a special form of the generalized finite element method with special basis functions. No productivity index or any other approximation is used; the near-wellbore pressure is modeled by the use of special basis functions. This technique is very accurate yet inexpensive, because higher accuracy is obtained without resorting to fine grids around wells. For this reason, this technique is very well suited to simulate wells that are turned on/off frequently. When wells come online or are shut off, the wells are automatically added/removed from the model. This translates in net saving at no cost, because this technique does not incur in the extra cost of having a fine mesh where is not needed.
Analysis of Stuck Pipe in Deviated Boreholes
Authors: Aadnøy Bernt S. , Larsen Kenneth , Berg Per C. 
Published: December 2007

Abstract
The complexity of the wells haveincreased significantly inlater years. Reach has more than doubled, and highinclination and fully 3-D well paths are common. However, statistics shows that sidetracking the boreholes due to stuckpipe has also shown a significant increase, and is presently ahigh cost factor. The margins between success and failure arenow much smaller.
A larger study was initiated to understand the stuck pipesituation better, and to develop improved procedures. Amechanistic approach was chosen. The following elementswere analyzed: 1) the forces developed during differentialsticking, 2) pipe strength under combined loads; tension, torque and pressure, 3) effects of buoyancy under variousconditions like equal or different mud densities in drillpipeand annulus, 4) wellbore friction as related to torque and drag.
This paper presents new equations to determine depth to thestuck point in deviated wellbores, based on pulling tests andtorsion tests. In particular it is shown that bends in thewellbore leads to more friction, which with the new equationsresults in a deeper stuck point in a deviated well compared to asimilar vertical well. Knowing all the forces involved in astuck pipe case, another analysis was performed to determinethe action that has largest impact to free the pipe. One of themain conclusions is that the most important element to freethe string is to keep the bottomhole pressure as low aspossible. The paper will present three methods to free thepipe, which where developed from the analysis: 1) maximummechanical force method, 2) minimum density method, and 3)maximum buoyancy method. A detailed field case from theYme field in the North Sea will demonstrate these methods, and show the effect on the stuck point using each method.
In addition to the field case, the paper will in the Appendicespresent the complete equations for pipe stress and strengthunder 3-dimensional loading, and define the effects ofbuoyancy in deviated wellbores. In particular is the buoyancyissue resolved, showing the differences and similaritiesbetween "the piston force approach" and the law ofArchimedes, as applied to deviated wellbores.
Rheology of Various Drilling Fluid Systems Under Deepwater Drilling Conditions and the Importance of Accurate Predictions of Downhole Fluid Hydraulics
Authors: Davison J. M. , Clary S. , Saasen A. , Allouche M. , Bodin D. , Nguyen V-A. 
Published: December 2007

Abstract
Previous rheological studies of water-base and oil-base muds have concentrated on fluid viscosities at elevated temperatures and pressures. This paper extends the data available to cold temperature regimes which can be expected to occur in the riser for deepwater wells. The rheology of eighteen different drilling fluids covering WBM, OBM and SBM have been evaluated between -1° to 90°C and 1 to 344.7 bar. The Herschel-Bulkley and Casson models both fitted the OBM and SBM rheograms very well. For the different WBM systems, the Herschel-Bulkley model also fitted the salt/polymer fluids and unweighted bentonite-based fluid rheologies, however, the Casson model best described the weighted bentonite-based fluid rheologies. The effect of the cold fluid viscosity in the riser on ECD for deepwater wells was assessed using a software model which uses a transient temperature simulator in conjunction with a hydraulic model which accounts for different mud viscosity throughout the wellbore. Comparing the ECD predictions with those calculated where the mud rheology is independent of temperature and pressure, the ECD was found to be underestimated by up to 6.1% for a SBM and overestimated by 3.1% for a WBM. If there are formations with small differences in the fracture and pore pressure gradients, then these variations in ECD could cause well control problems.
Cleanup of Wall-Building Filter Cakes
Authors: Zain Zulkeffeli M. , Sharma Mukul M. 
Published: December 2007

Abstract
Building up external filter cakes during drilling and completion operations has long been one of the most practical ways to minimize fluid loss to the formation. The effectiveness of the filter cake is critical especially for long openhole completions with no perforations. It is usually assumed that this wall-building material will be removed during oil production, due to pressure drawdown. However, it is quite commonly observed that only a small fraction of the cake is removed, leaving large portions of it remaining on the formation face. This condition results in a small wellbore area open to flow and a large skin. To increase the flow area and minimize skin, the filter cake needs to be completely removed. Solids from filter cakes can also cause plugging of screens and gravel packs. This is particularly important in horizontal wells completed openhole.
Experimental results are reported for mud cake lift-off tests. The flow initiation pressures required to flow through or remove drilling and completion fluids filter cakes are measured together with the return permeability of the rock. In this study, sized CaCO3 and sized salt drill-in mud were tested on rock samples with permeability ranges between 3 to 2000 md. The effects of mud filtration pressure, rock permeability, and flow back rate were also investigated. The results show that sized CaCO3 fluids require lower flow initiation pressures and are less damaging than sized salt fluids. Despite having low mud filtrate volume and less internal damage, low permeability samples need relatively high flow initiation pressures compared to high permeability samples. Total mud cake removal is observed for experiments with limestone cores while only cracks and small holes were seen for experiments with sandstones. This observation suggests that cake removal is not just a function of permeability but depends on mineralogy as well. High overbalance pressures were also found to increase the magnitude of the flow initiation pressure.
Methodology for Variogram Interpretation and Modeling for Improved Reservoir Characterization
Authors: Gringarten E. , Deutsch C. V. 
Published: December 2007

Abstract
The variogram is a critical input to geostatistical studies. It is the most widely used tool to investigate and model spatial variability of lithofacies, porosity, and other petrophysical properties. In addition, 90% of geostatistical reservoir characterization studies use variogram-based geostatistical modeling methods. Furthermore, the variogram reflects our understanding of the geometry and continuity of reservoir properties and can have an important effect on predicted flow behavior and consequent reservoir management decisions. Yet, the practice of variogram interpretation and modeling is poorly documented and unexperienced practitioners find themselves at lost when required to provide a reliable variogram model. This often results in wrong variogram models used in subsequent geostatistical studies.
Our approach is a two-step procedure similar to that used in modern well test interpretation, that is, model identification followed by parameter estimation. The total variance of the phenomenon under study is divided into variance regions. The behavior of each variance region is shown to follow clearly defined behaviors reflecting well-understood geological features. Establishing a mathematically consistent and geologically interpretable variogram model is straightforward after model recognition.
The proposed methodology for variogram interpretation and modeling provides a better, more rigorous, quantification of spatial variability, which leads to improved flow models and management decisions. The theoretical background of our methodology will be presented. A number of case studies are then shown to illustrate the practical importance of the methodology.
Accuracy Prediction for Directional MWD
Authors: Williamson Hugh S. 
Published: December 2007

Abstract
This paper describes a new method for predicting wellbore position uncertainty which responds to the current needs of the Industry. An error model applicable to a basic directional MWD service is presented and used for illustration. As far as possible within the limitations of space, the paper is a self-contained reference work, including all the necessary information to develop and test a software implementation of the method.
The paper is the product of a collaboration between the many companies and individuals cited in the text.
Modelling of Gel Diverter Placement in Horizontal Wells
Authors: Menzies N. A. , Mackay E. J. , Sorbie K. S. 
Published: December 2007

Abstract
Optimum placement of injected fluids during scale inhibitor or acid stimulation treatments is often difficult to achieve in long horizontal or deviated wells. Crossflow effects that displace the injected fluids away from the target zone can exacerbate the problem, even when coiled tubing is used to deliver the chemicals to the desired location. To overcome these problems, diversion techniques, using waxes or polymer cross-linked gels, can lead to improved placement with little detrimental impact on post treatment production.
Placement of the diverter itself is not always simple, particularly for gels where the rheology is controlled by temperature and shear rates. Modelling techniques are being developed to assist engineers to design the various stages of these diverter treatments. The model described here was developed, using a commercial reservoir simulation code, to simulate the placement of polymer gels in high crossflow wells. The model parameters were based on a field inhibitor squeeze treatment performed on a 2,000 ft highly deviated well that (cross) flowed 3,500 bbls/day during shut-in. The effect of the crossflow during the various injection and shut-in stages of the squeeze treatment would be to displace the inhibitor away from the water producing zones, hence leaving these sections of the well unprotected. Accurate placement of the gel would prevent loss of inhibitor to the thief zones, ensuring protection for the intervals vulnerable to scale, and thus extending the time before the well would need to be re-squeezed.
The initial gel placement model demonstrated the interaction between viscosity, friction and transmissibility profile along the well at various injection and crossflow rates. A threshold viscosity was identified above which the injectivity profile was dominated by connection transmissibility factors rather than the friction and crossflow forces. The model was then developed to incorporate the effect on the gel viscosity of varying shear stresses along the wellbore and in the formation.
Development of a model that can predict gel placement enables optimisation of the diverter stage of a treatment. It also leads to more accurate modelling of subsequent chemical injection (eg. inhibitor or acid), and hence the benefit to squeeze lifetime resulting from the placement strategy can be assessed.
Screen Performance and Cleanup Characterization in Horizontal Well Drill-in-Fluids Using a Large-Scale Radial Flow-Cell
Authors: Asadi Mahmoud , Penny Glenn S. 
Published: December 2007

Abstract
A large-scale radial flow cell was utilized to characterize 0.004 in. gauge, 0.006 in. gauge, and 0.008 in. gauge 40/60 resin coated prepack screens based on retention testing. In addition, screen cleanup methods such as backflow (flowing water in the injection and production directions), 10% hydrochloric acidization at 120°F, enzyme soaking, and the use of breaker were evaluated on damaged screens. A carbonate drill-in-fluid (DIF) containing 5000 and 10,000 PPM solids was formulated and pumped for three hours at 16 gpm and 120°F into the flow cell and around the screen at a constant 60 psi differential pressure across the screen. Effluent samples of drill-in-fluid were collected to measure total solids. Removal efficiency of each screen was then calculated. Damaged screens were then subjected to one or a combination of various cleanup methods. Permeability of the treated screen was measured to 10-ppg NaCl brine solution and was compared to the screen's original permeability. The degree of plugging was evaluated based on the retained permeability of each screen after being subjected to one of the cleanup methods.
Geostatistical Scaling Laws Applied to Core and Log Data
Authors: Frykman P. , Deutsch C. V. 
Published: December 2007

Abstract
Reconciling data from different scales is a longstanding problem in reservoir characterization. Data from core plugs, well logs of different types, and seismic data must all be accounted for in the construction of a geostatistical reservoir model. These data are at vastly different scales and it is inappropriate to ignore the scale difference when constructing a geostatistical model.
Geostatistical scaling laws were devised in the 1960s and 1970s primarily in the mining industry where the concern was mineral grades in selective mining unit (SMU) blocks of different sizes. These principles can be extended to address problems of core, log and seismic data. The adoption of these classic volume-variance or scaling relationships presents some challenges. Some specific concerns are (1) the ill-defined volume of measurement, (2) uncertainty in the small-scale variogram structure, and (3) non-linear averaging of many responses including acoustic properties and permeability.
We demonstrate the application of volume-variance relations for upscaling and downscaling techniques to integrate data of different scales. Practical concerns are addressed with data from a chalk reservoir in the Danish North Sea. A direct sequential simulation algorithm accounting for data at all scales is documented.