bluuebunny/crossref_metadata_2025_split huggingface dataset:
A 3D Network Model of Rock Permeability Impairment Due to Suspended Particles in Injection Water
Authors: Siqueira A. G. , Bonet E. J. , Shecaira F. S. 
Published: December 2007

Abstract
A 3-D network model is used to simulate the impairment of porous medium permeability during the flow of water with suspended particles.
Digitized 2-D images of the porous systems are obtained by petrographic image analysis of rock thin sections. Geostatistical procedures are applied to construct 3-D virtual realizations of the medium. The pore body and throat sizes distributions of the virtual medium and its connectivity, expressed by the average coordination number, are determined. Alternatively, these characteristics are obtained by using capillary driven porosimetry data and empirical correlations. A regular cubic network of sites (pore bodies) and bonds (pore throats) that reproduces these characteristics is structured.
Network absolute permeability can be calculated by solving a system of linear mass balance equations for the sites, along with equations of hydraulic conductivity for the bonds. Realistic permeability estimates are obtained.
Motion and contingent capture of injected particles inside the medium are simulated. Both physicochemical interception and size exclusion mechanisms of particle retention are modeled, the former with the aid of two empirical parameters. Particle capture modifies the flow in the network, that is recurrently calculated, resulting in permeability decline as more particles are retained.
Network simulated data and their comparison with those obtained in laboratory tests are reported. Besides particle to pore throat size ratio, concentration and flow velocity, other important factors governing the permeability impairment are: 1. medium coordination number and 2. shape of pore throats.
Scale Formation in Oil Reservoir and Production Equipment during Water Injection Kinetics of CaSO4 and CaCO3 Crystal Growth and Effect on Formation Damage
Authors: Moghadasi J. , Jamialahmadi M. , Müller-Steinhagen H. , Sharif A. 
Published: December 2007

Abstract
In the oilfield, due to the extensive use of water injection for oil displacement and pressure maintenance, many reservoirs experience the problem of scale deposition when injection water starts to breakthrough. In most cases the scaled-up wells are caused by the formation of sulphate and carbonate scales of calcium and Strontium. Due to their relative hardness and low solubility, there are limited processes available for their removal and the preventive measure such as the 'squeeze' inhibitor treatment has to be taken. It is therefore important to have a proper understanding of the kinetics of scale formation and its detrimental effect on formation damage under both inhibited and uninhibited environment.
This paper presents an experimental and theoretical study of permeability reduction of porous medium caused by scaling. Two incompatible solutions, calcium and sulfate/carbonate rich ions were injected into and calcium sulphate or carbonate generated within the porous medium by chemical reaction. Mechanisms by which a precipitate reduces permeability include solids depositing on the pore walls because of attractive forces between the particles and the surface of the pore, a single particle blocking a pore throat, and several particles bridging across a pore throat. The characteristics of the precipitate influence the extent of formation damage. Conditions such as large degree of supersaturation, presence of impurities, a change in temperature, and the rate of mixing control the quantity and morphology of the precipitating crystals.
Reinjection of Finely Disposed Produced-water Reduces Formation Damage in Low Permeability Zones
Authors: Wan Jun , Sui Xinguang , Liu Bing , Bai Yanming , Liang Shaohui 
Published: December 2007

Abstract
Daqing Oilfield is a water flooded oilfield, the injected water is usually the produced-water. It reduces the injection cost and performs a good environmental effect as well. The formation of tertiary infill wells are usually of a effective thickness less than 0.5m, and a permeability less than 0.050 Darcy, and the permeability in 60% of the formation is less than 0.010 Darcy, this kind of formations are vulnerable to be damaged, it requires a higher quality of injected water,. In tertiary infill wells, reinjection of produced-water does a more serious damage to the formation, the water absorbing thickness decreases from 76.4% of the secondary infill wells to that of 59.3% of tertiary infill wells, this result in a serious adverse waterflood development.
Through a considerable research and analyses of the injection operation , this paper suggests a finely treatment of produced-water by decreasing the suspended particle to less than 7-8mg/l, and increasing the water absorbing thickness of tertiary infill wells to 81.2%, this performs a better water absorbance. This makes the water absorbing thickness reach 66% in those formations with a permeability less than 0.010 Darcy, and the producing thickness in those formations with a permeability less than 0.010 Darcy reach to 61% in oil well, this eases the damage degree of produced-water to low permeable formations, thus performs a good waterflood effect in low permeable formations.
Formation Damage vs. Solid Particles Deposition Profile during Laboratory Simulated PWRI
Authors: Al-Abduwani F. A. H. , Shirzadi A. , van den Broek W.M.G.T. , Currie P. K. 
Published: December 2007

Abstract
The importance of produced water re-injection (PWRI) is unquestionable. It is in many cases the cheapest and most environmentally friendly solution for wastewater disposal. It is also a feasible method for EOR as a water flooding mechanism.
PWRI, however, suffers from a major limitation, which is the current inability in accurately predicting the lifespan and performance of its injection wells. This is due to the multitude of parameters that affect it. Current models 1-2 exist that incorporate the thermal effects 3 of PWRI leading to fracture growth. However, the leak-off pattern of this injection differs from that of clean water (seawater) injection due to the damage caused by the produced water onto the formation and especially the fracture faces. Thus, static filtration experiments with refined post-mortem analysis have been conducted to obtain quantitative deposition profiles along the core. This allows for the testing and verification of existing models 4-7.
The post-mortem analysis introduced in this paper will be used for future dynamic filtration experiments as well as experiments specifically devised to simulate the fracture tip area. A unified model that will accurately reproduce the permeability decline and deposition profile for all three sets of experiments will flow, thus advancing the predictability of injectivity decline associated with PWRI.
A detailed description of the post-mortem analysis will be presented. Testing of existing heuristic models Wennberg5 and Bedrikovedski7 will be published in the near future.
Conductivity Maintenance: Long-Term Results from the Use of Conductivity Enhancement Material
Authors: Lehman Lyle V. , Shelley Bob , Crumrine Tim , Gusdorf Matthew , Tiffin Judy 
Published: December 2007

Abstract
In 1997, a surface modification agent was introduced into the global stimulation market. The agent was designed to enhance and sustain fracture conductivity by making the proppant surface tacky. Several conductivity-enhancing mechanisms were suggested. Two important mechanisms resulting from increased surface tackiness are 1) increased proppant pack porosity resulting in increased pack permeability and 2) increased proppant pack stability that prevents encroachment of formation fines into the pack and migration of fines within the proppant pack. In terms of extended conductivity maintenance, the fines control aspect has proved to be the most valuable property developed from the product.
This paper presents a brief discussion on the theory of applying a tacky surface on proppants to mitigate conductivity loss from fines migration in the propped fracture. The paper then offers direct comparison case histories, which contain long-term production data that illustrate the benefits from lower operating expenses and increased production over the use of previous completion methods. Case histories are discussed in reservoirs that are known for fines migration, such as coal-bed methane (CBM) and high permeability-unconsolidated sandstones. The histories also include zones not widely known for fines migration problems, where the authors feel that this condition does exist.
Revitalizing a Mature Sand-Prone Field by Installing Enhanced Gravel-Pack Completions - A Case Study
Authors: Md Noor Mohamed Zaini B. , Selamat Kasim B. , Kasim Abdullah B. , Salahudin Sharifudin 
Published: December 2007

Abstract
The Dulang oilfield is located some 130 km offshore Terengganu in Peninsular Malaysia and is structurally complex. Production from the field began in March 1991, and oil production averaged 26,000 STB/D with peak production reaching approximately 50,000 STB/D. As with the other field developments in the Malay Basin, sand production was not anticipated under normal drawdown or producing conditions, and thus, all the wells in Dulang field were completed without any sand-control measures.
In the later stages of the field's life, however, a significant amount of sand production was observed. This condition gradually increased over time, resulting in reduced hydrocarbon production, additional costs for routine wellbore sand clean-outs, and platform shutdowns for surface vessel sand clean-up.
In 1991, eight years after initial development, a wellbore opportunity study was initiated to revitalize a section of Dulang field. The objectives of the study were to 1) identify remaining reserves, and 2) identify new completion options to maximize recovery. The study identified three major activities that would improve oil production: Develop by-passed reserves behind casingReactivate idle wells that had been closed in, some as a result of sand production.Provide additional drainage points for undeveloped reserves.
From the proposed wellbore opportunities study, ten wells were identified for a workover campaign, and six wells were identified for infill drilling or sidetracks.
Sand production mitigation using a gravel-pack technique was identified as a requirement in the completion plan for the majority of the targeted reservoirs. However, the increase in mechanical skin that would result from a sand control installation was also recognized. Hence, it was determined that the best approach for production optimization in these wells would be a combination of a sand control and a stimulation technique. Several technologies, which included frac-and- pack, extension pack with conductivity enhancer, and highrate water-pack (HRWP) gravel packing, were suggested. The use of a special completion tool that would enable greater flexibility on short string selective production in multi-zone gravel-packed wells was also identified.
After careful review of the options, a combination of sand control and stimulation technique (frac pack, extension pack and high-rate water pack) was selected, and the combined strategies have successfully increased the productivity and prevented sand production in the Dulang wells.
A Single Additive Non-ionic System for Frac Packing Offers Operators a Small Equipment Footprint and High Compatibility with Brines and Crude Oils
Authors: McElfresh P. M. , Williams C. F. , Wood W. R. , Ruzic M. , Baycroft P. D. 
Published: December 2007

Abstract
There are many advantages to using a single component, non- ionic viscoelastic surfactant gel (VES) for sand control and stimulation applications. The VES is highly compatible with a wide range of completion brines and crude oils, is virtually non-damaging to the formation and demonstrates shale- stabilizing characteristics with many types of shale. Another advantage of having a single additive VES system is that it requires a small equipment footprint. With this combination of compact equipment set-up and simplified fluid mixing, complex, high rate, high sand concentration frac jobs are possible where rig space is limited or equipment is limited because of the remote location from full stimulation service. A treatment using a single additive system can typically be performed with only one or two frac pumps, a frac blender, proppant silo or a modified sand infuser and data acquisition equipment.
Many offshore facilities have commingled gathering systems many of which must be treated for emulsions with chemicals. This treatment process may be substantially reduced or simplified when a non-ionic VES fluid is used for stimulation compared to a crosslinked gel fluid. The high compatibility with completion brines and crude oils, coupled with the non- damaging nature of the VES itself, reduces the likelihood of formation damage in the well. The VES promotes a fast and more thorough recovery of the stimulation fluid from the formation and if emulsions are generated, it will allow for easier treatment in the surface facility.
Since December 2000, non-ionic VES gels have been used in over 30 applications in the Adriatic Sea and in the Gulf of Mexico in brines ranging from seawater with varying amounts of KCl to 10.5 ppg CaCl2. Each application has resulted in enhanced production due to the excellent performance of the fluid. Clean-up rates have been directly related to bottom hole pressure, and have not been complicated with typical clean-up problems such as clay swelling, water blocks, and filter cake plugging of proppant packs. This type of treatment with a minimum equipment set-up has made high rate/volume frac treatments possible without the need of a stimulation vessel.
Real Time Monitoring of Permeability, Elastic Moduli and Strength in Sands and Shales Using Digital Rock Physics
Authors: Dvorkin Jack , Kameda Ayako , Nur Amos , Mese Ali , Tutuncu Azra Nur 
Published: December 2007

Abstract
The Digital Rock Physics (DRP) technology is based on a rigorous numerical simulation of physical experiments in a realistic pore space, at the pore-scale level. The output is usually a macroscopic property conventionally measured in the lab. For example, single-phase viscous fluid flow simulation through a digitized pore space provides absolute permeability. A simulation of electrical current provides conductivity, and a simulation of the stress field provides the elastic moduli and strength. DRP complements lab measurements and, at the same time, enormously enhances the geoscientist's capabilities because digital experiments can be conducted in real time and on small fragments of rock, such as drill cuttings.
In this paper, results of a feasibility study on DRP technology is reported using for the first time the drill cutting samples in obtaining petrophysical properties including permeability and porosity of formations. This real-time technology may become very beneficial to the industry once it is established that the results are reliable.
The 3D digital pore space needed for numerical simulation has been recreated from 2D images by means of statistical simulation. An example is also presented where the 3D digital pore space was obtained by direct CT scanning of drill cutting. The resulting macroscopic rock properties have been compared to independently obtained core data from laboratory measurements and log data from the same interval where cuttings are obtained.
Modelling of Near-Wellbore Formation Damage for Open Hole Horizontal Wells in Anisotropic Media
Authors: Ding Y. , Renard G. 
Published: December 2007

Abstract
It is well known that formation damage due to drilling fluid has a huge impact on well productivities, especially for open hole completed horizontal wells. To evaluate this impact to keep maximum oil productivity, a numerical model has been developed to simulate formation invasion and damage during the drilling phase of a well. This model can be used to study the impact of various parameters related to drilling fluid properties or drilling conditions on well performances.
In previous papers1,2, a methodology combining both experimental and numerical approaches has been proposed to model the near-wellbore formation damage for both water- based mud (WBD) and oil-based mud (OBM) and filter cakes removal by natural clean up procedures. However, anisotropic permeability was not considered, although heterogeneities were taken into account. The main difficulty of near-well modelling of anisotropic media is that the generally recognised elliptic flow behaviour in the well vicinity is not valid as the well cannot be considered as a point (or line) source. Flow behaviour is radial at the wellbore boundary and becomes gradually elliptic when going away from the well. To accurately model near-wellbore formation damage, a new grid system, which is obtained based on elliptic coordinate transformation, is proposed in this paper, and a new numerical scheme is given for the modelling of near-well flow in anisotropic media.
The proposed model can be used to study non-uniform formation damage and cleanup results around the well due both to permeability anisotropy and gravity effect. Examples are presented to study sensitivity of various parameters (fluid properties, drilling conditions, …) on well performances. This model is developed for the modelling of horizontal wells as well as slanted wells. It can be used as a tool for well design and construction. Finally, a field example in a deep offshore reservoir is presented to show an application of the developed model.
Modeling of polymer adsorption under near-wellbore flow conditions
Authors: Zitha Pacelli L. J. , Mandzi Daniel , Vermolen Fred , Darwish Mohamed I. M. 
Published: December 2007

Abstract
An investigation of the adsorption of long flexible polymer chainlike molecules during flows in low permeability porous media under near-wellbore conditions is reported. The theory for this phenomenon (canonical filtration theory) previously developed is firstly surveyed. This theory encompasses four partial differential equations describing the overall mass conservation, the conservation of the longest chains and the layer and bridging adsorption kinetics. Simple analytical expressions were derived mainly for flow in flat cores (having a length that is much smaller than the diameter), for which the problem reduces to the adsorption kinetic equations. Numerical computations were conducted to predict the transport and sorption behavior in long cores. Experiments conducted using a high molecular weigh cationic polyacrylamide and siliceous cores have been performed. The flat core experiments were used to determine the kinetic adsorption coefficients, which were then used in the numerical computations. Long core flow experiments were used to determine concentration profiles. The theoretical prediction and experiments in the long cores are in excellent agreement, which proves the validity of the canonical filtration model.
Predicting Asphaltene Deposition and Assessing Formation Damage
Authors: Garrouch Ali A. , Al-Ruhaimani Feras A. 
Published: December 2007

Abstract
This study formulates a mass balance model in integral form, for predicting permeability reduction caused by asphaltene deposition in vertical and horizontal wells. The theory accounts for both the effect of radius and time on all the parameters affecting the deposition process. This approach accounts, implicitly, for the effects of pressure, temperature, and fluid composition as a function of position in the reservoir. The model accounts for pore-size distribution, rock original permeability, and asphaltene particle-size distribution. The model is general and can be used to estimate the permeability reduction for both homogeneous and heterogeneous formations.
Formation Damage Resulting From Unexpexted Acid Incompatibilities At Brutus, Gulf Of Mexico
Authors: Fair P. S. , McNeil R. I. , Nitters G. , Stroman S. R. , Davis C. L. 
Published: December 2007

Abstract
Formation damage problems in the Brutus A-8 well in the Gulf of Mexico have provided a rich opportunity to study mechanisms of pore plugging. Field data and laboratory experiments have led to the following conclusions. Unexpected reactions can take place between spent organic acids and completion brine, resulting in polymerization and other reactions that can plug formations.These precipitates can be prevented by appropriate acidizing practices, including the use of sufficient (ammonium chloride or other innocuous brine) spacers to maintain separation of the (spent) acid and completion brine and the use of an appropriate post-flush acid to maintain a low pH in the spent acid.If a precipitate does form, it can be cleaned up readily by acid treatment if the acid reaches the occluding precipitate.Organic acids should not be mixed. That is, if completion uses one organic acid, no other organic acids should be used in subsequent stimulation treatments.
Stimulation Efforts in Carbonate Gas Reservoir Experiencing Subsidence in Offshore North West Java Field - Indonesia
Authors: Susilo Yoliandri , Rahamanda Zahazny , Wibowo Wahju , Tjahyadi Riza , Silitonga Frans J. 
Published: December 2007

Abstract
Subsidence and reservoir compaction continues to be significant concern for the oil and gas industry. The decrease of pore pressure during hydrocarbon production (depletion) leads to compaction of the reservoir. When compaction occurs, it changes the porosity and permeability properties of the reservoir rock and can affect recovery efficiency and well productivity. The results of stimulation efforts to improve gas deliverability in carbonate reservoir experiencing subsidence in Offshore North West Java (ONWJ) field are presented here.
The wells in this study were completed in the Parigi Formation, which is a thick carbonate buildup formation with large columns of gas about 250-300 feet thick underlain by aquifer.It has high porosities (32-45%) and good gas permeabilities up to several Darcies with the initial well production were around 20-30 MMSCFD. The continuous production of gas from this shallow, thick and low strength carbonate reservoir has resulted in reservoir compaction, surface subsidence, several well mechanical failures and a sharp production decline (from 15 MMCFD to 2 MMCF). The other impact of declining gas rate that is nearing its critical velocity is causing water condensation that cannot be lifted out of the well; it then accumulates in the wellbore and creates more back pressure on the reservoir.
Treatment efforts, starting from nitrogen kick-off with CT to unload the condense water in the wellbore followed by re- perforation and acidizing job, that were conducted in the first two well have resulted a significant production response. Gas production increases by 4-9 times after the treatment. The previous fear/perception that acidizing would perhaps even worsen the conditions of the reservoir and thus reduce production proved not to be true. These successful treatments have led to stimulation campaigns for other wells in the area.
This paper will also discuss several surveillance projects to monitor and assess the magnitude and progression of surface subsidence, reservoir compaction and wellbore damage in this area.