bluuebunny/crossref_metadata_2025_split huggingface dataset:
Openhole Gravel Packing With Exposed Shales: Waterpack Case Histories From Underground Gas Storage Wells in Italy
Authors: Zanchi A. , Ripa G. , Colombo M. , Ferrara G. , Belleggia E. , Barbedo R. , Illuminati R. , Rezende J. , Shenoy S. 
Published: May 2009

Abstract
One of the major challenges in underground gas storage wells in Italy is to maximize the sand layers exposure by drilling slanted or sub-horizontal wells through several shale bodies to obtain high gas rate performances during the production and the injection cycles. This challenge has a significant effect in selection of the completion technique in these wells, which require an effective and reliable sand control for long term, and open-hole and large tubular size to minimize friction losses.
Until now, standard open-hole gravel packing was the common completion in a single sand body, however in presence of shales open-hole expandable screens with annular barriers and blanks between each section of sand is the only completion option, except in fine sand environment.
In this paper, we present experimental data of shale stabilizer treated-brine and three open-hole gravel packing case histories from one UGS field in Italy. In the three case studies the wells were gravel packed using shale stabilizer treated-brine in open-hole made up of sand layers containing shale, without negative impact on completion time.
A Self-Mitigating Sand Control Screen
Authors: Yeh C. S. , Moffett T. J. , Petrie D. H. , Entchev P. B. , Long T. A. , Clingman S. R. , Dale B. A. , Harrison L. E. , Barry M. D. , Hecker M. T. , Howell D. A. 
Published: May 2009

Abstract
Sand screens often serve as the primary barrier to sand production from weakly consolidated reservoirs. Screen technology has improved significantly in the areas of sand retention, mechanical integrity, and quality control. As future field developments trend towards more hostile environments, requiring fewer wells at higher rates, the overall reliability and longevity of sand screens will be increasingly more important in this high cost environment.
This paper introduces a self-mitigating sand screen technology, MazeFlo™, that uses redundant sand control and compartment baffles to improve reliability and longevity for sand-prone well production. The technology self-mitigates downhole screen damage by isolating the effects of any mechanical failure of the screen to a local compartment, while allowing continued hydrocarbon flow through the undamaged sections. The compartment maze is comprised of baffles and tortuous flow paths that balance the incoming flow momentum from the outer screen. This flow redistribution mitigates risk of inner screen failure, while posing no additional plugging risk over conventional screens.
These self-mitigating screens reduce the frequency of sand-related workovers, extend well production, and increase recovery. Due to its simplicity and unique passive control capability, self-mitigating sand screens will expand the applicability of less complex and more cost effective standalone screen completions. Self-mitigating screens can also be easily combined with other emerging technologies such as zonal isolation and inflow control devices.
Modelling the Placement of Scale Squeeze Treatments in Heterogeneous Formations with Pressurised Layers
Authors: Vazquez O. , Mackay E. J. , Sorbie K. S. 
Published: May 2009

Abstract
The most common method for preventing scale formation is by applying scale inhibitor squeeze treatments. In this process, a scale inhibitor solution is injected down a producer well and into the near wellbore formation. Generally, reservoir formations consist of a number of layers or zones of different permeability which may or may not be in pressure communication. When the zones are non-communicating within the reservoir, they are often at different pressures. When this is the case, then this can have a strong influence on the flow and placement of any injected fluids. Indeed, it can dominate the dynamics of the placement process and can also cause wellbore crossflow during the shut-in period following the squeeze treatment. In order to design a successful squeeze treatment, it is very important to know where the injected fluid goes; i.e. where the slug of scale inhibitor is placed in the formation. Therefore, our squeeze design and prediction models must incorporate these layer pressure effects along with the other models for the scale inhibitor transport and retention mechanisms.
In this paper, we develop the analytical expressions for calculating the flow partition in radial layered formations, where the layers are non-communicating. This is not in itself original and these equations are "well known". However, we have incorporated them into our multi-layer, two phase scale squeeze design software (SQUEEZE VI) to simulate situations where layers are at different pressures. We demonstrate that this has an important effect on the scale inhibitor slug placement in a heterogeneous system and it drives crossflow between layers at production or injection stages. Furthermore, we go on to show what the consequences of these placement effects on the squeeze lifetime are. We also present a wide sensitivity study of this effect showing how a number of ancillary parameters affect the squeeze lifetime e.g. the magnitude of the differential pressure between layers, the permeability contrast, the retention mechanism. Finally, we give some general field guidelines for various specific situations where formation zone pressures are not equal in terms of squeeze applications.
Impact of Mutual Solvent Preflush on Scale Squeeze Treatments: Extended Squeeze Lifetime and Improved Well Clean-up Time
Authors: Vazquez O. , Mackay E. , Sorbie K. , Jordan M. 
Published: May 2009

Abstract
The most common method for preventing scale formation is by applying a scale inhibitor squeeze treatment. In this process, a scale inhibitor solution is injected down a producer well into the near wellbore formation. Commonly, scale treatments comprise the following stages: preflush, main scale inhibitor pill, overflush tubing displacement and shut-in, followed by back-production of the well. For some years the industry has applied mutual solvent chemicals in the preflush stage of such treatments to (i) avoid emulsion formation or water blocking, thus avoiding slow well clean-up, and also (ii) for enhancing adsorption of the scale inhibitor onto the formation rock.
This paper discusses the effect of a mutual solvent preflush on scale inhibitor squeeze lifetime and also on well clean up time. It builds on a previous publication that introduced a recent model to simulate the impact of a surfactant on improved inhibitor retention, which used data derived from laboratory experiments. The focus of this paper will be to consider the impact of the mutual solvent on well clean up time and the model is used to demonstrate the effect of a mutual solvent in quickly bringing wells back to full oil production. A field example is presented for a deepwater field in West Africa where intervention costs are high and any negative impact of squeeze treatments can have a significant associated deferred oil cost.
A scale inhibitor squeeze design in which a mutual solvent is deployed in the preflush should account for the following phenomena: mutual solvent propagation, diminishing mutual solvent efficiency due to interaction with the fluid phases, impact of the mutual solvent on scale inhibitor retention due to increased rock surface area available for adsorption, and impact of mutual solvent on saturation dependent relative permeability functions and phase mobilities. These aspects are discussed in the paper, and the model is used to demonstrate their impact on a squeeze treatment. Particular attention is paid to the reservoir wettability, and the importance of the shape of the relative permeability curves in determining the clean up time for a well, and the benefit that a mutual solvent may bring in overcoming slow clean up times.
The model is then used to demonstrate how the preflush stage of given specific field squeeze designs may be adapted to ensure optimum efficiency in terms of chemical usage, minimised deferred oil production and extended squeeze life.
Fines Migration in a High Temperature Gas Reservoir – Laboratory Simulation and Implications for Completion Design
Authors: Byrne Michael , Waggoner Steve 
Published: May 2009

Abstract
Fines migration is widespread in oil and gas reservoirs but often misunderstood. It can be difficult to identify and even more difficult to predict and interpret. The phenomenon, which can be considered a "natural" damage mechanism, involves the movement of rock particles through and within the pore matrix of that rock.
This paper presents a case history of fines migration investigation in a reservoir in the Malay basin in South East Asia. High temperature core flood tests and equivalent ambient condition core flood tests were used to evaluate the potential for fines movement in the producing gas phase. This paper outlines the laboratory test procedures, the results and discusses the implications. A comparison is made between the different laboratory techniques and recommendations made for similar reservoir challenges. The importance of scaling down near wellbore flow rates from field conditions to make them relevant in laboratory conditions was considered. Thus the test results are now able to be scaled up and are more relevant. This paper will also show significant differences in permeability reduction and fines movement between ambient conditions and high temperature reservoir conditions. The testing at high temperature reservoir conditions has not been a common practice and no published work has been found within SPE on this topic.
Once fines movement is predicted, the next challenge is to evaluate its potential impact on well performance. The implications for the specific reservoir and particularly for well design and completion options are discussed. Sand control issues as well as the potential impact on water injection or disposal wells are considered.
This paper presents clear evidence for fines migration in the production phase of a high temperature gas reservoir. Laboratory testing and subsequent analysis of tested samples demonstrate the nature of the fines and the process of permeability change. A process for identification of potential fines migration problems in gas reservoirs is proposed. The implications of fines migration in such a reservoir are discussed and potential mitigation is considered together with well completion design implications.
Design and Application of Invert Emulsion Drilling and Aqueous Completion Fluids for Long Horizontal Multilateral Wells
Authors: Hutton Alistair , Vickers Stephen , Davidson Marcus , Wharton Jon , Hatch Andy , Simmonds Roger , Brankling David 
Published: May 2009

Abstract
The Rita gas field was the first dual lateral well aimed at carboniferous reservoirs drilled in the UK Southern North Sea. This method enabled both the East and West fault segments of the field to be produced from the same upper well bore, thus reducing drilling costs and improving field economics. An invert emulsion drilling fluid was chosen for this field application due to the risk of shale instability over the long horizontal sections of each wellbore.
The West segment was drilled and suspended with a whipstock placed above the sand screen completion. The positioning of this whipstock would not allow for re-entry, making remediation of the West lateral impractical. A remediation treatment for this leg was required as the planned suspension fluid was an invert emulsion system that would be in contact with the completion screens and reservoir for more than a month whilst the East leg was drilled and completed. The chosen suspension fluid in the East leg removed the requirement for remediation with enhanced well productivity. This paper describes the design and testing of the reservoir drilling and suspension/completion fluids that were used on this multi-lateral project to minimise drilling time and maximise productivity.
Cases History Studies of Production Enhancement in Cased Hole Wells Using Microemulsion Fluids
Authors: Quintero Lirio , Jones Thomas A. , Clark David E. , Schwertner David 
Published: May 2009

Abstract
A high percentage of oil and gas wells drilled throughout the world have been completed using perforated casing. In older cased-hole wells, the production pressure may be depleted and/or hydrocarbon flow may be impeded by various damaging mechanisms such as in-situ emulsions, water blockage, solids migration, asphaltenes and paraffin deposition. In newer wells, drilled using oil- or synthetic-based drilling fluids, emulsion blockage may cause near-wellbore damage when the filtrate or whole mud interacts with formation fluids or completion brine.
Properties of microemulsions, such as high oil solubilization rates and ultra-low interfacial tension make this type of fluid ideal for addressing all of the described problems in old and new cased-hole wells.
This paper presents development procedures and case history results from numerous field applications that demonstrate the efficiency to reduce skin damage and improve productivity by using a single-phase microemulsion fluid specially designed for cased-hole wells.
Field Development and Productivity Improvement in Offshore Mexico: An Engineering and Laboratory Synergistic Approach to Carbonate Fracture Acidizing
Authors: Inda Antonio , Steffani Octavio , Soriano Eduardo , Robles Fernando 
Published: May 2009

Abstract
The marine light crude (CLM) project in offshore Mexico is a group of 12 oil fields located 75 km off the coast of southern Mexico (Jurassic and Cretaceous period). The fields have been under development since 2003, are high-temperature (160°C or &gt;300°F) carbonate formations producing gas and condensate with permeability that ranges from 1 to 6 mD, and are naturally fractured. These fields were experiencing considerable drawdown, which slowed down the return on investment and, in one case, could have potentially led to well abandonment. Established dogma dictates that carbonate formations in Mexico are best treated by matrix stimulation rather than fracture-stimulation techniques. The two case studies discussed in this paper demonstrate the effective implementation of a production-optimization design and execution methodology that has translated into productivity increase. The design resulted in up to 80% removal of the pressure drop experienced in the formation face, accomplished by establishing a linear flow path, bypassing the formation damage. After treatment, a production increase of 50% more than conventional treatments is the best proof of concept, validating the synergistic approach, entailing data collection and analysis, field and laboratory work, and engineering design and simulation. The selection of appropriate candidates was performed by analyzing productivity data (drillstem testing), which indicated a skin factor of zero but, nevertheless, a remnant and considerable pressure drop caused by the formation's low permeability. Fluid optimization and placement techniques were combined with core studies and rock mechanics in the job design. Candidate wells for acid fracturing had permeability of 1 to 20 mD, while matrix stimulation candidates had 20 to 50 mD, and 50-m etched fractures appear to have provided optimum results. The methodology signifies less risk of incurring damage caused by condensate formation in the formation. As a result, fracture acidizing in Mexico's offshore fields is a completely viable alternative to production improvement.
Flow Performance Of Perforation Tunnels Created With Shaped Charges Using Reactive Liner Technology
Authors: Atwood D. C. , Yang W. , Grove B. M. , Behrmann L. A. 
Published: May 2009

Abstract
We report on a series of laboratory flow experiments comparing the productivity of perforations created with reactive liner charges against those created with conventional liner charges. Three of the tests involved shots into an outcrop carbonate rock called Indiana Limestone. Three of the tests involved shots into an outcrop sandstone rock called Berea Sandstone. Four different charge types were tested, including one standard (conventional) charge and three different designs of reactive liner charges. Among all charges, the only difference of note was the design and composition of the liner. All other charge design parameters were kept constant.
For both rock types, the reactive liner charges produced perforations with lower productivity than the baseline conventional charge. The reduction in the normalized Productivity Ratio (PRn) ranged from 29% to 66%. Furthermore, the reactive liner charges produced characteristic "dynamic overbalance" conditions in the wellbore, in a system configuration which produced dynamic underbalance for the conventional charge. We conclude that the reactive liner charges tested are detrimental to productivity in naturally perforated completions.
Water Induced Formation Damage in Unconventional Gas Reservoirs
Authors: Lakatos István , Bódi Tibor , Lakatos-Szabó Julianna 
Published: May 2009

Abstract
In the 21st century, the global gas demand will be met only by extensive production of unconventional gas (shale and tight sand gas, deep gas, basin concentrated gas accumulation, etc.). All such gas-bearing formations are characterized, however, by extremely low, usually micro Darcy range permeability. Unfortunately, the operators of such reservoirs face with difficulties when routine drilling, well completion, fracturing, and production technologies are used. One source of the problems can be traced back to use of water-base fluids. Therefore, the laboratory studies aimed at elucidating the reasons why water-based fluids are harmful and seriously jeopardize the gas production from such reservoirs.
The water induced formation damage is illustrated in a porous media having 0.001–0.1 mD permeability and obtained from a tight sand gas formation. Its pore structure was analyzed by HP Hg porosimetry and the wettability was determined by digital image analysis. The spontaneous imbibition was tested with standard method. Surface tension of water was determined by automatic ring method. The critical Pc needed to mobilize water was calculated as a function of pore size distribution.
Using the relevant data (pore size distribution, wettability and surface tension) the calculated Pc was in range of 40–75 bar for cores obtained from medium depth (3600 m); meanwhile it was extremely high, 500–600 bar for cores derived from deeper layers (&gt;6000 m). Based on these data it was concluded that the native water saturation should be high (&gt;70%) and immobile in similar formations and because of the high imbibition rate the water behaves as a potential blocking phase in the cores. The mentioned factors seriously influence both the resource/reserve assessment and the production efficiency. Since the water may induce formation damage hard to control, application of water free fluids is recommended in any phase of field operation at unconventional gas reservoirs.
A Comprehensive Methodology to Analyze the Impact of the Sand Control Technique on the Efficiency of an Horizontal Well
Authors: Ferreira M. V. D. , Folsta M. G. , Vianna A. M. , Miura K. , Calderon A. , Martins A. L. 
Published: May 2009

Abstract
Sand production in unconsolidated formations has brought heavy injury for the oil and gas industry around the world. Million dollars have been invested in sand control techniques. Among the several sand control systems existing, Open Hole Gravel Pack (OHGP) is the one adopted for horizontal well completions in the offshore Brazilian fields. With the experience in the development of such fields, some assets start to consider the adoption of less conservative sand control strategies, such as the use of stand alone premium screens (SAS). The present work proposes a methodology for evaluating the impact of the sand control technique in the productivity or injectivity of a horizontal well. Several parameters, such as damage rate (DR) and productivity or injectivity index per horizontal effective length (PI/Lef) were used to compare similar wells equipped with different sand control techniques. The main goal of the study is to address the following questions:
There is any formation damage due to the gravel pack during production lifetime of a well? The wells equipped with stand alone screen exhibit formation damage? Wells equipped with OHGP have the same performance when compared with wells equipped with SAS? Stand alone completion is a good alternative path for multilateral and extend reach wells?
Horizontal Open Hole Gravel Pack Placement Requirements in Selective Completion Projects
Authors: Loureiro B. V. , de Magalhães J. V. M. , Ferreira M. V. D. , Calderon A. , Martins A. L. , dos Santos F. P. 
Published: May 2009

Abstract
Horizontal Open Hole Gravel Pack (HOHGP) is the conventional sand control technique for offshore non consolidated reservoirs in Brazil. Gravel pack placement requirements include the design of pumping pressures inside the operational window formed by the minimum pump rate to avoid premature rat hole screen-out and maximum pump rate to avoid formation fracture. Some special projects require additional equipment to provide selective completion – External casing packers (ECP) installed at different positions along the production screen aim the isolation of certain reservoir zones. In these cases, gravel pack placement present an additional constraint – operational pump rates should be high enough to avoid alpha wave sedimentation around the packers to assure sealing after the packer inflation process. Traditionally, design criteria consider a minimum critical velocity to avoid sand deposition.
The specification of minimum flow for cleaning the ECP, and prevent the deposition of sand in the annular space can be obtained from different criteria. Two methods are proposed to analyze the problem: a constant velocity and a constant shear stress approach. The major contribution includes computational fluid dynamic simulation (CFD) of the 3D flow around the packer, using a finite volume method. The methodology based on the estimation of the local shear stresses at the interfaces, suggests less conservative numbers which allows effective gravel pack placement in selective completion projects for narrow operational windows.
Microemulsion Technology for Improved Fluid Recovery and Enhanced Core Permeability to Gas
Authors: Zelenev Andrei S. , Ellena Linda B. 
Published: May 2009

Abstract
In recent years the use of microemulsions for remediating damaged wells has been a success story. Microemulsions are unique, thermodynamically stable, optically clear single phase blends of water, biodegradable water-immiscible solvent, co-solvent, and specially designed surfactant. Engineered mixtures of these ingredients can form stable microemulsions over a rather broad range of water to solvent to surfactant ratios. Are all microemulsions equally effective in their performance? The main focus of our study was to prepare various microemulsions and to examine a link between microemulsion composition and their performance.
Microemulsion treatments have proved to be effective for improving gas production rates by increasing formation permeability and for enhancing fluid recovery from sand-packed and shale-packed columns. For achieving maximum benefits, microemulsion formulations have to be properly designed. Both microemulsion composition and dose are important for their end performance. The effectiveness of a particular microemulsion may vary depending on the application, and may be sensitive to the type of formation.