bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Formation Damage from Transient Pressure Analysis: Unsteady State Skin Factor
Authors: El-Khatib Noaman 
Published: June 2011

Abstract
The damaged zone around the well is considered as the internal region of a composite system comprising two regions of different permeabilities. An analytical solution is obtained in Laplace space and is inverted using Stehfest Algorithm. The skin factor is obtained as the difference in dimensionless pressure at the well of the composite system and that of the homogeneous system at the same dimensionless time. The ratio of the skin factor to the steady state skin factor is estimated and correlated with the permeability ratio and the dimensionless depth of invasion.
The developed model and the correlation charts can be used to evaluate the formation damage from well test analysis around the well by estimating both the permability and depth of invasion in the damaged zone. This is an improvement in the conventional method that gives the steady state skin factor which is a combination of both permeability ratio and invasion radius.
Additional pressure drop due to damage is found to be time dependent and varies from zero at the start and approaches that obtained from steady state skin factor at very large dimensionless time. The unsteady state skin factor and skin factor ratio depends on both the permeability ratio and the dimensionless invasion radius and not uniquely on their combination.
Successful Application of a New Solids-Free Fluid Loss System in Acid Fracturing Treatments Achieved Significant Well Productivity Improvements in Saudi Arabian High Condensate Gas Producers
Authors: Leal Jairo , Solares J. Ricardo , Taq Ali , Duarte Jorge , Al-Shammari Nayef , Al-Ruwaished Azmi , Eoff Larry , Izquierdo Guillermo 
Published: June 2011

Abstract
Controlling fluid matrix leakoff into the formation is of critical importance during fracture stimulation treatments to ensure objectives are met. Decreasing the amount of fluid leakoff increases the volume that is available to maintain and propagate a hydraulic fracture. The need to minimize fluid leakoff is even more significant during acid fracturing since maintaining the fracture is difficult because of the ability of acid to spend quickly as it enters the formation. Traditional approaches utilize solids-laden viscous gels to reduce the volume of fluid leakoff as a fracture is propagated; however, it has been amply documented that the solids typically used are capable of damaging the formation if not properly removed after the treatment. Moreover, removal of treatment gels, which is required to minimize formation damage, is contingent on selection and design of breakers or other compounds, which are often chosen based on a number of uncertain reservoir parameters.
This paper will present both laboratory and field application results from a new solids-free fluid loss (SFFL) system designed to reduce matrix permeability to aqueous fluids, thereby resulting in longer fracture propagation caused by a significantly lower fluid-leakoff rate. This fluid loss system does not require the use of breakers, which eliminates the potential negative impact on post-stimulation well productivity. Laboratory test data will show the ability of the material to control fluid leakoff and its ability to achieve high levels of regained permeability to hydrocarbon.
Field results from the application of the new system during acid fracturing treatments in high condensate gas producers in Saudi Arabia, in which achieving long half-length fractures with acid is very difficult due to excessive fluid leakoff, are also discussed. Post-treatment analysis showed that utilization of the new system resulted in significant reduction of fluid leakoff, thereby allowing treating pressure to remain above closure pressure throughout the treatment and achieve a longer fracture extension. A post treatment performance comparison between gas producers treated with the new system and those stimulated using conventional fluids will show that using the new system consistently exhibited better productionperformance (normalized for reservoir characteristics).
Investigation of Asphaltene Deposition Mechanisms During Primary Depletion and CO2 Injection
Authors: Jafari Behbahani T. , Ghotbi C. , Taghikhani V. , Shahrabadi A. 
Published: June 2011

Abstract
Asphaltene deposition causes serious problems in the oil industry. Variation of oil composition and reservoir pressure is reported to be the most important factors that influence asphaltene deposition from reservoir oil. In this study, a mathematical model was developed to simulate asphaltene deposition during primary depletion and CO2 injection. The main purpose of this study is to investigate and to compare asphaltene deposition mechanisms due to primary depletion and CO2 injection. The solid model as thermodynamic model was applied to investigate asphaltene precipitation. A numerical model was established to the governing equations both in space and time and model parameters were determined by history matching. Because of the implicit and coupling nature of equations in the model, an iterative method was applied to solve the numerical equations. Results show that surface deposition, entrainment and pore throat plugging have occurred during primary depletion and CO2 injection. Deposit re-entrainment and surface deposition proceed against each other. So, in most situations one of these two mechanisms is dominant, and the other one might be ignored. Enhanced re-entrainment deposition allows flocculated asphaltene to change into precipitated asphaltene, or be dispersed into the oil phase. Also, surface deposition rate during CO2 injection is more important than due to primary depletion. Result shows that entrainment of asphaltene deposit and pore throat plugging are predominant mechanisms of physical deposition in CO2 injection. A thermodynamic modeling show that because of CO2 is a precipitant, asphaltene precipitation is more important during CO2 injection than primary depletion.
Improvement of the Criteria for Expandable Sand Screen Well Candidate Selection
Authors: Salehi-Moorkani Reza , Ghasemzadeh Amir 
Published: June 2011

Abstract
One of the new techniques to prevent sand production is completing well with Expandable Sand Screen (ESS). This technique is used in some sand stone reservoirs in Iranian onshore fields and the results of this technique were acceptable in reducing sand production and increasing productivity of the wells. Therefore, oil companies tend to complete more wells using this method. Selecting the suitable well to install ESS is one of production engineers concern which needs good knowledge of both technology concept along with well and reservoir conditions like perforation interval, critical flow rate, water oil contact level, etc. In this study previous wells which were completed with ESS have been studied and based on field experiences; the criteria for well candidate selection are developed. The results of this paper will provide engineers with a better knowledge of when and under which well and reservoir conditions this technique should be applied.
Application of Genetic Algorithms to the Optimization of Pressure Transient Analysis of Water Injectors using Type Curves
Authors: Zakaria Ahmed S. , Hafez Mohamed M. , Ochi Jalel , Zaki Karim S. , Loloi Mehdi , Abou-Sayed Ahmed 
Published: June 2011

Abstract
Injection pressure fall-off (PFO) test analysis has proven to be a reliable vehicle for understanding and evaluating well performance. Recently the methodology has been extended to the understanding of injectors. This paper presents an optimization model for analysis and interpretation of PFO tests for fractured water injectors. An elliptical composite flow model mathematically represents the fractured injector well. The optimization scheme couples the mathematical model of the well with a Genetic Algorithm (GA) to reach the final solution. The pressure transients representing the behavior of an injector a closing fracture and the discontinuity in fluid mobility are best developed in elliptical coordinates. The methodology derives the dimension of the induced fractures, formation permeability, fracture conductivity and fracture face skin.
The current paper illustrates the solution methodology by showing the attained match for a West Africa offshore field case. The field case provides reasonable agreement for the fracture dimensions and characteristics as verified by other techniques.
Genetic Algorithms are one of the most common artificial intelligence techniques for optimization. The reported solution is obtained by applying a GA with a non-linear least square error function as an objective function. A special penalty function, mutation, crossover probabilities, and stopping criterion are used to obtain the global minimum of the objective function. The test data analysis is done through type curve matching of the pressure and its derivative by minimizing the objective function to help determine the parameters that provide the best match between the field data and the presented novel fractured injector type curves.
Advancements in Screen Testing, Interpretation and Modeling for Standalone Screen Applications
Authors: Chanpura Rajesh A. , Fidan Selcuk , Mondal Somnath , Andrews Jamie S. , Martin Frederic , Hodge Richard M. , Ayoub Joseph A. , Parlar Mehmet , Sharma Mukul M. 
Published: June 2011

Abstract
Slurry type sand retention tests (SRT) that simulate gradual rock failure around the wellbore have been widely used in the industry to evaluate the performance of sand control screens for standalone screen (SAS) applications. Using the test results, screen selection is generally done based on the relative ranking of screen performances rather than absolute performance.
A recent paper by Chanpura et al. (2011) highlighted the drawbacks of the current practices in slurry type SRT procedures and proposed a new testing and interpretation methodology. Another recent work by Mondal et al. (2010) proposed simulation methods and results that, to the best of our knowledge, modeled screen performance numerically for the first time and presented comparisons to physical experiments. However, the approach used by Mondal et al. considers cases where hole collapse occurs on wire wrap screens and simulates "prepack" testing as opposed to slurry type tests considered in this work.
In this paper, we review the recent advancements in screen testing, interpretation and modeling for standalone screen applications, and present an analytical as well as a statistical (Monte Carlo) approach for prediction of sand production through sand screens with slot geometry. We show that the proposed methods can estimate both mass and size distribution of the produced solids in a slurry type SRT taking into account the full particle size distribution (PSD) of formation sand for wire wrap screens. Simulations show that once the slot opening is covered by particles bigger than the slot opening, sand production becomes negligible unless there is a true "fines" problem, which is characterized by a bimodal size distribution. The effect of slot size variation in screen coupons on sand production demonstrates the importance of proper quality control or at least accurate determination of slot sizes in these tests. The proposed methods can be used to estimate sand production in slurry type SRT for different screen sizes and thereby enable screen size selection based on defined acceptable level of sand production. Final screen selection can be confirmed through a sand retention test.
Determining Perforation Parameters from Single-Shot Tests: Radial vs. Axial Flow
Authors: Harvey J. , Kokel P. , Zhan L. , Grove B. , Huang H. , Atwood D. 
Published: June 2011

Abstract
Flow laboratories have been used for six decades to evaluate and optimize perforating systems for downhole environments. A key experimental variable is the pressure/flow boundary condition on the target core. Two standard configurations are axial flow, and radial flow. The implications of each configuration have been addressed somewhat in the literature in the context of steady flow with identical but prescribed tunnels. There has never been a careful comparison of the influence of boundary conditions on the actual tunnels.
In this paper we summarize the state of understanding regarding these two flow regimes by primarily focusing on the sensitivity of each to perforation damage and cleanup. In addition to addressing the differences under steady flow conditions, we also experimentally investigated the influence of target boundary conditions on the transient flow regime (i.e. during dynamic underbalance perforation cleanup). This was primarily an experimental investigation, supported by numerical simulations to determine baseline flow performance.
We find that radial flow provides the most meaningful measure of perforation damage (as indicated by post-shot steady flow). Indeed, radial flow is indispensable to parameterize skin and productivity models as they are currently formulated.
Axial flow yields steady production flow which is most sensitive to penetration depth, and relatively insensitive to perforation damage.
Finally, and perhaps most significantly, the transient perforation cleanup process is different for radial vs. axial boundaries. The intrinsic inflow characteristic of the tunnel is itself a function of the boundary conditions at shot time.
Proper selection of laboratory flow geometry is essential to yield meaningful measurements of perforation damage. In addition to this diagnostic purpose, target boundary conditions play a critical role in the removal of perforation damage, evolution of open tunnel length and diameter, and the resulting perforation flow efficiency.
Water-based, Frac-Pack Remedial Treatment Extends Well Life
Authors: Nguyen P. D. , Weaver J. D. 
Published: June 2011

Abstract
A solvent-based surface modification agent (SMA) has been very successful in precoating proppants to improve their performance in fracture stimulation treatments. To a far lesser degree, it was also used as an aggregating agent applied to formations and/or proppant packs to stabilize fines in a remedial method. However, its incompatibility with some aqueous wellbore fluids and the safety concerns due to the solvent base has limited its field applications. This paper presents the development of a new formulation of an SMA-aggregating agent that is aqueous-based, and includes results obtained from extensive laboratory studies. The new aqueous-based surface-modification agent (ASMA) provides significant improvements in health, safety, and ease of operation for the treatment of proppant, formation surfaces, and unconsolidated formations to control proppant and fines aggregation. Additionally, this ASMA will function to moderate undesirable diagenetic reactions that effect proppant strength, proppant pack permeability and formation permeability.
A unique property of this ASMA is that the rate of release of the active SMA ingredient can be controlled allowing it to be used for primary fracturing treatments or as a remedial treatment of damaged proppant packs or inhibiting continued formation fines production. This means the ASMA can be added directly to frac fluid during a treatment to coat proppant, to a fracture stimulation treatment prepad to treat the formation face, or at a later time as a remedial treatment.
As a remediation application, once injected into the proppant pack and formation matrix, the ASMA forms a thin film on the particulates, covering the fines and anchoring the particulates in place. In addition to controlling fines, ASMA coating forms a hydrophobic film that encapsulates the particulate surfaces, inhibiting the chemical reactions that lead to scale formation in the pack matrix and subsequent productivity loses.
Experimental testing using packed beds of proppant, formation sands, and various fines were used to simulate proppant pack conditions and formation fines before and after remedial treatments. It was observed that only a very thin film was formed, which encapsulated the proppant or formation particulates and created cohesion between grains without plugging the pore spaces. Additionally, laboratory results show that ASMA treatments effectively mitigate the buildup of scale in various sand packs as well as successfully control the migration of formation fines into proppant packs to maintain fluid flow paths.
Critical Assessment of Microemulsion Technology for Enhancing Fluid Recovery from Tight Gas Formations and Propped Fractures
Authors: Champagne Lakia M. , Zelenev Andrei S. , Penny Glenn S. , Travis Kerry 
Published: June 2011

Abstract
In recent years numerous case studies documenting the use of microemulsions in hydraulic fracturing of tight gas formations have appeared in the literature. Field case studies and supplemental laboratory data have illustrated that microemulsions enhance core permeability to gas and enhance fluid flowback mainly due to lowering capillary pressure and altering wettability in reservoirs and propped fractures. Although proven successful for enhancing gas production, many aspects of the microemulsion behavior in propped fractures are still poorly understood. In the present study we have performed numerous experiments on microemulsion-assisted fluid recovery from columns packed with sand proppant and shale, using microemulsions of different chemical composition. Our results indicate that the extent to which microemulsion additives promote foaming is an important factor in achieving highest possible levels of fluid recovery. By using properly formulated microemulsion compositions one can achieve significant improvement in fluid recovery at commercially viable doses of treatment.
Interactions of Organic-HF Systems with Aluminosilicates: Lab Testing and Field Recommendations
Authors: Al-Harbi B. G. , Al-Khaldi M. H. , Al-Dossary K. A. 
Published: June 2011

Abstract
Mixtures of HCl-HF, known as mud acid, have been extensively used in sandstone matrix stimulation. However, mud acid treatments were applied with poor success rate. This is mainly due to complex acid/rock interactions and other factors, such as the presence of HCl-sensitive clays and poorly consolidated formations. In addition, precipitation of reaction products of sandstone minerals dissolution in HF, especially at elevated temperatures, is another common factor limiting the mud acid effectiveness. These limitations associated with the use of typical HCl-HF mixtures warrant the use of organic-HF acids. These mixtures are used as an alternative to the HCl-HF blends to stimulate formations with HCl-sensitive clays and corrosion concerns. Various organic-HF blends have been extensively used; however, the studies of their interactions with sandstone rocks have been relatively limited. This work, for the first time, provides a systematic investigation of the chemical interactions of various sandstone minerals with three different organic-HF acids over a wide range of parameters.
Organic-HF systems based on acetic, formic, and citric acids were studied. Using static solubility tests coupled with chemical analysis of spent acid solutions, the dissolution of different sandstone minerals in each system was evaluated as a function of organic acid/HF weight ratio, reaction time, and temperature values of 50 and 75°C. The Scanning Electron Microscopy (SEM) and the X-ray fluorescence (XRF) techniques were used to explore the possibility of the presence of any precipitated reaction products.
Results based on this study showed that all organic-HF acids tested have a retarded nature with sand and clay minerals when compared to regular HCl-HF mixtures. In general, the dissolution of different sand and clay minerals in each organic-HF system is dependent on the type, ratio of the organic acid/HF used, and the temperature value. The reaction rate of different organic-HF acids with sand and clay minerals increased when the temperature value was increased from 50 to 75°C.
Findings based on this study addresses various chemical interactions and precipitation mechanisms involved with the reaction of organic-HF acids with sand and clay minerals. This work highlights the effects of the initial acid concentration, temperature, and soaking time on the performance of organic-HF acids. In addition, it provides new insights into the field application, and potential limitations of organic-HF acids.
Effect of Spent Acids on the Wettability of Carbonates at High Temperature and Pressure
Authors: Saneifar M. , Nasralla R. A. , Nasr-El-Din H. A. , Fahes M. , Hill A. D. 
Published: June 2011

Abstract
Accumulation of spent acid in the wellbore area after acidizing causes severe formation damage that would result in loss of productivity. This would cause reduction of relative permeability to gas, especially in tight gas wells. Capillary forces are the key parameters that affect trapping of spent acid in the formation. This work provides a comprehensive study of the effect of acid additives in spent acid on contact angle in tight gas carbonates. All experiments were conducted using the Drop Shape Analysis (DSA) at high temperature and pressure.
Different types of commonly used additives including corrosion inhibitors, iron control agents, mutual solvents, methanol, acetic acid and formic acid were tested at different concentrations. Experiments were conducted at temperature of 100 °C and pressure of 1000 psi.
Acid additives such as methanol, corrosion inhibitors, formic and acetic acids reduced the contact angle. Both iron control agents showed no impact on contact angle at concentration of 0.3 wt.% while at the lower concentration of 0.03 wt.% they decreased contact angle. A study was also done on the effect of temperature on contact angle of spent acid. The results showed that increasing temperature up to 100 °C increased contact angle, while beyond this temperature contact angle was decreased.
This work would help to better understand the ability of acid additives in altering wettability of carbonate rocks, which would consequently result in better designing the acid formulae and enhancement in well productivity by minimizing capillary forces.