bluuebunny/crossref_metadata_2025_split huggingface dataset:
Solubility and Inhibition Efficiency of Phosphonate Scale Inhibitor_Calcium_Magnesium Complexes for Application in Precipitation Squeeze Treatment
Authors: Valiakhmetova A. , Sorbie K. S. , Boak L. S. , Shaw S. S. 
Published: January 2016

Abstract
Scale inhibitor (SI) squeeze treatments are applied extensively for controlling scale formation during oil production. The current research involves phosphonate/metal precipitate studies in the context of precipitation squeeze treatments. The main focus here is on the precipitation and solubility behaviour of the SI_Ca_Mg complexes of HEDP (di-phosphonate), DETPMP (penta-phosphonate) and OMTHP (hexa-phosphonate) phosphonate Sis; these phosphonate/mixed Ca/Mg divalent precipitates are denoted as SI_Can1_Mgn2, where n1 and n2 are the stoichiometric ratios of Ca and Mg to SI.
Precipitation experiments with SI_Can1_Mgn2 species were carried out over the temperature range, 20–95°C, while varying the Mg/Ca molar ratio over a wide range from all Ca to all Mg. These precipitates were formed in MgCl2·6H2O/CaCl2·6H2O brine solutions with appropriate molar ratios of metals, then separated from supernatant by filtration. Subsequently, the solubility of the collected precipitate was found in a solution of the same Mg/Ca molar composition from which it was prepared. In this type of experiment, the solubility of the SI_Can1_Mgn2 precipitate without any re-speciation is determined. In addition, another type of solubility experiment was carried out for a precipitate formed in a brine with one fixed Mg/Ca ratio and this was subsequently placed into a solution with different Mg/Ca compositions (from all Ca to all Mg). In these experiments, re-speciation of the precipitate may occur.
We have been able to establish the solubility (Cs) of the precipitates of 3 SIs (HEDP, OMTHP and DETPMP) as a function of both temperature and Mg/Ca molar ratio. It has been shown, that the solubility (Cs) of precipitate is in equilibrium with Mg and Ca concentrations in solution and any change of these parameters leads to solubility (Cs) variation. All phosphonate/metal precipitates become less soluble with increasing temperature and much more soluble as the proportion of Mg increases. We have found, that any change in Mg/Ca ratio of brine does lead to a re-distribution of Ca, Mg and SI concentrations in a given precipitate and bulk solution, and hence leads to some variation in the precipitate solubility.
In addition, the inhibition efficiency (IE) of precipitated and then re-dissolved HEDP, OMTHP and DETPMP SIs was tested and was compared with the IE of industrial stock products. We show that, unlike polymeric SI precipitates, the inhibition activity of phosphonate SIs does not depend very significantly on the precipitation process and the IE of precipitated and re-dissolved SI_Ca and SI_Ca_Mg complex is very close to that of the industrial stock solutions. These results can be used directly for modelling phosphonates precipitation squeeze treatments and the significance of these results for field applications is explained.
Perforating System Performance at Downhole Conditions: Recent Advances in Modeling and Prediction
Authors: Grove B. , Harvey J. , Martin A. 
Published: January 2016

Abstract
Modeling of perforating system performance at downhole conditions has received significant attention in recent years. This is due to increased recognition of the importance that perforating plays in well performance, and ultimately asset value.
To this end, models have been recently developed to more reliably predict key downhole parameters, including formation penetration depth, perforation cleanup, and skin. These new models have been incorporated into a software tool, which enables users to optimize perforating designs around completion and production objectives, while considering operational constraints.
This paper summarizes these recent advances, some previously unpublished, and briefly summarizes recent case studies highlighting the impact of the improved modeling capabilities.
The Impact of Corrosion Inhibitors on Relative Permeability of Water Injector and Production Well Performance
Authors: Johnston C. J. , Sutherland L. , Jordan M. M. 
Published: January 2016

Abstract
In many oilfields with carbonate and sandstone reservoirs corrosion inhibitors are applied to control corrosion within production wells via continuous or batch treatments of the tubing and in water injection wells (seawater/aquifer and produced water) via continuous injection. The corrosion inhibitors within these formulations are fundamentally designed to control corrosion at the lowest treatment rate possible with little thought given to their potential impact on the wettability of the reservoir rock if they were to contact it.
This paper will present details from a set of corefloods which look at seawater and produced water re injection (PWRI) under matrix flow conditions within carbonate and sandstone cores.
The observed stimulation in the water injection tests suggests that it is possible for the injector wells to take more water due to the interaction of the corrosion inhibitors tested for both matrix types. The corrosion inhibitor solution when applied to cores which had been solvent cleaned showed stimulation (increased brine permeability) suggesting that the chemical interacted with mineral surfaces rather than improved brine permeability due to change in residual oil saturation within the pore space of the rock.
Results for corrosion inhibitor application to production wells where the chemical is allowed to flow out of the production tubing during "batch" tubing treatments are also presented. The production well data is in marked contrast to the water injector results, the change in wettability in both carbonate and sandstone observed with the introduction of the corrosion inhibitors tested would reduce oil production and increase water production due to the change in relative permeability observed with corrosion inhibitor adsorption onto the mineral substrate (both silicates and carbonate).
The paper outlines the mechanism of stimulation for water injection wells and highlights the damage potential of a flow assurance challenge that is receiving a significant amount of focus within both onshore and offshore fields at this time.
Results from Response Surface Methodology in the Study of Novel Temporary and Permanent Clay Stabilizers
Authors: Aften Carl W. , Zhang Yanqi Joy 
Published: January 2016

Abstract
The performance results from a systematic study of novel and contemporary clay stabilizers are provided. These interactions range from synergistic to antagonistic and are presented on a response surface with good correlation. Both organic and inorganic permanent and temporary clay stabilizers were studied. Some of these novel effective inhibitors have HIMS ratings lower than choline chloride.
Various clay stabilizers are employed when stimulation techniques requiring aqueous based fluids are necessary in water sensitive formations. Typically, if swelling or migrating clays are present, temporary or permanent stabilizers are utilized. Low molecular weight temporary stabilizers, as a rule, perform only above a critical level concentration, but as the stabilizer's concentration diminishes in the fracturing fluid due to flowback, formation fluid displacement, or other mechanisms, the clay can swell, reducing porosity and permeability. Permanent stabilizers are generally higher molecular weight and can adhere to single or multiple clay platelets, thus dissolution of the stabilizer into the fluid is not favored, and the beneficial anti-swelling effect is of higher duration.
This study was set up using Central Composite Design of Experiments. Performance testing was conducted using a low pressure Bariod fluid loss cell. A set concentration of unbenefited sodium bentonite was blended into water at a specific RPM and duration in the presence of the particular stabilizers, then placed in the cell, sealed, and pressure was applied. Finally leak off rates were measured. The slope of the leak off curve was calculated and plotted versus dosage. The slopes and response surfaces observed had excellent correlation. Additive effects and synergies were noted.
The design of efficient temporary clay stabilizers can be directly linked to performance. Novel temporary clay stabilizers competitive with choline chloride in both performance and environmental profile should be welcomed in stimulation. The duration of the stabilization could also be studied using this test method since porous media experimentation is difficult to perform.
Obtaining Comparable and Relevant Formation Swelling Sensitivity Data from CST: Is this Even Possible?
Authors: Benoit Denise , Montenegro-Galindo G. Rocio , Anderson Katelyn L. , Hoeman Kurt W. 
Published: January 2016

Abstract
Capillary suction time (CST) tests with drilling and treatment fluids have been used to characterize formations for swelling tendencies since 1983. However, in most cases, it is not possible to establish comparisons between data sets acquired in different laboratories or at different times. This paper evaluates how certain factors impact CST and offers useable constraints to the method to establish relevant comparisons across different samples.
The basic operation of CST tests is simple: slurries of formation materials are prepared in treatment fluids, and the time required for free liquid to travel a calibrated distance in standard porous paper is measured. Swelling formation materials consume free water from the slurry, decreasing the available free water and reducing the permeability of the filter cake, which increases the CST (Underdown and Conway 1992). Several factors can artificially alter the measured time, such as materials blocking the flow of fluid. Extensive experimentation to determine the most prevalent factors and minimize their significance led to a robust, sample-to-sample comparison methodology.
The work presented in this paper considers changes in CST response based on the source of formation materials (outcrop samples, drilled cores, and cleaned drill cuttings), the composition [standard spiked samples and natural formation materials analytically characterized by X-ray diffraction (XRD) and cationic exchange capacity (CEC)], and sample preparation (grinding method, particle size, shear rate, shear time, slurry volume, and fluid effects) to determine how each factor impacts the measured CST. Ultimately, a method for obtaining consistent sample preparations and data interpretation for CST is presented. This technique is especially useful in low-permeability formations where other conventional methods, such as core flood tests, cannot be used. In particular, this technique has proven to be very useful when no core formation materials are available and only drilling cuttings can be obtained. To test the robustness of the methodology, shale formation materials from 30 unique wells with clay contents from 6 to 64% were characterized. Measured CST values for each material were used to assess the damage potential in relevant fluids and determine treatment recommendations. By implementing the proper testing constraints, the CST can be used as a reliable, quick, low-cost, easy-to-run, and quantifiable analytical technique for sample-to-sample comparisons.
By controlling the parameters involved with sample preparation, CST can be used as a reliable means to accurately determine the formation material's sensitivity to a given fluid on a well-by-well basis.
Pressure-Dependent Induced Fracture Complexity or Natural Fracture Contribution Evaluation in Unconventional Reservoirs: How to Assure Their Long-Term Benefit
Authors: Sierra Leopoldo 
Published: January 2016

Abstract
Induced fracture complexity or natural fracture contribution to the productivity or hydrocarbon recovery optimization of unconventional reservoirs is fully accepted in the industry but not properly quantified, especially for complex environments where the high induced stresses can affect their shortor long-term conductivity and benefit. With respect to an unconventional reservoir’s matrix permeability, induced fracture complexity or existing natural fracture conductivity can also be pressure-dependent, which will drastically affect well productivity if an operator does not properly consider permeability, complexity, and conductivity during the well-completion stage.
If the pressure-dependent induced fracture complexity is packed as much as possible with small proppant or a microproppant system during the well-completion stage to assure its conductivity, the induced complexity will have a positive impact on well productivity; otherwise, only the stimulation fluid efficiency will be affected. Conversely, for existing pressure-dependent natural fractures, proper or limited packing is required to help minimize the negative impact of overpacking the open natural fractures and altering their original conductivity.
Considering the different completion scenarios and inclusion of small proppants or a microproppant system in the stimulation process, this paper quantifies the inherent benefits of the pressure-dependent induced fracture complexity and pressure-dependent natural fractures by performing numerous reservoir simulations of unconventional gas reservoirs.
Damage Remediation in a Mature Field Reservoir by Applying a Customized Treatment Using Surface Active Additives and Diversion Technologies: Case Histories from San Francisco Field
Authors: Lucuara German , Usuriaga Jose , Campo Pablo , Sepulveda Edwin , Pacheco Carlos 
Published: January 2016

Abstract
This paper discusses successful damage remediation performed in more than 10 wells in a mature oil field producing under a developed waterflooding project in Colombia. The primary damage mechanism observed is associated with a detriment to production related to reduced relative permeability caused by wettability preferences.
A chemical treatment was proposed that consisted of crude oil with efficient and effective surface active additives, such as microemulsions (MEs) and/or formation mobility modifiers (FMMs) and associative polymers (APs) for a proper diversion. The treatment was proposed as an effective method to restore near-wellbore (NWB) permeability in or through the damaged zone in the formation, resulting in production recovery. All matrix-stimulation treatments were conducted rigless by means of an annulus without affecting the artificial lift method and resulted in a significant time and cost savings.
Laboratory data confirmed the ability of the MEs and FMMs to modify interfacial tensions (IFTs) and contact angles. These materials helped promote a change in the degree of wetting of the system, which is dependent on the adhesion tension (the product of the IFT by the cosine of the contact angle). During well treatments, surface pressure spikes during the diversion stages were associated with the arrival of the APs at the perforations and were clearly observed during the development of the treatments, revealing that effective diversion was achieved. Finally, post-stimulation treatment data have shown positive results, confirming the effectiveness of combining these technologies.
This paper discusses how the synergy of using surface active additives with diversion technologies can yield productivity increase in mature oil reservoirs and improve the level of sustainability of current field production.
Ability of a Filter Cake Breaker to Diffuse into Completion Brine and Packed Gravel
Authors: Allogo Clotaire-Marie Eyaa , Ravitz Raymond , Gadiyar Bala , King'Ori Solomon 
Published: January 2016

Abstract
Successful completion of an open hole gravel pack well requires a deposition of a low-permeable filter cake on the wellbore to seal and protect the permeable reservoir formation during drilling and completion operations. The deposited filter cake is removed with the aid of a breaker system before the well is put on production. The placement of a breaker post gravel packing operation brings up a concern regarding the efficiency of the breaker system due to possibly limited contact with filter cake.
This study was initiated to simulate the ability of a filter cake breaker system to diffuse through gravel pack carrier fluids inside a screen base pipe and gravel pack. A new apparatus simulating the diffusion and testing protocol were created and used to perform this study. During the experiments breaker system migrated/diffused through a simulated base pipe and packed proppant filled with 10.3 ppg CaCl2 in less than 24 hours. This proves the ability of a breaker system to contact filter cake in post spot situations.
This paper describes a new method built to perform simulations with the objective to calculate the diffusion time and to document the ability of the filter cake breaker to migrate and/or diffuse through a gravel pack at ambient conditions. The paper also establishes the best practices in the design of an effective filter cake breaker system and pumping operations based on the breaker diffusion/migration mechanism.
A Novel Application of Standard Surveillance Techniques to Formation Damage Control by Identifying the Location of the Obstruction and Quantifying Skin Type
Authors: Gonzalez Fabio , Gonzalez Doris , Pietrobon Marney , Yilmaz Timur , Pecoraro Jered , Stewart Carlos , Giles Duvivier 
Published: January 2016

Abstract
Asphaltene is a naturally occurring constituent of crude oil consisting of high molecular weight components which in most cases are in equilibrium within the liquid phase at initial reservoir conditions. As crude oil is produced and the energy of the reservoir depletes, the equilibrium is distressed and asphaltene can precipitate out of the liquid phase. Precipitation of asphaltenes is a condition for asphaltenes deposition, but precipitation will not always result in deposition. Deposition of asphaltene has the potential to negatively impact productivity of oil wells up to the point of completely shutting in production if the problem is not identified on time and mitigated and/or treated properly. The objective of this work is to present a systematic process for data acquisition and data analysis to identify the region in the well production system where asphaltene deposition is occurring leading to a properly designed operating strategy for production and interventions.
In order to identify and mitigate (or treat) the organic damage caused by asphaltene deposition near the wellbore, a methodical surveillance plan has been developed to acquire and interpret the required information at the right stage of the oil field development. The methodology consists of combining two different approaches: 1) Laboratory analysis of reservoir fluid samples using near infrared (NIR), high pressure microscope (HPM), and particle size analysis (PSA); and 2) Pressure transient analysis and multi-rate testing.
This procedure has allowed us to determine when skin develops and where in the well production system between the perforations and the downhole gauge asphaltene deposition is occurring. Specifically, we have been able to integrate results of asphaltene onset pressure (AOP) with quantification of total damage and the evolution of Darcy versus non-Darcy skin to identify if damage is worsening in the formation rock or anywhere below the permanently installed downhole pressure gauge. This paper presents an innovative approach as the integration of reservoir fluid characterization; pressure transient analysis and multi-rate testing have been combined to fully assess the damage mechanism, location of the damage, and the evolution of damage as a function of cumulative production. As a result of this methodology we have been able to properly design and schedule treatments to enhance well productivity and extend the longevity of the wells without exorbitant operating expenses and unnecessary downtime. Individually, these interventions have generated economic value and greatly increased the worth of deepwater oil fields in the Gulf of Mexico through sustainable delivery.
Near Wellbore Damage and Types of Skin Depending on Mechanism of Damage
Authors: Patel Mahesh Chandra , Singh Aaditya 
Published: January 2016

Abstract
Near wellbore damage has been a topic of great attention over last many decades. Typical measures of formation damage is skin factor (S) which is a hydrodynamic parameter characterizing additional resistance to flow of fluids in the near borehole zone of the reservoir, leading to reduced production (yield) compared to the perfect (ideal) wells. This has been a great attention of topic because it directly effects on formation fluid productivity from the concerning well. Reasons behind formation of this damage can be combinations of several mechanisms are clay particle swelling, fluid loss or change in formation water saturation, wettability reversal, Emulsion blockage, Mutual precipitation of soluble salts in wellbore-fluid filtrate and formation water, Deposition of paraffins or asphaltenes, Fines migration etc. Operations which are usually leads to those mechanisms to happen are drilling, cementing, well completion, work-over operations, production of fluids, injection of fluids and Operations to isolate water production etc.
This paper describes mechanisms of the formation damage. And introduces types of skins depending on the mechanism of damage and source operation, and Types of skin are The mechanical or formation damage skin factors (Sd)Completion pseudo skin factor (Sp)Partial penetration skin factor (Spp)-Geometrical pseudo skin factor (Sg)Multiphase pseudo skin factor (Sm)Non-Darcy flow or Rate-dependent high velocity or turbulent flow pseudoskin factor (Sturb)
This paper also describes all type of skin in detail with mathematical models given to calculate the skin individually as well as effective skin.