bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of a Nanocomposite Gel for Lost Circulation Treatment
Authors: Lécolier E. , Herzhaft B. , Rousseau L. , Néau L. , Quillien B. , Kieffer J. 
Published: December 2007

Abstract
The problems due to lost circulation events may represent a major source of expenses for drilling operators, even if their consequences do not have all the same level of gravity. Probably the most problematic situations are the naturally fractured formations where the operator may face total loss with no mud return in the annular.
The voids or large fractures encountered in this case are often far too large to be plugged with conventional Lost Circulation Material. For these severe losses, the failure of extreme solutions as cement injection may even lead to loss of the well. Recently, treatments based on cross-linked pills have shown their effectiveness to plug large fractures under downhole conditions of pressure and temperature.
This paper describes the research and development process to formulate a new cross-linked pill usable to control severe losses: this new pill is a nanocomposite organic/inorganic gel. Formulation strategy, laboratory procedures and experimental results will be described. The gelation time, the viscosity before setting, the gel strength formed and the dependence of these parameters with pressure, temperature and physico-chemical environment are characterized with specific experimental devices. Particular components of the formulation give excellent visco-elastic properties to the nanocomposite gel, enhancing the ability to sustain pressures peaks.
The typical final formulation, which is easily prepared on site (dry blend formulation) gives remarkable properties regarding pumping through drill pipes, adjustment of setting time and especially strength of the lost zone sealing.
Field Validation of Acidizing Wormhole Models
Authors: Glasbergen G. , van Batenburg D. , van Domelen M. , Gdanski R. 
Published: December 2007

Abstract
In matrix acidizing of carbonate reservoirs, the generation of wormholes is a major key to success. Numerous papers have been written that describe the formation and propagation of such wormholes. Generally, these models have been based on sound chemistry and physics. Some of the models have been validated against laboratory experiments that are generally conducted in a linear geometry. However, in order to use the models in the design of matrix acid stimulation treatments, the models need to be validated under radial flow conditions that dominate field treatments.
Radial flow, competing wormholes, permeability contrasts, and reservoir height are example parameters that cannot easily be validated in laboratory experiments. Scaling of the models to field conditions might be required. Two types of models have been written for aiding in treatment designs. One model, called a linear-type model, is fully consistent with the decades of linear flow tests conducted in the laboratory. The second model, called a symmetry model, is exceedingly difficult to validate in the laboratory. This paper evaluates both models against treating pressure responses from field treatments.
A matrix treatment simulator was used that includes such effects as multiple formation layers with independent formation parameters and allows for modeling zonal coverage. The formation parameters include permeability, porosity, mineralogy, acid reactivity, skin damage, and permeability contrast. The well parameters include height of the layers, wellbore tubulars, friction pressures, etc. This simulator was an ideal framework for evaluating the two acidizing wormhole models. This paper demonstrates the key issues related to the interaction between the wormhole models and zonal coverage.
First Implementation of Hydrajet Fracture Acidizing in Deepwater Offshore Brazil Fields
Authors: Rodrigues V. F. , Neumann L. F. , Rosolen M. A. , Fernandes P. D. , Lima C. , Surjaatmadja J. B. , Gonzalez C. M. , Carneiro F. 
Published: December 2007

Abstract
The placement of multiple fractures in horizontal, deviated wells is usually more difficult than placement in vertical wells. When completed with uncemented preperforated liners, such treatments become much more difficult and often are ineffective using conventional stimulation methods. When found in offshore locations, these wells present even more problems.
Recently, in the shallow waters offshore Brazil, a relatively new hydrajetting technology was used with great success. However, additional complications arose when hydrajet fracturing was elected to stimulate a subsea well. This process requires dual high-pressure connections to the wellbore, including placement of a tubing string inside the full length of the well. Maintaining the hydrajet tool in position during each fracturing stage was a big issue in a floating rig. The need to pull tubing between stages of the stimulation process also poses a challenge.
Because this operation occurred in a subsea well, it was the first such application ever attempted worldwide. Extremely detailed planning was essential to the ultimate success of the operation. This paper discusses the rigorous planning involved in implementing multistage hydrajet fracture acidizing in a subsea well offshore Brazil. During the operation, all challenges, mechanical or otherwise, were meticulously scrutinized, including the proper operation of the stimulation vessel and riser motion. This paper also presents post-treatment production results evaluated and compared to other stimulation attempts in offshore horizontal completions in the area.
Accurate Measurement of the Hydrogen Sulfide Content in Formation Fluid Samples—Case Studies
Authors: Elshahawi H. , Hashem M. 
Published: December 2007

Abstract
The Hydrogen Sulfide (H2S) content of subsurface hydrocarbon reservoirs has a profound impact on completion, surface production, and process design. The H2S content of crude oil directly impacts the sale value of the produced hydrocarbons, while the H2S content of produced water can result in significant production problems, which can lead to detrimental effects on hydrocarbon transport and sales specifications.
In theory, the H2S content of reservoir fluids can be determined from samples collected by wireline formation tester tools. In practice, however, measurement is complicated by the partial-to-total loss of the gas by absorption/adsorption onto the metal components of the downhole tool, storage bottles, and transfer/analysis system, particularly those made from iron. H2S readily forms non-volatile and insoluble metal sulphides by reaction with many other metals and metal oxides, and analysis of the fluid samples can therefore underestimate the true H2S content. Therefore, many practical challenges must be overcome to accurately determine H2S levels in formation tester samples. These include metallurgical design considerations, sampling environment and system selection as well as the timing and type of H2S analyses.
This paper details our successes in accurately measuring both high and low concentrations of H2S in downhole formation tester samples. It describes an integrated workflow by which ultra low H2S concentrations can be captured and preserved in formation tester samples until the tool is brought back to surface where the samples can be analyzed. This workflow includes a number of modifications to some commercial formation tester tools and sample chambers to ensure that the bulk of the H2S does not get absorbed by the time the tool arrives to the surface. Downhole measurements made close to the fluid entry into the sampling tool are used to cross check and verify the surface measurements. Finally, on surface, a number of techniques are used to measure H2S concentration in the sample bottles as soon as practical after the formation tester tool is brought to the surface. The paper demonstrates, through a number of case studies, that by following this comprehensive workflow, it is possible to capture and analyze hydrocarbon samples with minimal loss of H2S, regardless of the levels of H2S being measured.
OBM's Filtrate Damaging Effect on Gas Wells
Authors: Emiliani C. N. , Ripa G. , Sportelli M. , Cobianco S. , Del Gaudio L. 
Published: December 2007

Abstract
Formation damage of gas wells can occur during drilling and completion operations causing a first sensible impairment of the potential productivity.
When drilling gas wells in low permeability reservoir with strongly inter-layered formation, as in the Adriatic Sea, oil based muds (OBM) are often used in order to minimize differential sticking and clay destabilization problems. The OBM's filtrate generates through the mud filter cake, when exposed to completion brine may form emulsion droplets that are not easily and fully removed during production, causing a permanent damage to rock permeability.
This paper presents the study carried out to understand the damage mechanism which gas wells undergo when drilled with OBMs and the results obtained in engineering a system able to enhance production recovery for new wells.
Bulk experiments and coreflood tests have been performed both to investigate the interaction effect of OBM's filtrate with high density water-based pill and to assess its impact on the well deliverability. In bulk conditions, viscosity and microscopy characterization of tight w/o emulsions (up to 99:1 W/O) highlighted that low shear rate and very low emulsifier concentration in the mud filtrate promote very viscous and thermally stable emulsion. Besides linear coreflood tests proved dramatic permeability impairment when flushing CaCl2 brine through a mud filtrate saturated core, confirming the formation of a blocking phase in the porous media.
A prevention system has been engineered as a peculiar surfactant to be added to completion brine, able to prevent emulsions from forming instead of simply breaking it up.
Surfactant selection guidelines have been provided as result of various additives screening being focused on the main characteristics affecting the surfactant efficiency, like HLB and solubility in brine.
Calculation of Productivity of a Gas-Condensate Well: Application of Skin With Rate Dependent Pseudopressure
Authors: Jamiolahmady M. , Danesh A. , Rezaei A. , Ataei R. , Sohrabi M. 
Published: December 2007

Abstract
The most crucial region affecting well productivity is the perforated region. An accurate determination of perforation performance, required in the optimum design and well productivity estimation, could be made by fine grid simulation, but it would be costly with many technical limitations. The alternative practical approach is the use of a skin factor in open hole calculations resulting in the same flow performance as that of the perforated well. However most of the skin calculations done today are based on single-phase flow conditions.
In this work, we have developed a method to determine the effect of perforation on gas condensate well productivity by defining a skin factor to be used in the pseudo pressure application. The main problem is that pseudo pressure in such systems is a function of velocity and the conventional skin factor, which is calculated for a perforated well, cannot be used directly in open hole calculations. This is due to the fact that the gas and condensate relative permeability (kr) can increase significantly by increasing the flow rate, contrary to the common understanding. This effect, known as positive coupling, complicates the flow of gas and condensate near the wellbore even further when it competes with inertial losses at higher velocities typical of those around perforation tips.
The above complications, which require information on velocity-location in the perforation region, have been tackled by proposing new techniques with an emphasis on their practicality. Sensitivity studies, comparing the results of developed methods with those using finite element methods, indicated the reliability of the proposed techniques. The methods can be used to estimate variations of skin due to long-term condensate banking and the need for any intervention and remedial action.
Analysis of Production Enhancement Related to Optimization of Propped Hydraulic Fracturing in Gazprom's Yamburskoe Arctic Gas Condensate Field, Russia
Authors: Butula K. K. , Maniere J. , Shandrygin A. , Rudenko D. , Zynchenko I. A. 
Published: December 2007

Abstract
Optimized hydraulic propped fracturing has proven to be the key to success for many operating companies in the West Siberian oil fields. The application of hydraulic propped fracturing stimulation in medium-permeability gas condensate formations was once considered uncertain because of mixed results in the past.
The particular conditions in a severe arctic and permafrost environment, however, required a range of specific completion and stimulation techniques for the Neocomian reservoir, including hydraulic fracturing.
The changes in fracturing treatment design in this gas condensate reservoir were made in adherence to an integrated project management approach, using forward modeling and reservoir and wellbore production simulation to mostly negate retrograde condensate effects.
The paper provides a comprehensive analysis of the work that was done on these gas condensate wells, focusing on the post-fracturing production analysis including production effects with time, factors affecting productivity, and post-fracturing production modeling.
Unprecedented productivity results, when compared to peer wells in the Yamburgskoe field, were realized from the treatments performed. The nine-well case history dataset presented in the paper confirms the effect of using this comprehensive approach to propped hydraulic fracture treatments in a Russian gas condensate reservoir.
Integrated Management of the Safe-Operating Window: It's More Than Just Density
Authors: Hemphill T. 
Published: December 2007

Abstract
The drilling of challenging wells, especially those in deepwater, high pressure / high temperature (HPHT), and extended reach environments, is often characterized by a narrow safe operating window between formation pore pressure and fracture gradient.Overstepping the window bounds can lead to unwanted incidents of well control and/or lost circulation. In the drilling literature, the management of the safe operating window while drilling has heretofore focused on the optimization of circulating pressure drop, hole cleaning, and rate of penetration, with little consideration of wellbore geomechanics.
Maintenance of wellbore stability (WBS) while drilling is critical to the success of today's challenging wells, yet applications of such modeling have largely centered only on predictions of surface drilling fluid density requirements.In this paper, an integrated approach using the following items is taken to show the utility of incorporating drilling fluid hydraulics and barite sag potential in the wellbore construction process.The use of this technology can help the drilling industry avoid unwanted surprises that can lead to unstable wellbores while drilling in today's technically-challenging environments.
Use of Streamlines and Quality Map in the Optimization of Production Strategy of Mature Oil Fields
Authors: da Silva Guimarães M. S. , Schiozer D. J. , Maschio C. 
Published: December 2007

Proposal
Developed or mature oil fields can be considered as sets of reservoir that present production strategy already established and implemented, generally presenting production in the decline phase. Changes in geologic characterization or economic or technologic scenarios can demand changes of the production strategy, requiring the application of an optimization process. The optimization process of developed or mature oil fields presents different characteristics from fields in beginning of production, mainly regarding flexibility for changes. The existence of production data allows the improvement of the geological characterization of the reservoir and the reduction of the uncertainties allowing a more detailed optimization procedure.
The objective of this work is to develop an automated optimization methodology combining the utilization of three important tools: traditional simulation, streamline simulation and quality map. The traditional simulation is used to give reliability to the process. The streamline simulation and quality map are supporting tools employed to give more reliability and to bring up insights about the optimization process and speedup to the process, mainly in the control of water injection and production and in the possible allocation of news wells.
The proposed methodology had been applied to an offshore field with water injection. The results show that the efficient control of fluid flow and the better understanding of the overall process provided by the supporting tools allow the determination of production strategy that improved the economic recovery of the developed or mature field studied. Additionally, the developed methodology allows the definition and the organization of the possible changes, making feasible the automation of part the process.
Determination of Gas Trapping With Foam Using X-Ray CT and Effluent Analysis
Authors: Nguyen Q. P. , Rossen W. R. , Zitha P. L. J. , Currie P. K. 
Published: December 2007

Abstract
Foam is used worldwide to improve acid placement in matrix acid treatments and redirect gas flow in improved oil recovery. Gas trapping is a major factor in foam processes: it affects foam mobility and controls diversion of liquids such as acid injected after foam. Most previous studies of gas trapping have relied on fitting effluent gas tracer profiles to a one-dimensional (1D) model for transport of tracer in the presence of trapped gas, including mass transfer between flowing and trapped gas. We present new experiments where X-ray computed tomography (CT) directly determines the gas tracer distribution in situ. The key is using a gas-phase tracer (Xe) visible in CT. The CT images show clearly that the standard 1D model used to interpret tracer effluent profiles is incorrect in its assumptions. For the first time here we compare the in situ tracer distribution from CT images to the trapped-gas saturation estimated from fitting the effluent tracer profile to the 1D model, augmented here for the effect of pressure variation along the core. The effluent profile is determined indirectly from the CT images in two ways: by imaging the tracer concentration in the flow line downstream of the core, and using a mass balance on tracer in the core. Estimates of trapped-gas fraction using the 1D model vary by as much as 0.2 among reasonable fits to the effluent data, and flowing gas fraction by as much as a factor of 1.5 or 2. The experiments span a range of foam qualities and injection rates in Bentheim sandstone. Model-derived estimates of trapped-gas fraction decrease with increasing gas injection rate and increase weakly with increasing liquid injection rate in our experiments. The CT images show a shift to a wider variety of fluctuating flow paths as liquid or gas injection rate increases.
A Methodology for Drilling Through Shales in Environments with Narrow Mud Weight Window (NMWW)
Authors: Araújo E. M. P. , da Fontoura S. A. B. , Pastor J. A. S. C. 
Published: December 2007

Abstract
Shales, in general, are the major source of wellbore stability problems. A particularly critical drilling scenario is the one that combines deepwater and shallow overburden, typical of ultra deepwater fields in Brazil. This scenario is characterized by high pore fluid pressure, low effective stresses, low fracturing gradients and narrow mud weight windows (NMWW). In order to drill under these conditions, it is necessary to establish means to increase the mud weight window. In this paper, we demonstrate that it is possible to increase the mud weight window by changing conveniently both drilling fluid pressure and salt concentration. A robust computational procedure is established in order to evaluate the size of the plastic zone around the wellbore as a function of the drilling fluid pressure and salt concentration and time of rock exposition to the drilling fluid. The final width of the mud weight window will depend upon the size of the failed zone that can be tolerated by the design.
Cost-Effective Drilling Optimization Technologies in Campos Basin
Authors: Paes P. , Aragão A. , Chen D. C-K. 
Published: December 2007

Abstract
This paper discusses a specially tailored cost-effective optimization program for drilling the Campos Basin and adjacent areas. Available well data show that the majority of the drilling problems are related to hydraulics issues such as lost circulation, kick, etc., and to equipment failure. Thus, with new and planned wells, the emphasis has been focused on the use of PWD sensors to closely monitor the ECD. Other important technologies used include vibration sensors and formation pressure evaluation, and related phenomena. Over the past three years, 62 drilling optimization operations were completed in Brazil, particularly in the Campos Basin area. They have substantially reduced the drilling cost, reduced non-productive time (NPT), and increased drilling efficiency. Most importantly, drilling optimization operations have added very little to the cost of the routine MWD services that had been in use.
Pulse-Rotating Jet System Acidizing in a Campos Basin Deepwater Horizontal Gravel Packed Injection Well
Authors: Pereira A. Z. I. , Calderon A. , Chagas C. M. , de Camargo C. , da Motta E. P. , de Miranda A. A. , de Santana J. P. F. , Acosta M. , Zacarias O. G. , Farias R. L. , Almeida V. 
Published: December 2007

Abstract
In most of its deepwater Campos Basin oilfields, Petrobras' strategy has been to develop the water flooding systems using horizontal gravel packed wells. Both drilling and gravel pack operations are only possible through the presence of a filter cake, formed on the formation face during the drilling process. Nevertheless, that film becomes an impediment to injection and must be removed to obtain good injectivity.
Special tools were developed to perform acidizing jobs, in one trip, just after the gravel packing operation. However, there were few alternatives to correct any eventual acidizing lack of performance, besides using coiled tubing and straddle packers, something that usually takes too much time.
Recently, a pulse-rotating jet tool system was applied in a well that could not be treated after the gravel pack operation. The tre atment, which is simpler and faster than those carried out with straddle packers, was performed in two stages: the first, using just HCl, and the last one, using mud acid.
The subsequent formation test performed after the HCl treatment showed a high skin value and an unacceptable injectivity index, due the need to keep the reservoir pressure above the bubble point. Even so, the test data in association with reservoir simulation, according with the field geology, showed that there was fluid injection throughout the entire horizontal section. Therefore, it was decided to perform a mud acid treatment, again, using the pulse-rotating jet tool system.
This time, a second formation test indicated an excellent injectivity index, confirming the pulse-rotating jet tool system effectiveness and creating perspectives for the application of this technique in future operations.
This paper will describe the technique, job details and the results obtained for this particular operation, which may be applied in other similar offshore environments.