Korean Otological Society

Introduction: Studies of isolated hunter-gatherers have found little evidence of the age-related rise in blood pressure (BP) that is common to Western societies, but none of these studies have included children or, for comparison, neighboring tribes exposed to Western culture. We tested the hypothesis that BP does not rise with age in isolated, hunter-gatherer Yanomami, and the age-BP slope is greater in neighboring Yekwana tribes that have some Western exposure. Methods: In the Upper Caura basin, a remote area of the Venezuelan Amazon, we sampled 438 participants from 5 isolated Yanomami-Sanema villages, accessible only by foot or canoe, and 3 Yekwana villages, 1 of which had a grass landing strip for small-engine planes, allowing for delivery of medicine and aspects of Western lifestyle, including salt. Trained researchers measured ausculatory sitting BP in triplicate per standard protocols, and height and weight to determine BMI (kg/m 2 ). We used ANCOVA to compare the age-BP slope between the Yanomami and Yekwana. Results: 154 participants (83 Yekwana; 71 Yanomami) ages 2-60 y (53% female) had data on age and sitting systolic BP (SBP). Age-SBP slopes were significantly different (p=0.02): in Yekwana, a 1-y age increment was associated with a 0.25±0.08 mmHg (p=0.003) increase in SBP ( Figure ), whereas in Yanomami age was not associated with SBP (1-y increment: 0.00±0.07mmHg; p=0.98). These results indicate that at age 10 y, mean sitting SBP was, on average, 5.8 mmHg lower for Yanomami compared to Yekwana, and that the average difference increased to 15.9 mmHg by age 50 y. BP differences between Yanomami and Yekwana remained after control for BMI. Conclusion: In isolated Yanomami with hunter-gatherer-grower lifestyles, BP does not increase with age over ages 2 to 60 y. Yet, among the Yekwana—the closest geographic neighbors of the Yanomami in whom Westernization is at the incipient stages—age is positively associated with BP, suggesting that the rise in BP with age may result in part from cumulative exposure to Western lifestyle.

Jae-Jun Song, Ja-Won Koo, Kyu-Sung Kim, Jae Yong Byun, Gyu Cheol Han and Sung Won Chae Sub-Committee on Meniere’s Disease, Quality Control Committee, Korean Otologic Society, Seoul; and Department of Otorhinolaryngology-Head & Neck Surgery, Dongguk University Ilsan Hospital, Goyang; and Department of Otorhinolaryngology, Seoul National University College of Medicine, Bundang Hospital, Seongnam; and Department of Otorhinolaryngology-Head & Neck Surgery, Inha University College of Medicine, Incheon; and Department of Otolaryngology-Head & Neck Surgery, Kyung Hee University College of Medicine, Seoul; and Department of Otolaryngology-Head & Neck Surgery, Gachon University of Medicine & Science, Incheon; and Department of Otorhinolaryngology-Head & Neck Surgery, Korea University College of Medicine, Seoul, Korea

The Successful Use of Polymer-Free Diverting Agents for Acid Treatments in the Gulf of Mexico Scott M. McCarthy; Scott M. McCarthy OSCA, Inc. Search for other works by this author on: This Site Google Scholar Qu Qi; Qu Qi OSCA, Inc. Search for other works by this author on: This Site Google Scholar Dan Vollmer Dan Vollmer OSCA, Inc. Search for other works by this author on: This Site Google Scholar Paper presented at the International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, February 2002. Paper Number: SPE-73704-MS https://doi.org/10.2118/73704-MS Published: February 20 2002 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation McCarthy, Scott M., Qi, Qu, and Dan Vollmer. "The Successful Use of Polymer-Free Diverting Agents for Acid Treatments in the Gulf of Mexico." Paper presented at the International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, February 2002. doi: https://doi.org/10.2118/73704-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search Dropdown Menu nav search search input Search input auto suggest search filter All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE International Conference and Exhibition on Formation Damage Control Search Advanced Search AbstractThe success or failure of a gravel pack or stimulation treatment performed in the Gulf of Mexico (GOM) is often times directly related to the ability of the diverting agent to force the treatment into different portions of the reservoir. Without the success of these diverter stages, entire treatments can be channeled into small portions of these "unconsolidated" reservoirs. Since most damaged intervals are often times the last intervals to be contacted by the acid, the treatment must be chemically forced to attack these intervals early in the treatment to insure proper stimulation and damage removal.Diversion of acid treatments in the Gulf of Mexico (GOM) have been predominantly accomplished by using either foam, HEC, or particulate matters to "temporarily" block off the zones and force the acid elsewhere. Foam and HEC are the preferred method of diversion due to their "low damaging" characteristics, but are severely hampered by temperature limitations. Foam diversions can also be difficult to control due to foam stability. Although HEC is essentially non-damaging, production can be hindered due to the viscous nature of HEC. Particulate matters such as carbonates, sized salts, and benzoic flakes are not as affected by temperature but can often times be difficult to remove and in some instances impede the production results.This paper describes the development of a new "solids-free non-damaging" diverting agent based on viscoelastic surfactants. The unique fluid properties of this system allow acid diversions to be tailored to specific well conditions and formation characteristics. By incorporating an internal breaker this system does not require contact with formation fluids, brines, or acids for clean up to provide optimum production. This paper describes the fluid properties at various pH's, temperatures, and salt concentrations along with several successful case histories.IntroductionPrior to the introduction of FracPacks in the GOM, standard sand control treatments would consist of a large acid treatment followed by placement of gravel in completion fluids, low-density brines, or linear gels. The success or failures of these treatments were often directly related to the ability of the acid treatment to remove near-wellbore damage and connect the wellbore to the formation.Prior to the actual sand control or stimulation treatment, expensive in-depth research was conducted on cores to determine the most effective combination of acid blends and volumes for each particular reservoir. Job design and planning was done to insure that the correct procedure was followed to insure that the acid was placed across the entire interval. Staging of the treatment was attempted to force acid across the entire interval, treating the damaged clean portion of the sands.It was often this portion of the treatment, the diverter stages, that was the most limiting or often times damaging portion of the treatment. As with most treatments injected into the reservoir below or above fracturing rates and pressures, the fluid will typically enter the region of lowest stress or highest permeability. In most cases this is the portion of the reservoir that will benefit the least from stimulation due to the apparent "cleanliness" of the sand. Fluid entering the damaged or less permeable zones will rely upon rate or the diverting agents to temporarily block the "clean" zones and force the fluid to other regions. Keywords: injection pressure, production enhancement, well intervention, qi qu, downhole intervention, viscosity, agent, injection, acidizing, upstream oil & gas Subjects: Hydraulic Fracturing, Reservoir Fluid Dynamics, Acidizing, Flow in porous media, Completion Installation and Operations, Well Intervention, Well Operations, Optimization and Stimulation This content is only available via PDF. 2002. Society of Petroleum Engineers You can access this article if you purchase or spend a download.

Abstract Because of the problems associated with hydroxyethyl cellulose (HEC), several water soluble polymers were evaluated to replace HEC used to viscosify completion and workover fluids. The rheological properties and formation damage tendencies of these polymers were initially tested in dry form in various brines at elevated temperatures. Then the same polymers were prehydrated and re-evaluated in high dense brines (above 11.6 ppg). The results showed that HEC is no longer the preferred polymer. The preferred polymer at equal polymer concentrations outperformed HEC in nearly all cases based on rheological and formation damage tests. The preferred polymer does not have a tendency to precipitate at elevated temperatures like HEC does in sodium and potassium chloride solutions and unlike HEC can viscosify brines containing a particular concentration range of zinc at any density. This polymer can be used to thicken formate brines where HEC is not recommended. As a result, the polymer was implemented into the field and successful case histories are presented.

The use of Potassium Carbonate as a non-corrosive, chloride free completion fluid has gained acceptance by several operators in the Middle East and North Sea. These brines can be formulated to reach a specific gravity of 1.52 (12.5 lbm/gal).The formulated brines possess physico-chemical properties such as high solubility, low crystallization temperature, low intrinsic viscosity, low corrosivity, etc., which make them candidates for utility as completion and/or packer fluids. Theoretically, these properties should provide a brine completion fluid which is operationally functional, corrosion resistant (high pH) and which eliminate the potential for chloride stress cracking of corrosion resistant alloys. However, the significance of these benefits is unpublished and other obvious potential incompatibilities were apparently not evaluated.This paper presents results from an extensive laboratory evaluation as to the suitability of potassium carbonate brines as completion fluids. Data from average weight loss and stress cracking corrosion (SCC) tests confirm both low general corrosion rates and little or no tendency toward stress corrosion. However, this low corrosion potential is not significantly lower than other chloride free brine alternatives such as sodium bromide.At test temperatures as high as 300°F, no evidence of 13 Chrome Stainless Steel stress cracking was identified in any of the completion brine systems tested, including chloride and bromide based fluids. Furthermore, fluid-fluid and fluid-rock compatibility test results indicate that carbonate based brines produce precipitation reaction products when intermixed with a range of synthetic and natural formation waters. Single-phase, brine flow tests on Berea cores showed an almost total loss of permeability after exposure to potassium carbonate brines.Guidelines are presented to assist the completion engineer in thoroughly evaluating completion fluid brine chemistries as to functionality and formation compatibility.INTRODUCTION. The potential for premature workovers caused by materials failure in corrosive environments has challenged the Oil and Gas Industry for many years.