bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effect of Core Dimensions on the Optimum Acid Flux in Carbonate Acidizing
Authors: Dong K. , Jin X. , Zhu D. , Hill A. D. 
Published: June 2014

Abstract
The results of matrix stimulation in carbonate formation strongly depend on the acid injection condition. Large amounts of lab tests indicate that an optimum acid interstitial velocity, vi-opt, exists, which results in the minimum volume of acid required for wormhole propagation (optimal breakthrough pore volume) and the most efficient stimulation. During the last decade, much progress has been made to identify the factors that affect the optimum conditions of linear coreflood experiments, including temperature, acid type, acid concentration and lithology. However, there lacks a discussion on the effect of core dimensions on the optimal conditions. Experimental results published before show strong evidence that the optimal condition changes as the dimension of core samples changes. Since the optimal condition from experimental studies is the critical information used in treatment design, it is necessary to investigate the relationship between the optimal condition and the core geometry.
In this work, a series of coreflood experiments were conducted with Indiana limestone cores at room temperature. The cores selected are relatively homogeneous to eliminate the effect of heterogeneity. The acid used is 15% plain hydrochloric acid. The core lengths range from 1-in. to 10-in. and the core diameters are 1-in., 1.5-in. and 4-in. From the experimental results, the effects of core length and core diameter are examined. The results showed that the vi-opt becomes independent of the core length when the core length reaches a value of 6 inches. These observations can help with the recommendations of the proper core length and core diameter to be used in future laboratory experiments.
The core-size dependence is important while scaling up the laboratory results to field applications. The results of this work can give a better understanding of how upscaling works. Also, with these results, the existing wormhole growth models can take into account the core-size dependence, resulting in more accurate upscaling of experimental results.
Solid Paraffin Inhibitors Pumped in Hydraulic Fractures Increase Oil Recovery in Viking Wells
Authors: Wornstaff V. , Hagen Scott , Ignacz T. , Chorney M. , Pedersen Barett 
Published: June 2014

Abstract
The Viking formation in southern Saskatchewan Canada represents an active area where steep production declines in the first year of production are common and are often attributed to wellbore or near-wellbore precipitation of paraffin. Excessive decline rates within the first year on production have been observed.
A producer was experiencing paraffin deposition in the wellbore and suspected it to be the reason for production declines. Conventional treatments targeted at wellbore deposition were carried out with little effect on production rates. In an effort to improve production rates horizontal treatments were attempted. These treatments resulted in brief increases in production (up to 6 weeks). Horizontal treatment success led to investigation into other treatment options. Precipitation in the formation may contribute to reduced conductivity and, therefore, lower oil production rates. Solid paraffin inhibitors delivered via hydraulic fracturing offered the best potential for success in new wells.
The chemical additive treatment was designed through product selection testing using cold finger deposition tests, compatibility testing with the hydraulic fracturing fluid system, and proppant crush prediction models. A baseline of the untreated oil characteristics was determined using offset wells. Pour point, carbon number distribution and wax percentage were analyzed in offset untreated wells and each treated well. Production trends were used to track the performance of the treatments. The solid inhibitor application effectively prevented conductivity restrictions due to paraffin precipitation issues in the proppant pack.
Placement of solid paraffin inhibitors into the Viking formation with the proppant during hydraulic fracturing increased cumulative production by approximately forty percent in the first 350 days on production and reduced decline rates. Comparing 150 untreated wells with the 90 wells treated with the solid paraffin inhibitor in 2012 has increased revenue by about 15.8 million USD over the 350-day period. Wells drilled in the same area, with similar frac treatments, depths, horizontal lengths and stages were compared.
Fines Migration in Oil and Gas Reservoirs: Quantification and Qualification Through Detailed Study
Authors: Byrne Michael , Rojas Elinor , Kandasamy Ram , Gibb Angela 
Published: June 2014

Abstract
Fluid flow through oil and gas reservoirs can induce movement of parts of the rock within and through the pore network. This movement or "fines migration" can have a significant impact on well and reservoir performance. Laboratory testing and detailed mineralogical study can help with quantification and qualification of the potential for and impact of fines migration. Laboratory core flood testing can be used to try to predict the potential for fines migration in any fluid phase and at any velocity. The design of the tests and the limitations of such testing need to be considered before data is too rigidly employed. Ideally, tests should be conducted with the same fluids as will be present in the reservoir, under the same temperature and pressure conditions (including consideration of depletion) and the flow rates carefully selected to replicate reservoir velocities. If tests are conducted carefully then various conclusions on the impact of fines migration on well and reservoir behaviour can be drawn. Several new cases will be presented that demonstrate the potential use of good data and the danger in badly designed tests.
Definition of the size, shape and composition of mobile fines is important in order to understand the potential impact of the fines. Quantification of potential mobile fines is useful but data must be carefully analysed. High fines content is an indication of potential fines migration damage risk but is by no means a definitive predictor. Instead, mineralogical identification needs to be coupled with physical flow testing in order to identify the risk.
If good quality data is acquired the risk of fines migration damage or excessive fines production can be identified and in some cases, appropriate mitigation against fines migration can be adopted. Several cases from oil and gas production wells and water injection wells will be used to illustrate best practice and identify the consequences of inadequate testing.
Development of a Dynamic Model for Drilling Fluid's Filtration: Implications to Prevent Formation Damage
Authors: VasheghaniFarahani Mehrdad , Soleimani Rasa , Jamshidi Saeid , Salehi Saeed 
Published: June 2014

Abstract
Drilling mud plays an important role in drilling operations. Forming a thin layer called mudcake is one of these roles which prevents the aquatic phase of drilling mud called mud filtrate from penetrating through the reservoir rock and therefore reduces the damage caused by that work. So knowing about the mudcake characteristics such as thickness, solid contents and also filtration rate of mud filtrate will help the drilling engineer.
Factors affecting filtration process are time, temperature and pressure. In this paper, a mathematical model will be presented which estimates mudcake thickness and filtration radius in both static and dynamic conditions with consideration a radial system at constant temperature conditions. The mudcake thickness and permeability variation with time are also considered in the dynamic model.
Particle Size Distribution Measurement Techniques and Their Relevance or Irrelevance to Sand Control Design
Authors: Zhang Ke , Chanpura Rajesh A. , Mondal Somnath , Wu Chu-Hsiang , Sharma Mukul M. , Ayoub Joseph A. , Parlar Mehmet 
Published: June 2014

Abstract
Sand particle size distributions (PSD) are used for various purposes in sand control: decision between various sand control techniques, sizing of the filter media (sand screens and/or gravel packs) through either rules of thumb or physical experiments or theoretical models. PSD of formation sand samples are also often used to generate "simulated" formation sand for laboratory experiments. The two most commonly used techniques for PSD measurements are sieve and laser, while some engineers use one technique for no obvious or justifiable reasons, others use both techniques for measurements and don't know what to do with the data when significant differences exist in PSDs obtained from each technique. Although the inherent limitations of, and the differences between, these two techniques as well as other factors impacting the measurements are well known, a systematic study as to what is relevant to sand control and why, is lacking.
In this paper, we critically review the current practices in PSD determination, use (and misuse) of the information obtained from these measurements, propose a methodology towards determining what is relevant, when and why, and present initial experimental results that support our conclusions.
Field Treatment to Stimulate an Oil Well in an Offshore Sandstone Reservoir Using a Novel, Low Corrosive, Environmentally Friendly Fluid
Authors: Nasr-El-Din H. A. , Dana H. , Tomos V. , Stanitzek T. , de Wolf C. A. , Alex A. 
Published: June 2014

Abstract
Acidizing in sandstone formations is a real challenge for the industry. Fines migration, sand production, and additional damages due to precipitation are some of the common concerns with sandstone treatments. Furthermore, the complexities of sandstone formations require a mixture of acids and loadings of many additives. The environmentally friendly chelating agent, glutamic acid N,N-diacetic acid, GLDA, was successfully used to stimulate deep gas wells in carbonate reservoirs. It was extensively tested in the lab to stimulate sandstone cores with various mineralogies. Significant permeability improvements were reported in our previous papers over a wide range of conditions. In this paper, we evaluate the results of the first field application with a fluid based on this chelating agent to acidize an offshore, sour oil well in a sandstone reservoir.
The field treatment included pumping a preflush of xylene to remove oil residues and any possible asphaltene deposited in the wellbore area, followed by the main stage that contained 25 wt% GLDA, a corrosion inhibitor, and a water wetting surfactant. The treatment fluids were displaced into the formation by pumping diesel. Following the treatment, the treatment fluids were allowed to soak for 6 hours, then the well was put on production, and samples of flowback fluids were collected. The concentrations of key cations were determined using ICP, and the chelate concentration was measured utilizing a titration method using ferric chloride solutions.
Corrosion tests conducted on low carbon steel tubulars indicated that this chelate has low corrosion rates under bottomhole conditions. No inhibitor intensifier was needed. The treatment was applied in the field without encountering any operational problems. A significant gain in oil production was achieved without adversely impacting the water cut, causing sand production, or fines migration. Analysis of flowback samples confirmed the ability of the chelating agent solution to dissolve various types of carbonates, oxides, and sulfides, while keeping the dissolved species in solution without causing unwanted precipitation. Unlike previous treatments conducted on this well, where 15 wt% HCl or 13.5/1.5 HCL/HF acids were used, the concentrations of iron and manganese in the flowback samples were negligible, confirming the very low corrosion rates of well tubulars when using GLDA solutions.
Reduced Models for Description of Invasion Zone Geomechanics
Authors: Bocharov Oleg , Seryakov Alexander 
Published: June 2014

Abstract
This paper presents a coupled poroelastic model describing rock matrix deformation and two-phase filtration flow. The model has been derived based on mechanical principles of interpenetrated continuum and includes conservation laws written for the mixture components and constitutive equations in a form of the generalized Hook's law. The system has at least two spatial scales that define small quantity - scales ration. The small parameter decomposition has been utilized to obtain a series of approximate model corresponding to the special deformation condition. The zero-order approximation describes porous media with invariant volume. One also has obtained and analyzed an analytical solution in cylindrical coordinates for the zero volumetric deformation. The periodicity along radius stresses and pore pressure distribution in this solution demonstrate a possibility of disruption zones appearances not only at the borehole wall but also at some distance deeper in the rock. Its first-order approximation under a compact phase incompressibility assumption produces a generalization of the Buckley-Leverett two-phase filtration model with porous space deformations taken into account. The reduced poroelastic models presented enables a quick solution for mechanics and fluids-dynamics problems of invasion zone.
Experience of Carbonate Acidizing in the Challenging Environment of the Volga-Urals Region of Russia
Authors: Kayumov Rifat , Konchenko Andrey , Bairamov Alexey , Klyubin Artem , Levanyuk Olesya , Chikin Andrey , Firsov Vladislav , Nikulshin Evgeniy 
Published: June 2014

Abstract
The Volga-Urals basin is one of the largest oil-producing regions in Russia. Orenburg region is essential part of Volga-Urals basin and it represents most of the challenges encountered in the other parts of the basin. More than half the wells produce exclusively from carbonate formations and require periodic acidizing treatments to maintain economic production. Carbonate stimulation treatments are usually based on pumping of hydrochloric acid into the formation with use of special diverters to maximize zone coverage by acid treatment. Some of the formation properties in Volga-Urals basin create additional challenges for successful acidizing treatments, including significant reservoir pressure depletion, high water cut, formation heterogeneity with high- and low-permeability strikes, low reservoir temperature, crude with tendency for emulsion and sludge creation, and enormous thief zones created by previous acidizing treatments. In many cases, uncertainties in the formation properties make the stimulation more complex.
Carbonate stimulation practices in the Orenburg region have continuously improved during the last 6 years. First, degradable balls and polymer self-diverting acid were introduced to improve zone coverage. Later, viscoelastic self-diverting acid was added to eliminate damage associated with the polymer, and a viscoelastic selective diverter was used to minimize the probability of an increase in water cut after the treatment. Finally, foam was placed as a diversion agent, with and without coiled tubing (CT), to account for reservoir pressure depletion and help in post-acidizing flowback. Many lessons were learned, resulting in recommendations for use of various technologies at different reservoir and wellbore conditions.
In addition to the recommendations for technologies, a quality assurance and quality control (QAQC) standard was developed and implemented for acidizing treatments. Moreover, laboratory work such as core flow testing and proppant embedment tests has been undertaken to clarify post-treatment aspects.
Most fields in the Orenburg region are old, which implies that quality of well candidates became worse from year to year. However, with continuous improvement in stimulation practices and rigorous quality control we manage to maintain production at economic level and even increase work scope compared with previous years. This paper presents the experience gained during the 6-year of acidizing treatments in Orenburg region with lessons learned, and best practices adopted.
Challenging the Economic Limit in Mature Fields by Hydraulic Fracturing of Wet Producers
Authors: Rachid R. , Milne A. , Ali S. , Ramones M. , Jimenez J. 
Published: June 2014

Abstract
In Ecuador there are mature subhydrostatic sandstone reservoirs that have lateral water drive or that are located close to the oil/water contact. With time the water saturation has increased and water breakthrough is common in high-permeability streaks, causing the water cut to increase substantially. In these fields the challenge is to increase oil production and recoverable reserves through stimulation without increasing the water cut. For this reason, until recently, hydraulic fracturing was not considered a viable option. Although conventional acid treatments increased oil production, they also increased the water cut, sometimes making the production uneconomical. To overcome this, either acid treatments with diverter stages are used to selectively stimulate the oil-saturated intervals or relative permeability modifiers are used to limit water production. However, these have not proved to be reliable solutions.
To hydraulically fracture wet producers, a linear fracturing fluid was introduced. The fluid is formulated with low concentrations of a disproportionate permeability modifier (DPM) or a relative permeability modifier (RPM), and guar polymer creates a pseudoviscoelastic disproportionate permeability modifier (VDPM). The VDPM reduces the effective permeability to water in the fracture faces, and the relatively low viscosity of the fluid limits the net pressure and the risk of fracture height growth, without compromising proppant transport. The viscosity and leakoff control of the fluid can be adjusted as a function of the formation properties, leak-off and stress profile.
The first hydraulic fracturing campaign of eight wells using the VDPM fluid was in the Hollin formation, which has a strong aquifer below it and in some cases a lateral aquifer. Typically, the upper section produces oil and the lower section is water saturated; the distance between the two sections is 5 to 25 ft. On average the oil production increased threefold and the water cut was not increased after the fracturing job, in spite of the proximity to the wet zone. While the results of matrix treatments with RPMs in wet producers are notoriously mixed, hydraulic fracturing with a VDPM fluid has proved a reliable means to selectively increase oil production in the presented case. This has had a very positive impact on the economics and reserves recovery in these marginal mature fields.
Optimizing Surfactant Additives for Enhanced Well Stimulation in Bakken Formation
Authors: Morsy Samiha , Zhou Jia , Lant Kimberly , Cutler Jennifer , Sun Hong , Qu Qi , Shuler Patrick 
Published: June 2014

Abstract
The Bakken reservoirs represent a large untapped resource of oil. One of the challenges is extracting the crude oils from their low-permeability formations at economic rates. These reservoirs contain multiple pay zones, including some with carbonate (dolomite) lithology. Recent common practice is to drill horizontal wells and perform a series of large, multi-stage hydraulic fracture treatments. The fractures penetrate deeply into the reservoir and promote more efficient drainage of the oil. This situation suggests that a surfactant technology designed to enhance oil recovery from fractured carbonate formations is a fit for these typical Bakken cases with Middle Layer complex fractured lithology. The concept of this technology is to incorporate appropriate surfactant formulations at a low dosage in the well stimulation fluids. If properly designed, such additives in the fracture fluids will penetrate into the highly oil-saturated matrix or natural fracture region and accelerate the extraction of the oil in place by rapid imbibition. This extracted oil can readily move from the matrix into the propped fracture system to be produced. Another benefit of the additive is its engineered property to leave the matrix or natural fracture face water-wet to facilitate oil movement during production.
This paper presents a study of a series of such stimulation fluid additives developed for enhanced oil recovery. Over 10 special customized product blends were evaluated in the laboratory for effectiveness in increasing recovery of Bakken crude oil samples. Tests included compatibility with formation brine, emulsion tendency, recovery factors from spontaneous imbibition with crude oil and formation brine, and compatibility with proposed fracturing fluids. These results show that more than one of these products improve recovery of Bakken crude oil by spontaneous imbibition from both outcrop limestone cores and from Bakken core material. The best of these products is recommended for field application.
Successful Treatment of a Green River Sandstone Formation Using a Novel Low-Polymer Crosslinked Fluid
Authors: Legemah Magnus , Debenedictis Frances , Workneh Nigatu , Smith David , Le Hoang , Sun Hong , Qi Qu , Moulton Mickey 
Published: June 2014

Abstract
Guar-based fracturing fluids are the most commonly used fluids in reservoir stimulation. To provide high viscosity, borate crosslinked gels are preferred for their ability to heal after mechanical shearing and their favorable environmental properties. More efficient crosslinkers capable of cross-linking fluids with reduced polymer loading have always been of great interest to reduce formation and proppant pack damage from polymer residues, and to reduce overall fluid cost.
Low permeability and the interwell connectivity of Green River sandstone formations of the Uintah Basin require hydraulic fracturing treatment to economically produce oil. The most typical fracturing treatments use guar crosslinked borate fluids to transport sand into wells with vertical depths of 3500-6,800 feet and bottom-hole temperatures of 115-160°F. Most operators in this area place emphasis on reduced polymer loadings for stimulation treatments; and even with breakers present, broken polymer residues can remain in the formation even at these reduced polymer loadings, resulting in damage and decreased production. The stimulations for these wells are flow backed at the end of the last stage. This poses a challenge of a proper balance between polymer and breaker loading, so that the fluid effectively transports up to 6 pound per gallon added (ppa) of sand into the formation without screen out, and breaks within the treatment time (30-40 minutes per stage) to minimize flow back of proppant.
Recently developed novel poly-aminoboronate crosslinker (also reported in SPE 140817 and SPE 164118) was tested in the aforementioned formation. Multiple boron sites are available in the crosslinker and it is capable of interacting with multiple polysaccharide strands to form more complex crosslinking networks at lower polymer loadings than conventional guar fluids. The crosslinker with up to additional 15% reduced guar loading is capable of matching or out performing conventional crosslinked fluids in fresh water and more impressively in 7% KCl. This paper will discuss the novel crosslinker developed, the laboratory testing and successful field application. Analysis and discussion of the chemistry, crosslinking performance and economics will be presented.