bluuebunny/crossref_metadata_2025_split huggingface dataset:
Identifying Well Completion Applications for Passive Inflow Control Devices
Authors: Garcia Gonzalo A. , Coronado Martin P. , Gavioli Paolo 
Published: October 2009

Abstract
The main horizontal well completion issues have been identified and addressed during the previous decades, resulting in wells with better performance, lower water production and higher recovery efficiencies. One of the most important issues has been inflow equalization, which is affected by reservoir heterogeneities and pressure losses in the completion (annulus and liner). Evaluations of the flow equalization, in sandstone and natural fracture reservoirs, along horizontal wells have shown the importance of this technique to improve reservoir management.
Passive inflow control device (PICD) performance in producer and injector wells under different fluid properties (density and viscosity) and operational conditions will be presented to show the technical benefits of this technique as well as their improved recovery efficiencies when compared to non-PICD completions. The quantification of the benefits of this completion technique was performed using a fully integrated reservoir simulator where the PICD flow performance characteristic, well completion description (packers, blank pipe, gravel pack, annulus flow, etc.), and reservoir simulation are considered.
Lessons learned and best practices regarding equipment selection and specification acquired during the last 10 years are summarized to define potential PICD applications in horizontal wells. Finally, the field experiences and numerical simulation results are analyzed to establish the best well completion strategy to fit specific reservoir conditions.
Modeling Horizontal Completion Deformations in a Deepwater Unconsolidated Sand Reservoir
Authors: Hilbert L. B. , Saraf V. K. , Birbiglia D. K. J. , Shumilak E. E. , Schutjens P. M. T. M. , Hindriks C. O. H. , Klever F. J. 
Published: October 2009

Abstract
We present the development and results of geomechanical models and analyses used to assess the risks of compaction-induced deformation and potential failure of horizontal gravel-pack completions in a field located in deepwater, but at shallow depth below the sea floor. The target reservoir consisted of high-porosity, under-consolidated stacked turbidite sandstones, which are comparable to some of the more well-known, problematic compactive reservoir sands. The formations indicated a high level of risk of depletion-induced compaction, which could produce large deformations and potential failure of completion equipment in horizontal wells. Coupled poroelastoplastic geomechanical finite element models were constructed to assess the risks of completion equipment damage due to depletion-induced reservoir compaction. Both open-hole and cased-hole gravel packed completion configurations were analyzed. Details of the pre-packed screen assembly components were included in the models, such as the ribs between the base pipe and inner screen, and deformable epoxied sand between inner and outer screens. Model results presented in this paper include deformations of the completion equipment and stresses in the screen components, as a function of reservoir depletion pressure. The results of the geomechanical modeling indicated that the overall compaction loading should not cause significant deformation of the specified completion equipment.
Fluid Selection for Energized Hydraulic Fractures
Authors: Friehauf Kyle E. , Sharma Mukul M. 
Published: October 2009

AbstractTraditional hydraulic fracture simulators do not take into account the compositional, thermal, and phase behavior effects that are crucial to the success of energized fractures. This implies that until recently there has not been a systematic, simulation based approach for energized hydraulic fracture design.Traditional water-based fracturing fluids are not ideally suited for use in tight, depleted or water sensitive formations. In such situations, if the drawdown pressure does not overcome the capillary forces in the formation, the liquids leaking-off will remain trapped in the invaded zone around the fracture face. A fluid is energized by adding a gas component to the fracturing fluid. Gas addresses the water trapping problem by creating a high gas saturation in the invaded zone, thereby facilitating gas flowback.In this paper, a fully compositional fracture simulator is used to evaluate different designs for energized fractures. It is shown that gases with high solubility in aqueous solutions perform significantly better than gases that are not. CO2 has higher solubility than N2, and therefore outperforms N2 in most cases. Because N2 is less soluble in water, additional measures are needed to make sure it is present in the invaded zone. This can be done by delaying flowback and allowing the gas phase to penetrate into the invaded zone. Adding methanol to the liquid phase can increase the solubility of CO2 and reduce clay swelling in some formations resulting in more effective fracture treatments.It is shown that energized fluids should be applied to rocks when the drawdown pressure is insufficient to remove the liquid. This corresponds to a drawdown pressure of ~200 psi for 0.1 md formations, ~500 psi for 0.01 md, and ~1500 psi for 0.001 md.Simulations show that under a wide range of reservoir conditions, foam qualities from 30 to 50% are optimum because they allow enough gas to saturate the liquid to maximize gas flowback and they yield long fractures. Higher quality (up to 70%) may be necessary if shorter and wider fractures are preferred.Use of a compositional fracture simulator allows us for the first time to systematically design energized fracture treatments. Simulations provide a cheap and effective method of predicting fracture performance and reaching conclusions that allow the design of better performing fractures.
Wellbore Re-entries and Repairs: Practical Limits of Cementing New Casing Inside Existing Casing
Authors: Metcalf Arthur S. , Purvis Donald L. , Stillwell Shannon 
Published: October 2009

Abstract
Whether a well is being re-entered, after having been abandoned for some time or it simply needs to be repaired to be functional, many operators choose to cement a new smaller outside diameter (OD) casing string inside the old one. Wells previously abandoned have been re-evaluated and found to respond to fracture stimulation using newer methods; however, to accomplish this, the casing string must have integrity. Casing integrity is also of significance to operators in view of state regulations.
The challenges of this type of operation are many. One of these is to avoid excessive surge pressures while running the new casing and means that on many occasions running rates of the casing may have to be approximately 1 foot per second. Excessive surge pressure can fracture a formation of interest, making it difficult to obtain the desired production rates. Another challenge is to match casing size for stimulation with achieving successful cement isolation of an annular space. Smaller diameter casing will result in increased friction pressure and therefore treatment rate restrictions. Stimulation may require multistage completions to be effective. The increased cost of stimulation must be balanced with the need to achieve cement isolation.
Presented are the analyses of various scenarios examining fracture gradient, old casing burst pressures, fracture stimulation rates and pressures and equivalent circulating densities of potential cement slurries. Case histories are used to illustrate these scenarios and present situations in which the cost of the cement pumped versus what should have been required is compared. Also presented, are the operational and cost differences regarding stimulation as a function of casing internal diameter. In one case over three times the quantity cement, which should have been necessary to achieve circulation back to surface, was pumped without circulating.
New Liner-Hanger Technology Improves Safety and Reduces Non-Productive Time in Deviated High-Temperature Wells in South Central Venezuela
Authors: Jimenez Cesar , Soto Simon , Leon Andrehny , Marval Pedro , Schoener-Scott Martin 
Published: October 2009

Abstract
In deep drilling operations, liners hangers are used to eliminate the need to run full strings of casing. Unlike regular casings that are installed back to surface and will be terminated downhole at a hang-off point in the last casing. Depending on the wellbore conditions, deploying liner hangers can be very difficult, and in many scenarios, the bottomhole assembly (BHA) must be rotated and/or reciprocated in order to set the BHA at the target depth. Unfortunately, conventional liner-hanger systems often do not permit tool rotation due to the complex design. Liner-hanger deployment failures can cause loss of the wellbore or a section of the wellbore, which in turn, will result in additional well construction costs to sidetrack and drill another section through the production zone.
An expandable liner hanger that has a less complicated design that withstands aggressive reaming as well as drilling to depth is now available. This expandable system has no external moving parts such as slips, hydraulic-setting cylinders or separate liner-top packers, which are used in conventional liners. These attributes help mitigate the risks associated with the deployment exercise and complexity of the completion.
PDVSA embraced this technology to help them optimize operations in their deep wells in which extreme environments, often close to 300°F, with deviations greater than 60 degrees and setting depths of more that 12,000 feet are encountered.
The benefits that have been gained by adopting this technology are: Optimized capital expenditureOptimized rig-time efficiency (reduced NPT)Avoidance of costly trips to mitigate hanger damage, and premature settingElimination of external moving parts on the hanger assembly (reduced complexity)Reduced rig timeImproved reliability and fluid flowElimination of slip damage to supporting casing
Three case histories that compare the traditional and expandable liner hanger systems and verify the advantages stated above will be presented in the paper.
Optimization of Multiple Hydraulic Fractures for Open Hole Horizontal Wells by Numerical Modeling—Saudi Arabia Case Study
Authors: Lee Byung , Soleimani Arash , Dyer Steve , Bartko Kirk 
Published: October 2009

Abstract
Technological advances in the use of open hole completion with mechanical isolation have led to the ability to perform multiple fracturing applications in one continuous efficient operation. The new system allows effective hydraulic fracture placement by segmenting the lateral with mechanical isolation points using high-performance open hole packers. This application was used successfully in carbonate plays in Saudi Arabia where multiple acid fracture stimulation improved productivity from seven compartments and anisotropic reservoirs with high productivity contrasts.
Optimizing reserve development while maintaining maximum well productivity requires reliable evaluations of stimulation performance for field development planning. Reliable methods include the use of numerical reservoir simulation for the design, in combination with transient analysis techniques for the evaluation of the stimulation solution. In this study, a reservoir simulator incorporating a hydraulic fracture model within a subsurface geological software environment was used to optimize multiple fracturing in an open hole horizontal well in Saudi Arabia. The study investigated the impact of fracture number, location, spacing and geometry on reservoir drainage efficiency by using a sector model with a multisegmented horizontal wellbore model. Comparing various types of reservoirs shows how fracturing design can benefit from understanding the interaction between the reservoir and the horizontal wellbore intersected by hydraulically induced fractures.
An actual reservoir simulation model with geological and structural inputs was used to history match the performance of the fractured well. The same model was also used to interpret the transient pressure buildup data through their flow regimes.
Dynamic Characteristic Evaluation Methods of Stress Sensitive Abnormal High Pressure Gas Reservoir
Authors: Xiao Xiangjiao , Sun Hedong , Han YongXin , Yang JianPing 
Published: October 2009

Abstract
Gas reservoirs with abnormally high pressure have been encountered all over the world. Due to unusual stress environments, a potential impact to reservoir performance is the stress-sensitive permeability. The result of skin factor will be abnormally positive if we interpret the sensitive data using traditional welltesting analysis software. Interpretation of well testing and performance prediction is a major challenge.
This paper establishes a numerical well test model and develops a simulator by finite element method with consideration of stress sensitive permeability. LOG-LOG curves are obtained and their characteristics are analyzed. In the earlier period, the pressure response of sensitive reservoir is identical to that of the normal reservoir. In the latter period, the pressure reservoir reaches a semi-log straight line, but the value of the derivative curve is less than 0.5. The transitional period is controlled by sensitive permeability. For lower permeability module, the transitional period is longer. In the log-log plot, the distance between pressure and pressure derivative is larger than the normal reservoir. Permeability modulus will be obtained by log-log analysis.
An evaluation method of the effect of stress sensitivity on gas deliverability is presented using the concept of permeability modulus. By combining the LIT equation with the material balance equation, the performance prediction model is also established. The tank material balance equation for gas reservoirs has been written taking into account the effective compressibility of formation.
This paper presents an analysis of a flow after flow test in the Tarim abnormally, stress-sensitive gas reservoirs. The effect of stress-sensitive permeability on well test response is analyzed through numerical simulations. Permeability modulus
is about 0.01MPa−1; Skin is −1.48 ( traditional software is 60.8; qAOF decrease is 14%; period of stabilized production decrease is 5.5 a; and, degree of reserve recovery decrease is 6.8%. The interpretation results show that numerical well test analysis can accurately identify gas reservoir parameters and acidizing effectiveness and that the decrease degree of gas deliverability is different and depends on the ‘permeability modulus’ in the formation on which the gas well is located.
Enhanced Migration of Surface-Treated Nanoparticles in Sedimentary Rocks
Authors: Rodriguez Elena , Roberts Matthew R. , Yu Haiyang , Huh Chun , Bryant Steven L. 
Published: October 2009

AbstractEngineered nanoparticles have properties potentially useful for certain oil recovery processes and formation evaluation. Nanoparticles are small enough to pass through pore throats in typical reservoirs, but they nevertheless can be retained by the rock. The ability to predict retention with distance traveled, and to predict the effect of different surface treatments on retention, is essential for developing field applications of such particles.We inject concentrated (up to ~20 wt%) aqueous suspensions of surface-treated silica nanoparticles (D = 5 nm and 20 nm) into sedimentary rocks of different lithologies and permeabilities (10−14 to 10−12 m2). The particles generally undergo little ultimate retention, nearly all being eluted by a lengthy postflush. Nevertheless the nanoparticles do not propagate as classical non-retained solutes or particles (e.g. conservative tracers). Effluent nanoparticle concentration histories show breakthroughs later than 1 PV injected, plateau concentrations less than the injected value, and long tails. Longer elution times occur in samples with greater specific surface area. This set of observations is consistent with weak, reversible attachment of particles to pore walls. Such attachment is predicted by DLVO theory for very small particles when van der Waals attraction is the dominant force. This is the situation in our experiments, as the nanoparticles carry virtually no surface charge due to their surface coating.Compared to viscosities measured on bulk suspensions, the apparent viscosities of suspensions flowing through sedimentary rocks are significantly smaller. Bulk phase viscosities show little or no dependence on shear rate, and all experiments involved single-phase flow in water-wet samples. The simplest explanation for these observations is that a moderately thick layer (several hundred nm) of water depleted of particles exists at the pore walls. The mechanism for depletion of nanoparticles is presumably analogous to the mechanism for depletion of colloidal particles near rough confining surfaces.
Management and Operation of the Colorado School Field: An Interinstitutional Experience Between the Academy and the Industry
Authors: Zuly Calderón C. , Acevedo Duarte Leonardo , Saavedra Nestor Fernando 
Published: October 2009

Abstract
The aim of this paper is to describe the methodology underlying the Project "Colorado School-Field" (Colombia, South America), as well as the monitoring, assessing, and improvement indicators. In addition, it intends to highlight the academic and practical projects designed to improve the conditions of the field, within a medium and long terms. In 2006, this field was given from ECOPETROL S.A. (Colombian Petroleum Company) to the UIS to be operated as a school-field approach which means that it aims both academic and productive objectives and indicators. From the academic point of view, the School-Field involves comprehensively the UIS missionary duties with regard to teaching, research, and community impact. As far as the productive point of view, the activities of exploration, exploitation, and dispatch of crude and gas are reactivated, enhanced and they continuously consider the social responsibility with the community. The experience of the School-Field has been very beneficial for both institutions, as it has reinforced and qualified traditional relationships and agreements between ECOPETROL S.A. and the UIS. The Experience of "Colorado" has also inspired changes in the structure of subject courses in formal and informal education. Now it allows simultaneity of studies, investigation and professional work, convergence of strategic enterprising lines with research lines. In the same way the graduate program subjects must be support and consultancy to improve knowledge products of each posgrade level: research studies in master's programs and doctoral theses. On the other hand, the experience has been an inspiring model to similar projects at UIS such as, turning the Hospital Universitario Regional into a School-Field and supporting (Scientific and Technological Park-Guatigurá, with the presence of both institutions)) other School-Fields in the areas of alternative energy, biotechnology, agro-industry and materials.
The Porochemothermoelastic Coupled Solutions of Stress and Pressure With Applications to Wellbore Stability in Chemically Active Shale
Authors: Nguyen Vinh X. , Abousleiman Younane N. 
Published: October 2009

Abstract
Overcoming wellbore drilling instability in shale formations will always present one of the major challenges to drilling engineers. It is well established that the pore pressure differential between the drilling mud and the drilled formation is governed by the diffusion process which is a time-dependent phenomenon. On the other hand, shales are highly chemically active and they swell when brought in contact with aqueous drilling fluids. Chemical effects arise from imbalance in chemical potentials between the species in the formation pore fluid and wellbore drilling fluid. The transport phenomenon and the diffusive nature of the solvent and solutes in the solution affect the chemical potential, which in turn will modify the fluid pressure, e.g., via chemical osmosis, and eventually may compromise borehole stability. In addition, a temperature gradient between the drilling fluid and the formation will lead to not only induced thermal stresses but also transient thermo-induced pore pressure responses. Thus, the downhole chemical activity and temperature (mud/shale) is also time-dependent variables leading to time delayed failures in collapse or fracture gradient. This work addresses the coupled transient thermal and chemical effects on shale stability through analytical poroelastic inclined wellbore solution. The shale is modeled as an imperfect semi-permeable membrane which can allows partial transport of the solutes. In addition to chemical osmosis, both solute transport and thermal effects are taken into account to realistically model field condition. The solution is applicable to studying deep shale drilling using water based mud where thermal effect and chemical interaction are significant. The solution is helpful in the prediction and visualization of time-dependent alteration of near wellbore effective stress concentration as well as mud chemistry, density and temperature effects on the mudweight window. Specifically, borehole stability is investigated under various scenarios such as heating, cooling, high and low mud activity for simulated downhole condition as well as for a field case. Analyses reveal that cooling the wellbore and high mud activity can destabilize the near wellbore region and result in a narrower mudweight window. Ignoring the coupled solute transport and thermal effect may mislead the optimization of mud density, mud salinity or mud temperature to stabilize the wellbore over the course of time.
Closed-Loop Modeling of a Gulf of Mexico Reservoir Using Petrophysical Seismic Inversion
Authors: Liu Yuhong , Pelissier Michael , Barnes Martha , Tribe Julian , Uden Richard , Teer Joshua 
Published: October 2009

Abstract
We integrated pre-stack 3D seismic data with petrophysical, geological and production data to build a closed-loop reservoir model. All four data types were honored at the appropriate scale in their respective domains using a petrophysical seismic inversion workflow.
Starting from an initial fine-scale geocellular model of the subsurface built using state of the art methods, we forward modeled it into synthetic seismic data through user-defined petro-elastic models, that is, a set of rock physics relationships used to compute compressional and shear velocities, and density. Reflection coefficients were calculated and convolved with the wavelet to obtain the forward modeled seismic response. The modeled seismic data were compared with the measured seismic data and the discrepancy was gradually minimized through a simulated annealing optimization. Additional perturbation of the initial model was performed through comparing modeled production performance with the measured production data. This perturbation/updating process stops when the modeled performance matches the measured performance data.
The workflow was applied to a sand reservoir in the Gulf of Mexico. It is shown that the resulting product is a closed-loop reservoir model consistent with log, seismic and production data at their respective scales and domains. The workflow overcomes the many limitations of the linear "throw-over-the fence" approaches widely used in reservoir modeling. A potential expensive deep-water well was analyzed using precise delineation and evaluation of the reservoir and was found to have a high risk of failure so the well program was cancelled.