bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful Water-Shutoff Case Histories in a Naturally Fractured Carbonate Reservoir in Offshore Mexico Using an Organically Crosslinked Polymer System With a Modified Tail-In
Authors: Hernandez R. , Vasquez J. , Cancino V. , Soriano E. 
Published: February 2010

Abstract
This paper presents the laboratory development and successful field implementation of an organically crosslinked polymer (OCP) system for water- and gas-shutoff applications. An overview of case histories in a naturally fractured carbonate reservoir (with BHT &gt;250°F) in offshore Mexico where the OCP was successfully applied to reduce water production is presented. To control overdisplacement of the treatment, a modified tail-in combining the OCP system with inert particles was used to provide leakoff control, resulting in a controlled placement of the sealant.
The OCP system is based on a copolymer of acrylamide and t-butyl acrylate (PAtBA) crosslinked with polyethyleneimine (PEI). To date, more than 600 jobs have been performed with the OCP system around the world to address conformance problems, such as water coning/cresting, high-permeability streaks, gravel-pack isolation, fracture shutoff, and/or casing-leak repair. The development results of this OCP system are discussed regarding its activation time and its effectiveness to limit permeability to water and provide thermal stability in sandpack flow tests at elevated temperatures. Lastly, the combination of the OCP system with inert particulates to provide fluid-loss control is discussed.
The OCP system has been successfully applied to sandstone, carbonate, and shale formations in need of conformance treatments. This system has been successfully tested to withstand a differential pressure of at least 2,500 psi and is resistant to acid, CO2, and H2S environments. Because of the ability of the OCP system to withstand pressure, workover operations have been successfully performed in previously treated wells including acid-stimulation, sand-control, and frac-packs treatments, among others. An overview of case histories in which the OCP system was used in offshore Mexico is presented. This advanced water-control technology has extended the well life and profitability of the treated wells. In the past, many of these wells were abandoned because of the limited water-handling facilities.
Dynamic Scaling Evaluation in Gravel Packs Using Low-Sulphate Seawater
Authors: Shields R. , Bourne H. , Vazquez O. , Sorbie K. , Singleton M. 
Published: February 2010

Abstract
In fields where it is unattractive to control barite scaling through chemical intervention (e.g. scale inhibitor squeeze treatments), one option is to substitute the injection of seawater with low-sulphate seawater (LSSW) for pressure maintenance. Injecting LSSW minimises the operational risk of barite deposition on injection water breakthrough. The specification for the LSSW sulphate ion concentration dictates the design of the Sulphate Removal Plant (SRP) required and may influence the field development strategy. There is the possibility that barite deposition can occur within gravel packs designed to minimise sand production. It is in these that the potential for scaling was investigated.
Dynamic scaling runs were performed in laboratory scale gravel packs using a mixture of a Formation Water (FW) and LSSW. The initial design involved varying the total flow rates and mixing ratio of the brines in order to produce a 'safe envelope' (Ba2+/SO42- composition) that could be used in the field. The experimental procedure was developed to examine the steady-state effluent profiles and to use these to derive the rate constant, k, for barite deposition. This could then be used in a computer model to predict scaling quantities and timescales.
Under 'true' LSSW conditions (20ppm sulphate) the steady-state effluent results proved difficult to interpret due to the limits of accuracy. The sulphate levels were then varied in order to increase the level of accuracy, with the hypothesis that, for a given set of conditions (temperature and pressure), the rate "constant" should remain the same for any Saturation Ratio (SR).
Upon closer inspection of the derived rate constants, it was discovered that they were not constant but were directly proportional to the SR for the different input concentrations. Plotting the rate constants against SR showed a linear relationship between the two variables. This was confirmed by using sulphate and barium levels that were unrelated to the previous series of tests.
The experimental procedure and the resulting model being developed from the work reported in this paper will assist in designing operational procedures to minimise rate related scaling in gravel packs in fields where squeezing is undesirable.
A New Method of Grain Size Determination for Sand-Control Completion Applications
Authors: Chen J. , Chen S. , Altunbay M. M. , Tyurin E. 
Published: February 2010

Abstract
Grain size distribution of formation sands is one of the crucial parameters in a sand control program. Such information is commonly derived from sieve or laser particle size analysis (LPSA) techniques on a limited number of core samples from the target well or from a neighboring well in the same field. These laboratory-based grain size analysis methods require proper disaggregation of grains, a process which often causes breakup of some grains resulting in distortion in the grain size distribution. Moreover, variations of grain sizes in the formation may not be captured by the limited number of core samples.
This paper presents a new method of grain size determination from nuclear magnetic resonance (NMR) logs using micro-structural rock modeling (MSRM). NMR probes the pore space as the relaxation time distribution of the wetting-phase fluid correlates to pore size distribution while the non-wetting phase fluid carries no pore size information. To derive grain size distribution from NMR relaxation time measurements, MSRM is applied to reconstruct the pore/grain distribution and to simulate NMR responses by considering mineralogy, partial water saturation, surface relaxivity, and the surface roughness factor of the grains. Extensive core studies were performed to validate this method. A ternary diagram is developed to correlate surface relaxivity and the surface roughness factor with the amount of quartz, feldspar, and clay as a triangle in the ternary diagram.
Field application case examples are presented. Continuous grain size distributions are calculated on foot-by-foot basis that capture the variations of grain size in the formation sands along the depth. The log-derived grain size distribution shows good agreement with the core data at depths where core samples are available. D50 and D90 characteristics are derived from the continuous grain size distributions to assist the completion decisions, e.g., the selection of screen mesh size in the openhole standalone screen sand-control approach, or the selection of gravel size in the gravel-packing sand-control approach.
Two-Dimensional Analytical Solution of Ideal Perforation Flow
Authors: Li B. , Sun D. , Gladkikh M. , Wu J. 
Published: February 2010

Abstract
Core flow efficiency (CFE) is defined to quantitatively evaluate the flow performance of single-shot perforation. To calculate CFE, the flow rate of the ideal perforation flow in the core target is needed. The ideal flow rate is typically calculated with numerical simulators, but the computation may be time-consuming and costly.
This paper presents the two-dimensional analytical solution of the steady state flow model (mass conservation equation) for the ideal single-shot perforation in a cylindrical core sample. The separation of variable method is used to solve the partial differential equation of the flow model. Pressure and velocity distributions in (r, z) space are obtained, as well as the flow rate distribution along the perforation tunnel.
The accuracy and convergence of the analytical solution for the ideal single-shot perforation flow are investigated and compared with those of the numerical solution of the commercial software ANSYS FLUENT. The analytical solution for the governing equation of the ideal perforation flow is composed of the infinite number of Bessel functions. To compute the CFE by making use of this analytical solution, the analytical solution is approximated with a limited number of Bessel functions. The approximated analytical solution is analyzed and compared with the numerical solutions from ANSYS FLUENT.
Further, the axial, radial, and radial-axial flow geometries of the ideal shingle-shot perforation are characterized with their approximated analytical solutions. Interactions between the boundary condition, perforation parameters, and core parameters are investigated for these flow geometries.
The analysis results show that: 1) the analytical solution has no grid effects; 2) the boundary condition of the perforated core is the dominant factor to the ideal flow rate of the perforated core; 3) the penetration depth and anisotropic permeability are the significant factors to the flow performance of the perforated core.
Development and Field Applications of an Aqueous-Based Consolidation System for Proppant Remedial Treatments
Authors: Villesca J. , Loboguerrero S. , Gracia J. , Hansford A. , Nguyen P. D. , Rickman R. D. , Dusterhoft R. G. 
Published: February 2010

Abstract
Proppant produced during production often causes damage to downhole pumps and surface equipment. In addition to restricting production rate, frequent workovers are often required to remove proppant or sand infill, thus resulting in costly downtime. To help resolve these proppant production problems, solvent-based curable resins have often been used in remedial treatments of affected wells. These resin systems have been applied in intervals of less than 100 ft. For longer intervals, ineffective diversion of solvent-based resins and their potential interaction with water in the wellbore can prevent them from providing complete coverage over the entire perforated interval.
A novel water-based consolidation system has been successfully developed to overcome safety, fluid compatibility, and placement issues, which most current solvent-based resins encounter during their field applications. This paper presents the results of laboratory testing and field applications and discusses the challenges, lessons learned, treatment procedures, and recommendations in applying this newly developed resin system.
The curable consolidation component is emulsified to form a water-external emulsion so that the active material can be delivered in a brine-based solution. Extensive laboratory testing has indicated that optimum concentration of coating is necessary to maximize the bonding between proppant grains. This allows the proppant pack to withstand high production flow rates and to overcome the effects of stress cycling while minimizing any reduction in its permeability. Results from field trials showed that this aqueous-based consolidation system successfully treated both proppant and formation sand in near-wellbore regions to lock them in place without damaging production flow paths. In these field tests, intervals in excess of 300 ft were treated effectively with a bullhead squeeze using consolidation-treatment fluids that were foamed to a quality of 50 or higher to aid in diverting treatment fluids and extending treatment volume.
One major advantage of this aqueous-based system is its simplicity in field treatments without the concern of fluid incompatibility between fluid stages during their placement because of its benign behavior. The new system uses small treatment volumes to impart excellent consolidation properties while, at the same time, retaining formation permeability. This makes the treatment system simple to deploy and economically viable.
Laboratory Investigation of Brine Diffusion Through Oil-Based Mud Filter Cakes
Authors: Berntsen A. N. , Robbes A.-S. , Cerasi P. R. , van der Zwaag C. H. 
Published: February 2010

Abstract
When gravel packing wells in brine after an oil-based drill-in, filter cake strength and permeability are important factors for successful operations. These relate to controlling fluid losses, firstly, by resisting mechanical wear when running production screens and, secondly, by providing a tight hydraulic seal when pumping gravel.
Two oil-based mud formulations with "initial" and "depleted" bridging packages, respectively, and otherwise equal formulation, were used to deposit filter cakes on outcrop sandstone plugs in a Hassler-type core holder. Drilling mud was then displaced by gravel pack carrier brine keeping an overbalance pressure. Brine was allowed to permeate through the oil-based filter cake. The filter cakes before and after exposure to brine were compared in terms of cake strength, and volume of brine produced through.
It was found that brine transport through the filter cakes at the same overbalance pressure was slower than the static mud filtration rate. Scratch tests showed a higher strength for the filter cake formed with the "initial" particle size distribution, and that both filter cakes strengthened significantly following brine diffusion. NMR T2 distributions and 1D NMR intensity profiles showed that core plugs exposed to the mud formulation with "depleted" bridging package experienced stronger alterations in NMR properties and deeper damage than the formulation with the "initial" bridging package.
The methods used in this study have shown to have the potential of probing some of the mechanical and hydraulic properties of filter cakes and the extent to which core plugs are invaded by mud particles during filtration and filter cake buildup. Future work will address the effect of different base fluids, water-based or oil-based, and of different bridging packages to improve our understanding of how the fluid basis affects filter cake qualities. Other options are to look at the effect of wash pills on filter cake properties.
A Theoretical and Experimental Analysis of Dynamic Filtration in Drilling Operations
Authors: Scheid C. M. , Calcada L. A. , Araujo C. A. , Waldmann A. T. , Martins A. L. 
Published: February 2010

Abstract
This paper describes a numerical filtration model validated by data obtained from an experimental dynamic filtration loop. The model predicts the filtercake buildup and filtrate flow rate in the drilling process using non-Newtonian muds. It is also able to calculate filtercake properties like permeability and thickness. The equations, written in cylindrical coordinate, are based on the motion and mass conservation equation of the fluid described by Darcy's law. In addition, the permeability and porosity are correlated to the filtercake pressure. The point at which the mud fluid shear rate and the filtercake shear strength are equal defines the filtercake thickness.
In the dynamic filtration loop there is a tube with a permeable wall where the carbonate suspension of different sized particles is filtrated. The suspension is homogenized in a tank mixer and pumped using a positive displacement pump. The filtration model was validated through experimental data. In this paper, we discuss the effects of cross-flow velocity and filtration pressure on the filtrate rate and filtercake buildup. The simulated data of filtrate rate and filtercake thickness agreed well with the experimental data.
Improved Selection Criteria for Sand Control - When Are "Fines" Fines?
Authors: Byrne Michael , Slayter Adrian , McCurdy Philip 
Published: February 2010

Abstract
When sand control is required in production or injection wells, one of the key design criteria is that the sand control should allow those "fines" present to pass, whilst retaining "sand". However the definition of "fines" is not universal and some arbitrary size and/or compositional definitions are often used that could potentially lead to inappropriate sand control design.
The fines in any rock sample are usually categorized as that portion of the rock which passes through a ~45 micron sieve. This is a convenient cut-off point for laboratory evaluations as it represents the finest commonly used sieve. It has become routine to use the percentage of fines in a rock sample as one of the key parameters for sand control type selection and specific screen selection. In a coarse-grained, well-sorted sand, particles "less than ~45 microns" may well represent that part of the rock that can move through the pore throats. However, significant variation exists in oil and gas reservoirs and this should be considered in order to obtain an appropriate definition of what constitute fines for a specific reservoir. From a reservoir perspective, the preferred definition of "fines" is that part of the rock that can move through the pores of the intact rock.
Using pore throat size measurements and estimates, it is possible to develop a much more rigorous mobile fines size for any formation. Coupled with grain size analysis (which should include some laser analysis of the finer fraction) the true "fines" can be quantified for any given sand. The sand control selection is made using this new definition of fines, leading to optimum and tailored selection, based on science rather than convenience or tradition. For sand control performance evaluation it is not only the mobile reservoir fines that are a concern. Should the formation fail into an annulus then the rock components may re-sort in the annulus and bring about high skins and possible screen plugging. Here, the sizing of the fines that are of concern will be different.
It has been convenient to adhere to somewhat arbitrary particle size distribution cut-off points when selecting sand control. When informed with an improved understanding of the petrology, particle behaviour, impact of their movement, and the interaction between the formation and the well, while it is being both constructed and produced it is proposed that we can improve the selection process.
Propagation and Retention of Viscoelastic Surfactants Following Matrix Acidizing Treatments in Carbonate Cores
Authors: Yu M. , Mahmoud M. A. , Nasr-El-Din H. A. 
Published: February 2010

Abstract
Viscoelastic surfactants have been applied extensively in the field, because of their unique characteristics of forming rod-like micelles with the increase of pH and calcium concentration. There is continuous debate in the industry on whether the gel generated by these surfactants causes formation damage or not. This is especially true in dry gas wells. The objective of the present study is to conduct core flood experiments using surfactant-based acids and measure the concentration of the surfactant concentration in the core effluent. Material balance on the surfactant will shed lights on the amount of surfactant recovered, which will help in assessing damage due to surfactant gel retention in the cores.
Core flood tests were performed using calcium carbonate cores 1.5 in. diameter and 20 in. length. The cores were injected with a surfactant-based acid of 15 wt% HCl that contained 7 vol% surfactant and other acid additives. Core flood test were conducted at constant injection flow rate that was varied from 3 to 40 cm3/min. Carbonate cores of various initial permeability were used. In all core tests, surfactant concentration was measured in the injected acid and core effluent using the two-phase titration method. Mutual solvent was used to break surfactant gels. Considerable amounts of viscoelastic surfactant were retained in the carbonate cores after the acid treatments, and the retained surfactant gel is a source of formation damage if not effectively removed. The amount of surfactant-based acid required to create wormhole in carbonate matrix is high at both low shear rate (&lt; 900 s-1) and high shear rate (&gt; 3,000 s-1), and is low at intermediate shear rates with the minimum value at shear rate of 1,500 to 2,000 s-1. The surfactant retention in the carbonate matrix is lowest at shear rates near 2,000 s-1, and is high at both high and low shear rates. Surfactant was retained in gelled form. Mutual solvent was able to remove as much as 21% of the total amount of surfactant injected into the core.
Enhancing Gas and Oil Production With Zeta Potential Altering System
Authors: Johnson D. , Schoppa D. , Garza J. , Zamora F. , Kakadjian S. , Fitzgerald E. 
Published: February 2010

Abstract
This paper describes laboratory studies and field results of a Zeta Potential Altering System (ZPAS) used in hydraulic fracturing treatments. Laboratory and field results show ZPAS minimizes proppant flow back, controls fines migration, enhances fluid load recovery, and inhibits calcium carbonate scale formation. This system, based on an inner salt, modifies the zeta potential of particles such as frac sand and formation substrate, changing the charge towards neutral values and therefore enhancing particle agglomeration. A variety of oil and gas formations can be treated by incorporating the new chemical additive into stimulation fluids. The chemical additive can be applied on the fly using several fluid systems to deliver the product. It is capable of treating proppants such as white and brown sand as well as ceramic proppants in any mesh size allowing flexibility in treatment design. A multi-well comparison of fractured wells, treated with ZPAS and of offset wells without the chemical, has been made in the Des Moines Granite Wash formation of the Texas Panhandle. In this study, results show wells treated with ZPAS had no significant proppant flowback compared to non-treated wells. In one case, a significant difference in production was observed from the ZPAS treated well compared to the untreated well.
Single-Trip Perforate and Frac-Pack Completion With High-Efficiency Frac Gel in Bonga Phase II
Authors: Janz H. , Ogunsina O. , Apena A. , Alawode O. , Bagal J. , Kouteu Y. , Mbiguis Y. , Bopda G. 
Published: February 2010

Abstract
The Bonga field is located offshore deepwater Nigeria. Part of the second phase of the development comprised five frac-pack treatments executed in a multi-darcy environment. With permeability variations from 1 to 7 Darcies, the salt-tolerant fracture fluid that was used for the frac treatments had efficiencies in the order of 40%, compared to 10 to 15% most commonly achieved in such treatments (Witteveld, 2004; Cipolla, 2005). Use of such a high-efficiency fluid resulted in substantial reduction in pump rates and horsepower requirements.
All five treatments were performed from a stimulation vessel, three of the treatments with the conventional two-trip technique and two using the single trip perforating and frac-packing technique. The single trip system allowed the completion time to be reduced by 1 to 2 days as compared with conventional system.
This paper discusses Bonga Phase 2 frac-pack treatments, with a comparison of the two techniques (single trip versus conventional) from a cost savings as well as well performance standpoints based on field applications. Design, execution and evaluation of the treatments are detailed, along with a discussion of the fluid system, and the lessons learned during the completions campaign.