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Q&A Your North America business is doing well. Will that continue to be your focus in the short term? We are really excited about our business in North America. We have always had significant investment in North America and as we look at the immediate future, it will be the busiest market. It is extremely impactful on many different stages. Do you see a slowdown in the unconventional business in North America, or do you think it is still on the way up? I think that North America is going to be very resilient in a $50–55/bbl world. There is a lot of demand for North America resources and I think the speed to market is really relevant and important, particularly as demand increases. Unconventionals can fill that demand most quickly because of the timing more than anything else, which is a real advantage relative to mature fields and particularly deep water. There is a lot of demand for what we do and I expect that we will be very busy in 2018. The sense I get from the customers is that the outlook is good at current commodity prices. We continue to reduce costs and make more barrels. And that’s how Halliburton spends most of its time—determining how to deliver the lowest cost per BOE. Any fear that equipment shortages or labor shortages could slow activity? I don’t think they will. The market is undersupplied today. We estimate that the market is about a million-and-a-half horsepower undersupplied for pumping equipment and I think the other services are also quite tight. Layer onto that the challenges with people and the shortages actually generate a flight to quality. One of the reasons I am confident about our business is that we have been disciplined about maintenance of our equipment and hiring people well ahead of time. That comes at a cost but the fact is there is no substitute for service quality. No substitute. Outside of North America, where are the highest priorities for Halliburton? We have outperformed the market through the downturn internationally in seven of the past eight quarters. The Middle East is extremely important to us. One of the things I am most pleased with is the ability of Halliburton to focus intently on North America, but at the same time steadily grow our international footprint. The fact is, we are present in every important market around the world today. That is something we could not have said 10 years ago and maybe even 5 years ago.

Introduction: We previously reported that “drip and ship” patients received at our tertiary center were younger and less often black when compared to those presenting directly. Given that disparities exist at many levels of acute ischemic stroke (AIS) care, the objective of this analysis was to determine if age and race disparities exist in inter-hospital transfer to a higher level of care (HLOC). Methods: In this cross-sectional analysis, we extracted patient characteristics and transfer status of AIS patients from the State Emergency Department Databases (SEDD) and Inpatient Databases (SID) of 5 states between 1/1/2010 and 12/29/2010. Hospital characteristics were determined using the American Hospital Association Database and The Joint Commission. We used Poisson regression with robust variance estimation adjusted for age, gender, payer type, Elixhauser comorbidities, and state to estimate prevalence ratios (PRs) and the proportion of whites and blacks, aged 18-64 or ≥65 years transferred by PSC status and hospital AIS volume. Results: We identified 58,321 AIS discharges (29% age 18-64 years) of whom 4.8% were transferred to a HLOC. Blacks were less likely to be transferred compared with whites (3.9% vs. 5.0%, PR 0.76; 95% CI 0.68-0.84). Among those age 18-64 years presenting to very low volume non-PSC hospitals (2 AIS discharges/month), blacks had a lower predicted percent transferred when compared with whites (16.2% vs 29.9%: 13.6% difference; 95% CI 6.6-20.6[Figure 1]). Differences by race were present for non-PSC hospitals with volumes as large as 8 AIS discharges/month (9.8% vs. 12.7%: 2.9% difference; 95% CI 0.9-4.9). Similar, although smaller, differences were observed in older patients (data on minority serving hospitals to be presented also). Conclusions: These findings suggest that age and race disparities exist in inter-hospital transfer for AIS. Specifically, black AIS patients aged

Objective:We sought to derive and internally validate a Sepsis Risk Score and a Severe Sepsis Risk Score predicting future sepsis and severe sepsis events among community-dwelling adults.Design:National population-based cohort.Setting:United States.Subjects:A total of 30,239 community-dwelling adult

Objective Prescription sleep medication use is most prevalent among women and older adults. Morning drowsiness and impaired coordination are side effects of sleep medications that may affect driving safety. The association between current use of zolpidem-containing medications and motor vehicle collisions (MVCs) was evaluated among drivers of advanced age. Methods Participants were current drivers aged ≥70 years residing in north-central Alabama, spoke English, had a valid driver's license, and had driven within the past three months (n = 2000). Current zolpidem use was determined by pill bottle review. The participant's five-year MVC history was determined from Alabama Department of Public Safety accident reports. The five-year MVC and at-fault MVC rate ratios (RR) were estimated comparing zolpidem users with nonusers in the overall sample and a priori–defined age and sex subgroups. Results The unadjusted RR (95% confidence interval [CI]) of MVCs comparing zolpidem users with nonusers was attenuated after adjustment (1.46 [1.02–2.08] and 1.38 [0.97–1.98], respectively). Among women, the unadjusted and adjusted RRs (95% CI) were 1.65 (1.03–2.66) and 1.61 (1.00–2.60), respectively. The unadjusted and adjusted RRs (95% CI) among those aged 80 years or more were 2.24 (1.19–4.57) and 2.35 (1.20–4.61), respectively. There were no statistically significant associations among men or participants less than 80 years old. Similar patterns were present for at-fault MVCs. Conclusion Current zolpidem users, specifically women and individuals aged 80 years or more, had higher MVC rates than nonusers. Practitioners should consider behavioral treatment before initiating low doses of zolpidem and increasing it as needed to achieve restorative sleep in women and individuals aged 80 years or more to reduce the risk of zolpidem-associated MVCs.

E&P Notes BHGE Shares Strategy for Integration of Services, Products, and Digital Platforms Pam Boschee, Senior Editor Marking 100 days as a new company after the merger of Baker Hughes and GE Oil and Gas, Baker Hughes, a GE company (BHGE), shared its strategies and plans for taking a fullstream approach to global oilfield services, products, and digital capabilities to improve productivity, safety, and project economics. Speaking at the SPE Annual Technical Conference and Exhibition in October, Mathias Schlecht, BHGE vice president of enterprise technology, described the concept as the full integration of services from upstream to midstream to downstream. “We know how to get the molecules and transport and use them. From molecules to megawatts, and deep sea to the cloud.” Accidental Discovery: Bitumen Pellets for Heavy Oil Transport Stephen Whitfield, Senior Staff Writer Researchers at the University of Calgary have developed something that may have a significant impact on the transport of heavy oil, and it is the size of a pill. The discovery is a pellet, self-sealing with a liquid core of either bitumen or heavy oil within a super-viscous, semi-solid, or solid skin that reduces the chance of a damaging spill during transport. The pellets can be designed to be buoyant and safe if they are spilled into the environment by incorporating agents within the pellets, like gas bubbles, catalysts, and solvents. Their outer coating is unreactive, making them much less likely to cause environmental damage than a liquid heavy oil or bitumen spill. Jones Energy CEO Tells of Company’s Transformation Joel Parshall, JPT Features Editor Jones Energy CEO Jonny Jones described his company’s transformation from a small private entity to a publicly traded company in a talk in October at the Leaders in Industry Luncheon, sponsored by the Independent Producers Association of America and the Texas Independent Oil Producers & Royalty Owners, at the Houston Petroleum Club. Jones highlighted the company’s entry into the Merge oil play, a newly defined play at the junction of the SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend, Anadarko and Canadian and Kingfisher [counties]) plays in central Oklahoma. Largest Gulf of Mexico Lease Sale Announced John Donnelly, JPT Editor The US Department of the Interior in October proposed the largest oil and gas lease sale ever held in the United States—almost 77 million acres offshore Texas, Louisiana, Mississippi, Alabama, and Florida. The sale would be held in March 2018 and is attempted to revive interest in a sector that has been reeling since oil prices fell sharply beginning 3 years ago. The sale includes all available unleased areas on the Gulf ’s Outer Continental Shelf. The Trump administration said the auction should make the US energy industry stronger. This proposed sale follows a lease sale in the Gulf of Mexico in August that attracted $121 million in high bids on 90 offshore tracts.

The original version of this article unfortunately contained a mistake. There was an error in figure one. The correct figure can be found below. We apologize for the mistake.

Editor's column This month is the deadline to nominate someone for one of SPE’s numerous international awards. The deadline for nominations for regional awards is 1 March. The awards are designed to recognize individual contributions to the oil and gas industry and to the petroleum engineering profession. The awards depend on nominations from colleagues familiar with an individual’s professional, technical, or service accomplishments. The most well-known awards include honorary member, the highest honor that SPE presents to an individual and which is limited to 0.1% of the SPE total membership; distinguished member; Anthony F. Lucas Gold Medal, noting achievement in the identification and development of new technology; John Franklin Carll Award, honoring contributions to the application of engineering principles to petroleum development and recovery; and the Lester C. Uren Award, recognizing distinguished achievement in the technology of petroleum engineering. Other awards, such as the Public Service Award, honor distinguished public service through leadership, service, or humanitarianism. These awards highlight the good works that members do around the globe on a volunteer basis and without publicity. Winners of the award over the past 6 years show the variety of contributions that members have made. Last year, Pascal Breton, deputy vice president E&P communications with Total, was cited for his work with an organization in the Philippines. In 1998, Breton took a sabbatical year to launch ANAK-Tnk, a Manila-based nongovernmental organization (NGO) that supports the Philippines capital city’s most impoverished children. He then created French and international branches of the NGO and still serves as its president. In 2018, David C. Baldwin was recognized for his work with the disabled. He created Pursuit, whose mission is to support individuals with intellectual and developmental disabilities (IDD) and encourage collaboration among IDD supporting organizations. Along with his wife, Baldwin has volunteered more than 25 years in support of disabled persons and, in 2016, completed a cross-country bicycle ride that raised $13 million for the cause. In 2017, Saka Matemilola was honored for helping found and establish the Center of Excellence in Geosciences and Petroleum Engineering at the University of Benin in Nigeria. In 2016, Richard J. Murphy, retired from Marathon, was noted for volunteer work at the MD Anderson Cancer Center in Houston, helping with the institute’s Patient Family Center and providing high school math tutoring services. He also created a volunteer in-class chemistry and physics tutoring program at a high school. In 2015, Richard D. Folger was recognized for work that led to him receiving the National Multiple Sclerosis Society Hope Award honoring service and leadership. In 2014, Nathan Meehan, who was 2016 SPE President, was honored for missionary work. He took a sabbatical to coordinate his church’s humanitarian activities in Asia. He trained volunteers and administered millions of dollars’ worth of humanitarian projects, including the provision of clean water and sanitation, medical services, and emergency relief. Award recipients are announced in July and they receive their awards at the SPE Annual Technical Conference and Exhibition. For more information on nominating someone, see the article on page 76 or visit www.spe.org/awards.

There are no validated systems for characterizing long-term risk of severe sepsis in community-dwelling adults. We tested the ability of the REasons for Geographic and Racial Differences in Stroke-Severe Sepsis Risk Score (REGARDS-SSRS) to predict 10-year severe sepsis risk in separate cohorts of community-dwelling adults. We internally tested the REGARDS-SSRS on the REGARDS-Medicare subcohort. We then externally validated the REGARDS-SSRS using (1) the Cardiovascular Health Study (CHS) and (2) the Atherosclerosis Risk in Communities (ARIC) cohorts. Participants included community-dwelling adults: REGARDS-Medicare, age &ge, 65 years, n = 9522, CHS, age &ge, 65 years, n = 5888, ARIC, age 45&ndash, 64 years, n = 11,584. The primary exposure was 10-year severe sepsis risk, predicted by the REGARDS-SSRS from participant sociodemographics, health behaviors, chronic medical conditions and select biomarkers. The primary outcome was first severe sepsis hospitalizations, defined as the concurrent presence of ICD-9 discharge diagnoses for a serious infection and organ dysfunction. Median SSRS in the cohorts were: REGARDS-Medicare 11 points (IQR 7&ndash, 16), CHS 10 (IQR 6&ndash, 15), ARIC 7 (IQR 5&ndash, 10). Severe sepsis incidence rates were: REGARDS-Medicare 30.7 per 1000 person-years (95% CI: 29.2&ndash, 32.2), CHS 11.9 (10.9&ndash, 12.9), ARIC 6.8 (6.3&ndash, 7.3). SSRS discrimination for first severe sepsis events were: REGARDS-Medicare C-statistic 0.704 (95% CI: 0.691&ndash, 0.718), CHS 0.696 (0.675&ndash, 0.716), ARIC 0.697 (0.677&ndash, 0.716). The REGARDS-SRSS may potentially play a role in identifying community-dwelling adults at high severe sepsis risk.

OBJECTIVE: To determine the racial disparities in severe sepsis hospitalizations and outcomes in United States academic medical center-affiliated hospitals. DESIGN: Retrospective analysis of sepsis hospitalizations. SETTING: United States Academic medical center-affiliated hospitals participating in Vizient Consortium from 2012 to 2014. PATIENTS: Sepsis hospitalizations using International Classification of Diseases, Ninth Revision discharge diagnoses codes defined by the Angus method. INTERVENTIONS: None MEASUREMENTS AND MAIN RESULTS: We compared rates of sepsis hospitalization, ICU admission, organ dysfunction and hospital mortality between blacks and whites. We repeated the analyses stratified by community-acquired, healthcare-associated, and hospital-acquired sepsis subtypes. Of 10,244,780 hospitalizations in our cohort, 1,114,386 (10.9%) had sepsis. Sepsis subtypes included community-acquired sepsis (61.8%), healthcare-associated sepsis (23.8%), and hospital-acquired sepsis (14.4%). While the proportion of discharges with sepsis was lower for blacks than whites (106.72 vs 109.43 per 1,000 hospitalizations, p30 years old. Blacks exhibited lower adjusted sepsis hospital mortality than whites (OR 0.85; 95 % CI: 0.84–0.86). The adjusted odds of hospital mortality following community-acquired, healthcare-associated, and hospital-acquired sepsis were lower for blacks than whites. CONCLUSION: In this current series of hospital discharges at United States academic medical center-affiliated hospitals, blacks exhibited lower adjusted rates of sepsis hospitalizations and mortality than whites

Q&A How did your company get started? Visuray was born out of a simple desire to help oil companies see inside their wells, thereby eliminating downtime on rigs where each moment of uncertainty translates to thousands of dollars lost. Conventional imaging in wells is fraught with issues, not least being the fact that most wells are filled with opaque fluid. The solution has been to use X-rays that pass through all types of well fluids and then to use the back-scattered X-rays to produce 2D and 3D images of the downhole hardware, even in the most opaque and troublesome well environments. With start-up funds from Statoil, BP, and Shell, we first developed the foundation for our technology. In 2005, the first successful laboratory image was taken through mud. Two years later in 2007, a prototype 4m long and 9 in. in diameter was run in the Ullrigg test well just outside Stavanger. This prompted a second round of funding by our JIP partners. In early 2015, after 7 years and $90 million of investment, a 35/8-in. commercial wireline tool, called the VR90, was successfully tested in a well in Germany. How big is your company now? Visuray comprises a team of 60 professionals from 20 countries, who have developed the world’s first downhole X-ray platform. Visuray has developed cutting-edge technology and proprietary processes to deliver electronically produced radiation in an oil well at unprecedented levels of brightness in a perfectly safe manner. Coupled with the most sensitive high-temperature, solid state X-ray detectors, Visuray can see and diagnose problems inside oil wells with millimetric accuracy. The first commercial product stemming from the downhole platform is the VR90 downhole X-ray diagnostic tool. It has proven itself in the field with 100% successful jobs conducted in North America, Europe, and the Middle East since 2015. What’s next for Visuray? After doing some 20 jobs from North America to the Middle East, the VR90 has reached a significant level of maturity and proven success, and the downhole X-ray platform (DXP) is now proving capable of providing a range of services. In the last 6 months, the VR90 has done 10 times as many jobs as it did in the previous 6-month period. So, you can say the uptake is increasing and is now limited only by the number of tools in our fleet. These tools are now being built at our product center in Katy, Texas and we are ramping up production to be able to service the demand in the market.

Objective. The Centers for Disease Control and Prevention has recommended emergency department (ED) opt-out HIV screening since 2006. Routine screening can prove challenging due to the ED's complexity and competing priorities. This study examined the implementation and evolution of a routine, integrated, opt-out HIV screening program at an urban academic ED in Alabama since August 2011. Methods. ED routine, opt-out HIV screening was implemented as a standard of care in September 2011. To describe the outcomes and escalation of the screening program, data analyses were performed from three separate data queries: ( 1) encounter-level HIV screening questionnaire and test results from September 21, 2011, through December 31, 2013; ( 2) test-level, fourth-generation HIV results from July 9 through December 31, 2013; and ( 3) daily HIV testing rates and trends from September 9, 2011, through June 30, 2014. Results. Of the 46,385 HIV screening tests performed, 252 (0.5%) were confirmed to be positive. Acute HIV infection accounted for 11.8% of all HIV patients identified using the fourth-generation HIV screening assay. Seventy-six percent of confirmed HIV-positive patients had successful linkage to care. Implementation of fourth-generation HIV instrument-based testing resulted in a 15.0% decline in weekly HIV testing rates. Displacement of nursing provider HIV test offers from triage to the bedside resulted in a 31.6% decline in weekly HIV testing rates. Conclusion. This program demonstrated the capacity for high-volume, routine, opt-out HIV screening. Evolving ED challenges require program monitoring and adaptation to sustain scalable HIV screening in EDs.

Background: Patterns of acute kidney injury (AKI) can be distinguished by the rate of changes in the serum creation concentrations during hospitalizations. We hypothesized that the timing and values of minimum and maximum serum creatinine (sCr) could be used to distinguish between transient hospital-associated AKI (THA-AKI) and hospital-acquired AKI (HA-AKI). Materials and Methods: We evaluated adults admitted to 2 regionally distinct academic medical centers. Peak sCr during the hospitalization was used to define AKI, using absolute changes and timing from the minimum sCr. sCr trajectories were derived based on the rate of change between the minimum and peak creatinine concentrations. Results: Peak creatinine followed the minimum creatinine for HA-AKI, while the peak creatinine preceded the minimum creatinine for THA-AKI. There were 82,403 patients included in the analyses, and 53,882 (65%) did not have AKI during the index hospitalization. There were 2,611 inpatient deaths; HA-AKI had a 4.8-fold increased risk relative to those without AKI (p < 0.01), and transient AKI had a 1.6-fold increased risk for inpatient mortality relative to inpatients without AKI (p < 0.01). Conclusions: Patients with hospital-associated AKI are at an increased risk for inpatient mortality. Creatinine trajectories can be used to describe the rate of development as well as recovery from inpatient AKI. The 24- and 48-hour interval slopes may be early indicators of developing AKI.

Hepatitis C virus (HCV) infection is a growing problem, disproportionately affecting those born between 1945 and 1965. Here, we demonstrate the wide geographic reach and surveillance potential of emergency department–based screening and identify areas of elevated HCV infection in central Alabama that were socioeconomically disadvantaged compared with surrounding communities.

In the United States, national efforts to reduce hospital readmissions have been enacted, including the application of substantial insurance reimbursement penalties for hospitals with elevated rates. Readmissions after severe sepsis remain understudied and could possibly signify lapses in care and missed opportunities for intervention. We sought to characterize 7- and 30-day readmission rates following hospital admission for severe sepsis as well as institutional variations in readmission.Retrospective analysis of 345,657 severe sepsis discharges from University HealthSystem Consortium hospitals in 2012.United States.We applied the commonly cited method described by Angus et al for identification of severe sepsis, including only discharges with sepsis present at admission.None.We identified unplanned, all-cause readmissions within 7 and 30 days of discharge using claims-based algorithms. Using mixed-effects logistic regression, we determined factors associated with 30-day readmission. We used risk-standardized readmission rates to assess institutional variations. Among 216,328 eligible severe sepsis discharges, there were 14,932 readmissions within 7 days (6.9%; 95% CI, 6.8-7.0) and 43,092 within 30 days (19.9%; 95% CI, 19.8-20.1). Among those readmitted within 30 days, 66.9% had an infection and 40.3% had severe sepsis at readmission. Patient severity, length of stay, and specific diagnoses were associated with increased odds of 30-day readmission. Observed institutional 7-day readmission rates ranged from 0% to 12.3%, 30-day rates from 3.6% to 29.1%, and 30-day risk-standardized readmission rates from 14.1% to 31.1%. Greater institutional volume, teaching status, trauma services, location in the Northeast, and lower ICU rates were associated with poor risk-standardized readmission rate performance.Severe sepsis readmission places a substantial burden on the healthcare system, with one in 15 and one in five severe sepsis discharges readmitted within 7 and 30 days, respectively. Hospitals and clinicians should be aware of this important sequela of severe sepsis.

Severe sepsis poses a major burden on the U.S. healthcare system. Previous epidemiologic studies have not differentiated community-acquired severe sepsis from healthcare-associated severe sepsis or hospital-acquired severe sepsis hospitalizations. We sought to compare and contrast community-acquired severe sepsis, healthcare-associated severe sepsis, and hospital-acquired severe sepsis hospitalizations in a national hospital sample.Retrospective analysis of severe sepsis discharges from University HealthSystem Consortium hospitals in 2012.United States.We used the criteria from Angus et al (discharge diagnoses for both a serious infection and organ dysfunction) to identify severe sepsis hospitalizations. We defined healthcare-associated severe sepsis as severe sepsis hospitalizations with an infection present at admission, where the patient was a nursing home resident, was on hemodialysis, or was readmitted within 30 days of a prior hospitalization. We defined community-acquired severe sepsis as all other severe sepsis patients with an infection present at admission. We defined hospital-acquired severe sepsis as severe sepsis patients where the documented infection was not present at admission.None.Prevalence of community-acquired severe sepsis, healthcare-associated severe sepsis, and hospital-acquired severe sepsis, adjusted hospital mortality, length of hospitalization, length of stay in an ICU, and hospital costs. Among 3,355,753 hospital discharges, there were 307,491 with severe sepsis, including 193,081 (62.8%) community-acquired severe sepsis, 79,581 (25.9%) healthcare-associated severe sepsis, and 34,829 (11.3%) hospital-acquired severe sepsis. Hospital-acquired severe sepsis and healthcare-associated severe sepsis exhibited higher in-hospital mortality than community-acquired severe sepsis (hospital acquired [19.2%] vs healthcare associated [12.8%] vs community acquired [8.6%]). Hospital-acquired severe sepsis had greater resource utilization than both healthcare-associated severe sepsis and community-acquired severe sepsis, with higher median length of hospital stay (hospital acquired [17 d] vs healthcare associated [7 d] vs community acquired [6 d]), median length of ICU stay (hospital acquired [8 d] vs healthcare associated [3 d] vs community acquired [3 d]), and median hospital costs (hospital acquired [$38,369] vs healthcare associated [$8,796] vs community acquired [$7,024]).In this series, severe sepsis hospitalizations included community-acquired severe sepsis (62.8%), healthcare-associated severe sepsis (25.9%), and hospital-acquired severe sepsis (11.3%) cases. Hospital-acquired severe sepsis was associated with both higher mortality and resource utilization than community-acquired severe sepsis and healthcare-associated severe sepsis.

Mobility and function are important predictors of survival. However, their combined impact on mortality in adults ≥65 years with heart failure (HF) is not well understood. This study examined the role of gait speed and instrumental activities of daily living (IADL) in all-cause mortality in a cohort of 1,119 community-dwelling Cardiovascular Health Study participants ≥65 years with incident HF. Data on HF and mortality were collected through annual examinations or contact during the 10-year follow-up period. Slower gait speed (

Purpose The Emergency Department (ED) is an important venue for the care of patients with cancer. We sought to describe the national characteristics of ED visits by patients with cancer in the United States. Methods We performed an analysis of 2012–2014 ED visit data from the National Hospital Ambulatory Medical Care Survey (NHAMCS). We included adult (age ≥ 18 years) ED patients, stratified by history of cancer. Using the NHAMCS survey design and weighting variables, we estimated the annual number of adult ED visits by patients with cancer. We compared demographics, clinical characteristics, ED resource utilization, and disposition of cancer vs. non-cancer patients. Results There were an estimated 104,836,398 annual ED visits. Patients with cancer accounted for an estimated 3,879,665 (95% CI: 3,416,435–4,342,895) annual ED visits. Compared with other ED patients, those with cancer were older (mean 64.8 vs. 45.4 years), more likely to arrive by Emergency Medical Services (28.0 vs. 16.9%), and experienced longer lengths of ED stay (mean 4.9 vs. 3.8 h). Over 65% of ED patients with cancer underwent radiologic imaging. Patients with cancer almost twice as likely to undergo CT scanning; four times more likely to present with sepsis; twice as likely to present with thrombosis, and three times more likely to be admitted to the hospital than non-cancer patients. Conclusions Patients with cancer comprise nearly 4 million ED visits annually. The findings highlight the important role of the ED in cancer care and need for addressing acute care conditions in patients with cancer.

ObjectivesLumbar puncture (LP) is an important technique for assessing and treating neurological symptoms. The objective of this study was to describe the characteristics of diagnostic lumbar punctures performed on hospitalized patients in the United States.MethodsWe analyzed data from the 2010 National Inpatient Sample (NIS) and the National Emergency Department Survey (NEDS). We included patients treated in the Emergency Department (ED) as well as those admitted to an inpatient bed through the ED. We identified patients undergoing LPs from ICD-9 procedural code 03.31 and CPT code 62270. We generated nationally weighted estimates of the total number of LPs. We also assessed patient and hospital characteristics of cases undergoing LP.ResultsOf an estimated 135 million hospitalizations (ED + admission, or ED only), there were an estimated 362,718 LPs (331,248-394,188), including 273,612 (251,850-295,375) among adults and 89,106 (71,870-106,342) among children (ConclusionsLumbar Puncture remains an important procedure for diagnostic and therapeutic uses in United States Hospitals.

The Centers for Disease Control and Prevention and U.S. Preventive Services Task Force have highlighted public screening as an essential strategy for increasing hepatitis C virus (HCV) detection in persons born between 1945 and 1965 (“baby boomers”). Because earlier HCV screening efforts have not targeted emergency department (ED) baby boomer patients, we describe early experience with integrated opt-out HCV antibody (Ab) screening of medically stable baby boomers presenting to an urban academic ED. We performed HCV Ab testing 24 hours per day and confirmed positive test results using polymerase chain reaction (PCR). The primary outcome was prevalence of unrecognized HCV infection. Among 2,325 unique HCV-unaware baby boomers, 289 (12.7%) opted out of HCV screening. We performed HCV Ab tests on 1,529 individuals, of which 170 (11.1%) were reactive. Among Ab reactive cases, follow-up PCR was performed on 150 (88.2%), of which 102 (68.0%) were confirmed RNA positive. HCV Ab reactivity was more likely in males compared to females (14.7% vs. 7.4%; P

Hospital-associated acute kidney injury (HA-AKI) is associated with increased inpatient mortality. Our objective was to categorize HA-AKI based on the timing of minimum and peak inpatient serum creatinine (sCr) and describe the association with inpatient mortality. Materials and Methods: This study is a retrospective analysis of an administrative data set for adults admitted to a single medical center for over 4 years. Changes and timing of the minimum and peak sCr were used to define HA-AKI categories. Results: Peak creatinine followed minimum creatinine for HA-AKI, and preceded the minimum value for transient HA-AKI (THA-AKI). A subset of patients developed HA-AKI after recovering from THA-AKI. Multivariable Cox regression analyses examined the association between these categories and 28-day inpatient mortality, adjusting for age, sex, race, Charlson comorbidity index, baseline kidney function, AKI recovery and renal replacement therapy. There were 50,601 patients included in the analyses, and 29,996 (59%) did not have AKI. There were 2,440 deaths; HA-AKI had a 2.24-fold (95% CI 1.99-2.51) increased risk, while THA-AKI group (12,101) had a 1.23-fold (95% CI 1.09-1.40) increased risk for inpatient mortality. THA-AKI patients who recovered and then developed HA-AKI had the same mortality risk as THA-AKI (1.27-fold [95% CI 1.07-1.51]) but longer hospitalization and less recovery from AKI. Conclusions: Risk of short-term inpatient mortality is associated with AKI, and this risk is attenuated with recovery of kidney function in the hospital. Systematic surveillance with repeated inpatient sCr values is needed to assess the short- and long-term consequences of HA-AKI.

Objective To characterize the relationship between stress and future risk of sepsis. We also evaluated the role of depression in this relationship. Methods We used population-based data on 30,183 participants in the Reasons for Geographic and Racial Differences in Stroke cohort, characterizing stress using the Perceived Stress Scale (PSS) and depressive symptoms using the Center for Epidemiologic Studies Depression Scale (CES-D). We identified incident sepsis events as hospitalizations for a serious infection with the presence of at least two systemic inflammatory response syndrome criteria. We assessed associations between PSS and incidence of sepsis for 1 and 10 years of follow-up, adjusting for demographics and chronic medical conditions and assessing the role of health behaviors and CES-D in these relationships. Results In 2003 to 2012, 1500 participants experienced an episode of sepsis. Mean PSS and CES-D scores were 3.2 (2.9) and 1.2 (2.1). PSS was associated with increased 1-year adjusted incidence of sepsis (hazard ratio [HR] = 1.21 per PSS standard deviation, 95% confidence interval = 1.06-1.38); multivariable adjustment for health behaviors and CES-D did not change this association (1.20, 1.03-1.39). PSS was also associated with increased 10-year adjusted incidence of sepsis (HR = 1.07 per PSS standard deviation; 95% confidence interval = 1.02-1.13). Multivariable adjustment showed that health behaviors did not affect this long-term association, whereas the addition of CES-D reduced the association between PSS and sepsis during 10-year follow-up (HR = 1.04, 0.98-1.11). Conclusions Increased stress was associated with higher 1-year adjusted incidence of sepsis, even after accounting for depressive symptoms. The association between stress and 10-year adjusted incidence of sepsis was also significant, but this association was reduced when adjusting for depressive symptoms. Reduction of stress may limit short-term sepsis risk.

Older adults, those aged 65 and older, frequently require emergency care. However, only limited national data describe the Emergency Medical Services (EMS) care provided to older adults. We sought to determine the characteristics of EMS care provided to older adults in the United States.We used data from the 2014 National Emergency Medical Services Information System (NEMSIS), encompassing EMS response data from 46 States and territories. We excluded EMS responses for children18 years, interfacility transports, intercepts, non-emergency medical transports, and standby responses. We defined older adults as age ≥65 years. We compared patient demographics (age, sex, race, primary payer), response characteristics (dispatch time, location type, time intervals), and clinical course (clinical impression, injury, procedures, medications) between older and younger adult EMS emergency 9-1-1 responses.During the study period there were 20,212,245 EMS emergency responses. Among the 16,116,219 adult EMS responses, there were 6,569,064 (40.76%) older and 9,547,155 (59.24%) younger adults. Older EMS patients were more likely to be white and the EMS incident to be located in healthcare facilities (clinic, hospital, nursing home). Compared with younger patients, older EMS patients were more likely to present with syncope (5.68% vs. 3.40%; OR 1.71; CI: 1.71-1.72), cardiac arrest/rhythm disturbance (3.27% vs. 1.69%; OR 1.97; CI: 1.96-1.98), stroke (2.18% vs. 0.74%; OR 2.99; CI: 2.96-3.02) and shock (0.77% vs. 0.38%; OR 2.02; CI: 2.00-2.04). Common EMS interventions performed on older persons included intravenous access (32.02%), 12-lead ECG (14.37%), CPR (0.87%), and intubation (2.00%). The most common EMS drugs administered to older persons included epinephrine, atropine, furosemide, amiodarone, and albuterol or ipratropium.One of every three U.S. EMS emergency responses involves older adults. EMS personnel must be prepared to care for the older patient.

Background Prior studies associate steroid use with infection risk but were limited to select populations and short follow-up periods. The association of steroid use with long-term risk of community-acquired infections is unknown. We sought to determine the association of steroid risk with long-term risks of community- acquired infections and sepsis. Methods We used data on 30,239 adults aged ≥ 45 years old from the Reasons for Geographic and Racial Differences in Stroke (REGARDS) cohort. The primary exposure was oral or injectable steroid use, determined from medication inventory obtained at baseline in-home visit. The primary outcome was time to first infection event during 2003–2012, determined through adjudicated review of hospital records. We determined associations between baseline steroid use and first infection hospitalization events using Cox proportional hazards models, adjusting for demographics, health behaviors, chronic medical conditions, and medication adherence. Among the first infection hospitalization events, we also determined the association between baseline steroid use and sepsis. Results Steroid use was reported in 2.24% (n = 677) of the study population. There were 2593 incident infection events during the 10-year follow-up period. Infection incidence rates were higher for steroid than non-steroid users (37.99 vs. 13.79 per 1000 person-years). Steroid use was independently associated with increased risk of infection (adjusted HR 2.10, 95% CI: 1.73–2.56). Among first-infection events, steroid use was associated with increased odds of sepsis (adjusted OR 2.11, 95% CI: 1.33–3.36). The associations persisted in propensity matched analyses as well as models stratified by propensity score and medication adherence. Conclusions In this population-based cohort study, baseline steroid use was associated with increased long-term risks of community-acquired infections and sepsis. Electronic supplementary material The online version of this article (doi:10.1186/s13054-017-1767-1) contains supplementary material, which is available to authorized users.

Background Sepsis is associated with long-term health consequences. We sought to determine the long-term risks of acute and fatal coronary heart disease (CHD) events after sepsis hospitalizations among community-dwelling adults. Methods We analyzed data from 30329 participants in the population-based REasons for Geographic And Racial Differences in Stroke (REGARDS) cohort. Sepsis events included hospitalizations for a serious infection with ≥2 systemic inflammatory response syndrome criteria. Acute CHD events included myocardial infarctions (MIs; nonfatal and fatal) and acute CHD deaths. Fatal CHD included deaths ≤28 days of an acute MI and acute CHD deaths. We age- and time-matched each sepsis participant with 5 nonsepsis participants. We assessed the associations between sepsis hospitalizations and future acute and fatal CHD events using Cox regression, Gray's model, and competing risks analysis, adjusting for comorbidities. Results The matched cohort contained 1070 sepsis and 5350 nonsepsis participants. Risk of acute CHD was higher for sepsis than nonsepsis controls after adjusting for sex, race, education, income, region, tobacco use, and select chronic medical conditions (0-1 year adjusted hazard ratio [HR], 4.38 [95% confidence interval (CI), 2.03-9.45]; 1-4 years, 1.78 [1.09-2.88]; and 4+ years, 1.18 [0.52-2.67]). Risk of fatal CHD was similarly higher for sepsis than nonsepsis individuals (0-1 year adjusted HR, 3.12 [95% CI, 1.35-7.23]; 1-4 years, 3.29 [1.89-5.74]; and 4+ years HR, 1.15 [0.34-3.94]). Conclusions The long-term risks of acute and fatal CHD are elevated after sepsis hospitalization. Management of acute CHD risk may be important for individuals surviving a sepsis event.

Motor vehicle collisions (MVCs) continue to place an increased burden on both individuals and health care systems. Self-reported and state-recorded police reports are the most common methods for MVC evaluation in epidemiologic studies, with varying degrees of agreement of information when compared in previous studies. The objective of the current study is to address the differences in MVC reporting and provide a more robust measure of the agreement between self-reported and state-recorded MVCs in a community dwelling population of older adults.A three-year prospective study was conducted in a population-based sample of 2000 licensed drivers aged 70 and older. At annual visits, participants were asked to self-report information on any MVC that occurred over the prior year where police were called to the scene. Information on police-reported MVCs was also ascertained from Alabama official state-recorded databases. The kappa coefficient was calculated to determine overall agreement between any self-reported and state-recorded crashes, as well as the raw number of crashes reported. In addition, agreement was stratified by demographics, health status, medication use, functional status (i.e. vision, cognition), and driving habits.1747 participants who completed three years of follow up were involved in 225 state-recorded MVCs and 208 self-reported MVCs yielding overall substantial agreement between any self-report and state-recorded MVC (kappa=0.64). Cumulative number of self-reported and state-recorded MVCs was also compared, with agreement slightly reduced (kappa=0.55). The clinical characteristic resulting in the greatest variation in agreement with drivers was impaired contrast sensitivity showing better agreement between self-reported and state-recorded MVCs (kappa=0.9) than those with non-impaired contrast sensitivity (kappa=0.6).Study results showed substantial agreement between self-reported and state-recorded MVCs for any MVC involvement among the study population. When examining the reporting of the total number of MVCs over the three year period, agreement was reduced to a moderate level. There was consistency in agreement across MVC risk factors except among individuals with contrast sensitivity. These findings have implications for the design and analytic planning of epidemiologic and clinical research focused on MVCs.

Introduction: The risk of ischemic stroke doubles for each decade beyond the age of 55. While disparities, particularly racial disparities, have been described for many aspects of acute stroke care, these disparities have not been well characterized among older adults. The purpose of this analysis was to evaluate potential differences in IV-tPA utilization among acute ischemic stroke (AIS) patients aged ≥65 years. Methods: We used the Nationwide Inpatient Sample (NIS) to examine primary AIS diagnosis discharges (ICD-9 codes 433.x1, 434.x1 and 436) from US hospitals over 2006-2011, among those aged ≥ 65 years. Utilization of IV-tPA was identified using procedure code 99.10. Multivariate logistic regression was conducted to determine age and race associations with IV tPA utilization. Results: Over the 6 year study period, we identified 1.5 million ischemic stroke discharges, with 3.9% receiving IV-tPA. Compared to discharges who did not receive treatment, those receiving IV-tPA were less likely to be female and black. The odds of women receiving IV-tPA were 10% lower than men. After adjusting for demographics, insurance, and medical comorbidities, the odds of women receiving IV-tPA were still 5% lower (Table). When compared to non-black discharges, older blacks were at 25% lower odds of receiving IV-tPA. After adjusting for demographics, insurance and medical comorbidities, older blacks were at 22% lower odds of receiving IV-tPA (Table). Conclusions: Among older Americans, women and blacks have lower odds of being treated with IV-tPA, even after adjusting for age, insurance and comorbidities. A greater understanding of the reasons for these unexplained differences in the fastest growing proportion of our population is needed.

Background: Spontaneous intracerebral hemorrhage (sICH) is associated with substantial disability, accounting for considerable resource utilization among stroke survivors. Debate exists about the timing and utilization of tracheostomy (Trach) and percutaneous gastrostomy (PEG) tube placement in sICH patients. We hypothesized that sICH survivors with PEG and/or Trach would have higher odds of 30-day readmission. Methods: We analyzed the 2013 Nationwide Readmissions Database, a nationally representative sample of hospital discharges. Patients with a primary discharge diagnosis of sICH (ICD-9 code 431) were included in the analysis. Repeat, pediatric, same-day events, head trauma, AVM/fistula, and discharges occurring in December were excluded. Patients who received PEG and/or Trach were identified using published algorithms. We defined readmission as any admission within 30-days of index hospitalization discharge. Odds ratios for 30-day readmission comparing exposed versus unexposed were estimated with adjustment for demographics, risk factors, and concurrent illness. All analyses were performed using survey design variables. Results: Among the 32,715 sICH index hospitalizations, 3,480 (10.6%) received a PEG and 1806 (5.5%) received a Trach. Overall 4,320 (13.2%) were readmitted within 30 days (PEG 20.5%, trach 18.9%). In the fully adjusted models, sICH patients with PEG had higher odds of readmission (OR 1.43, 95% CI 1.14-1.80), while patients with trach did not (OR 0.77, 95% CI 0.54-1.11). Predictors of readmission among individuals with and without PEG and Trach will be presented. Conclusions: sICH patients who underwent PEG placement had higher odds of 30-day readmission while patients receiving Trach did not. This finding suggests that heightened post-discharge surveillance of individuals receiving PEG may be warranted.

Introduction: Readmission for acute ischemic stroke (AIS) is an important quality of care metric, and has been tied to reimbursement penalties. We aimed to describe nationwide readmission for AIS patients, and the potential impact of IV-tPA and Intra Arterial Treatment (IAT) on 30-day readmission. Methods: We analyzed the 2013 Nationwide Readmission Database, a nationally representative, weighted probability sample of ~ 36 million discharges from short-term hospitals. We used ICD-9 codes to identify patients with diagnosis of AIS (434.x1, 434.x1, 439), and patients receiving IV-tPA (99.1) or IAT (39.74). We excluded repeat, pediatric, and same-day events, and discharges in December. We defined readmissions as any admission within 30-days of index hospitalization discharge. Using published methods, we classified events as planned or unplanned, and identified readmissions attributable to potentially preventable ambulatory care-sensitive conditions. Logistic regression, using survey design variables, was performed to report nationally-weighted estimates of odds ratios (OR) and 95% CIs for factors associated with readmission. Results: A total of 319,317 index cases were identified with a primary diagnosis of AIS. Figure 1 illustrates the overall and therapy specific proportions for 30-day readmissions. Overall 12.1% (95% CI: 11.9 -12.3) of AIS patients were readmitted during 30-day post index hospitalization discharge. After adjustment, both IV-tPA and IAT were significantly associated with lower odds of 30-day readmission. For patients receiving either IV-tPA or undergoing IAT, the OR for 30-day readmission was 0.71 (CI: 0.66 - 0.77). Subgroup analyses for patients older than 65, and reasons for readmission will be presented. Conclusion: Recanalization therapy for AIS is associated with 23-34% lower odds of readmission. Analyses are limited by lack of survival data; however, thrombolysis has not shown to increase mortality in clinical trials.

Editor's column For almost 2 decades, the world’s major gas producers have been trying to form an organization similar to OPEC that would offer stability to gas prices and give producers some control over security of supply and security of demand. With international spot trade of gas increasing and public pressure growing for cleaner fuels, the producers believe the time is finally right to become a major force in global energy markets. The main obstacle to establishing such an influential producers’ group has been the lack of international spot trade that reflects current supply-demand dynamics. Unlike oil, most gas has been traded through medium- and long-term contracts for pipeline delivery, with the gas price usually linked to the price of oil. Gas producers often felt they were leaving money on the table in these deals, which hampered further gas upstream development. But that is changing with the recent growth of liquefied natural gas (LNG) trade on the spot market and the increase in gas output from North America, the Middle East, and Africa. While all eyes were on OPEC-plus members and what they would do about oil production in the coming months, the Gas Exporting Countries Forum (GECF) met in late November in Equatorial Guinea. Members include two of the globe’s top gas exporters, Russia and Qatar, along with 10 other members (including Iran, Libya, and Algeria) and seven “observer members” (including Norway, Iraq, Oman, and Angola). Notably absent from the group are two of the largest LNG exporters responsible for the fledgling gas spot market, the US and Australia, but GECF members control 70% of world gas reserves. One of the group’s worries is that, after years of talk about gas being a solution for cleaner energy, momentum for renewables in the wake of heightened concern over climate change could push gas to the sidelines. The oil and gas industry sees gas not only as a bridge to the future but a mainstay of future energy supply. “This idea of natural gas as a transition fuel to renewables is strange,” Total Chief Executive Patrick Pouyanne said recently at an industry gas conference in Washington. “Natural gas is a solution (to climate change). It’s been scientifically proven.” And Qatar Minister of State for Energy Affairs Saad al-Kaabi told GECF members, “We all have the same objective: to place natural gas at the heart of the energy industry as a fuel of the future, and to affirm our true belief that natural gas is a cornerstone in the energy transition.” BP CEO Bob Dudley said recently that he was “concerned that gas is being increasing marginalized, even vilified and demonized” by environmental groups. But for the industry to sell gas as a “green” fuel, it will need to overcome two obstacles: methane leaks/emissions and flaring. Three of the world’s largest flaring culprits are associated with the GECF—Russia, Iran, and Iraq—and flaring from the Permian Basin in the US is on the rise. In response to these concerns, Qatar—which has ambitious gas growth goals—is touting its plans to adopt more carbon and sequestration projects.

This study sought to characterize variations in severe sepsis mortality between hospitals in the United States. Hospital discharge data (2012) were used from the University HealthSystem Consortium (UHC), a cooperative of US not-for-profit academic medical centers and affiliated hospitals. Discharge diagnosis codes were used to define severe sepsis as the presence of a serious infection with at least 1 organ dysfunction on hospital presentation. Expected mortality was determined from UHC risk adjustment mortality models. Among the 188 hospitals in the analysis, there were 256 509 patients with severe sepsis on admission. The median number of severe sepsis cases per hospital was 1202 (interquartile range [IQR] = 718-1940). Severe sepsis observed mortality (median = 8.6%; IQR = 6.8%-10.3%; range = 0.9%-18.2%) and observed-to-expected (O:E) mortality ratios (median = 0.91; IQR = 0.77-1.05; range = 0.16-1.95) varied across the hospitals. Variations in institutional severe sepsis observed mortality rates and O:E mortality ratios were observed in this national consortium of major medical centers.

Optimal out of hospital cardiac arrest (OHCA) airway management strategies remain unclear. We compared OHCA outcomes between patients receiving endotracheal intubation (ETI) versus supraglottic airway (SGA), and between patients receiving [ETI or SGA] and those receiving no advanced airway.We studied adult OHCA in the Cardiac Arrest Registry to Enhance Survival (CARES). Primary exposures were ETI, SGA, or no advanced prehospital airway placed. Primary outcomes were sustained ROSC, survival to hospital admission, survival to hospital discharge, and neurologically-intact survival to hospital discharge (cerebral performance category 1-2). Propensity scores characterized the probability of receiving ETI, SGA, or no advanced airway. We adjusted for Utstein confounders. Multivariable random effects regression accounted for clustering by EMS agency. We compared outcomes between (1) ETI vs. SGA, and (2) [no advanced airway] vs. [ETI or SGA].Of 10,691 OHCA, 5591 received ETI, 3110 SGA, and 1929 had no advanced airway. Unadjusted neurologically-intact survival was: ETI 5.4%, SGA 5.2%, no advanced airway 18.6%. Compared with SGA, ETI achieved higher sustained ROSC (OR 1.35; 95%CI 1.19-1.54), survival to hospital admission (1.36; 1.19-1.55), hospital survival (1.41; 1.14-1.76) and hospital discharge with good neurologic outcome (1.44; 1.10-1.88). Compared with [ETI or SGA], patients receiving no advanced airway attained higher survival to hospital admission (1.31; 1.16-1.49), hospital survival (2.96; 2.50-3.51) and hospital discharge with good neurologic outcome (4.24; 3.46-5.20).In CARES, survival was higher among OHCA receiving ETI than those receiving SGA, and for patients who received no advanced airway than those receiving ETI or SGA.

Editor's column US crude oil production will reach a record level of 12.29 million B/D in 2019, increasing faster than expected both this year and in 2020, according to the latest US Energy Information Administration (EIA) forecast. Output will rise to 13.29 million B/D next year. Similarly, the International Energy Agency predicted last month that US shale oil production will continue to reshape world energy markets, with the US accounting for 85% of the increase in global oil production to 2030. US output will rise to 19 million B/D over the next decade, wresting additional market share from OPEC producers and Russia, according to the agency’s annual World Energy Outlook. But while shale will continue to affect global markets, some believe this predicted rate of growth may be optimistic. There are already signs that producers are curtailing spending and production in the major shale basins as they are under increasing pressure to focus more on capital discipline and returns rather than production growth. In contrast to the EIA and IEA, consultancy IHS Markit sees much slower growth in US shale next year, just a 440,000 B/D increase, with output flat in 2021. “Going from nearly 2 million B/D annual growth in 2018, an all-time global record, to essentially no growth by 2021 makes it pretty clear that this is a new era of moderation for shale producers,” said Raoul LeBlanc, IHS Markit vice president for North American unconventionals. “This is a dramatic shift after several years where annual growth of more than 1 million B/D was the norm.” IHS Markit predicts prices for West Texas Intermediate (WTI) crude to hover in the $50/bbl range and that capital spending will drop by 10% this year, 12% in 2021, and 8% in 2022, from $102 billion in 2019 to $83 billion in 2022. Prices need to be about $65/bbl for producers to be able to both increase production significantly while also satisfying shareholder expectations, it said. In the meantime, producers are focusing more on completing wells than drilling new ones, which is a more economical way of boosting output. There were 7,740 drilled but uncompleted wells in the seven major US shale regions at the end of September, according to the EIA, compared with 8,800 in January. After years of producing all out, pushing US oil and natural gas production to record levels, shale producers are pulling back. Although output has skyrocketed, particularly in places such as the Permian Basin, financial results have not. Mergers and bankruptcy filings are common, and investors have become reluctant to lend capital. Natural gas companies in particular are hurting, and they are promising more capital discipline and lower production going forward. During third-quarter earnings calls, Chesapeake Energy, EQT, Callon Petroleum, Cimarex, and Diamondback Energy all signaled flat to lower spending and production. Chesapeake’s CEO had to re assure investors of the company’s financial health a week after the company said in a third-quarter earnings filing that it had “substantial doubt” of its ability to continue as a going concern. “I don’t think OPEC has to worry that much more about US•shale growth long term,” Pioneer Natural Resources Scott Sheffield told investors last month.

Editor's column Sustainability and environmental issues played a key part in the content at two of SPE’s recent major conferences. Offshore Europe was held in Aberdeen in September and the Annual Technical Conference and Exhibition (ATCE) took place for the first time in Canada in late September-early•October. Days before the ATCE conference began, activists held rallies around the world, including in Canada, demanding action on climate change, and the issue has risen to the forefront of political campaigns in Europe and the US. Three presidential candidates in the US have promised to “ban” hydraulic fracturing for environmental reasons if elected, although not offering specifics. At the United Nation’s climate change summit in September, more than 100 international banks pledged to decrease investment in the oil and gas sector because of the issue. The bankers promised to support full implementation of the Paris climate agreement and increase investments in renewables in lieu of hydrocarbons. The oil and gas industry is paying attention, as government and financial scrutiny of it increases and as public momentum for environmental regulation grows. But the scrutiny comes at a time when global energy consumption also is increasing, particularly in developing counties. Even with increased support for renewable forms of energy, oil and gas will play a major role in meeting world demand for years to come. At the same time the climate summit was taking place, the Oil and Gas Climate Initiative (OGCI)—a CEO-led group representing international and national oil companies—met in New York and announced further plans to accelerate the reduction of greenhouse gas emissions and support the goals of the Paris agreement. The group outlined a proposal to encourage investment in carbon capture and storage, and reported progress toward its goal of reducing industry methane emissions. OGCI said its member companies met its “methane intensity target” by cutting intensity 9% in 2018. It is now working to reduce carbon intensity in upstream operations by 2025. Members of the OGCI include ExxonMobil, Chevron, Shell, BP, Total, Equinor, Occidental, Eni, Repsol, Saudi Aramco, Petrobras, and CNPC. Both individual companies and other organizations are also taking steps to reduce the industry’s environmental footprint. During the Offshore Europe conference, The Oil & Gas Technology Centre announced it will create with industry a Net Zero Solution Centre to accelerate the development and deployment of technologies to de carbonize offshore operations and develop the UK continental shelf as the first global net zero oil and gas basin. The center is backed by several companies, including BP, Shell, Total, and Equinor. Much of the industry’s response hangs on the viability of carbon capture, utilization, and storage. The International Energy Agency describes it as one of the only technology solutions that can significantly reduce emissions across key industries. An article beginning on page 24 of this issue outlines the industry’s progress in this initiative and the challenges to be met.

Editor's column The US shale sector continues to disrupt global oil markets. Soaring US crude production and the resulting exports to Asia and Europe, are transforming worldwide trade flows and changing how consumer countries price crude. The US has overtaken Saudi Arabia as the world’s largest exporter, the International Energy Agency (IEA) reported in September, as its crude oil exports rose to more than 3 million•B/D and its total exports of crude and products reached almost 9 million B/D. Saudi Arabia was the globe’s top exporter for part of the third quarter as hurricanes and the US-China trade dispute affected US exports but that appeared to be temporary. In the past decade, US has more than doubled oil production, to 12.3 million B/D, becoming the world’s largest producer. “Since the last in-depth (IEA) review 5 years ago, the United States has reshaped energy markets both domestically and around the world,” said Fatih Birol, the IEA’s executive director, The US’ new role was underscored last month when a drone strike knocked out a large portion of Saudi Arabian production. In previous years, oil markets would have panicked, but traders quickly looked to the US to make up much of the difference. The US lifted its ban on exporting oil in 2015—put in place after the oil embargoes of the late 1970s—and, in December 2015 exported its first oil cargo in 40 years. That shipment of Eagle Ford light oil to the Mediterranean ushered in a new age and, within 2 years, the US was exporting more than 1 million B/D. Exports of unconventional crude from the Permian, Bakken, Niobrara, and Eagle Ford joined output from Gulf of Mexico fields such as Mars and Thunderhorse headed abroad. The impact on trade flows has been significant. Just a few years ago, Nigeria sold the US more than 1 million B/D of crude annually, but that volume has been replaced by the similar light, sweet crude produced in the Permian Basin. US crude has flowed to European refineries, which have seen declines in North Sea output, and to Asia, principally China. Since the US-China trade dispute began, Chinese refineries have cut back on US imports significantly, but consumption in India, Indonesia, and Taiwan has risen sharply at the same time. Asia has accounted for 45% of all US crude exports so far in 2019. That shift is changing how crude oil is bought and sold. The US Gulf Coast is quickly becoming a benchmark center for the worldwide oil market, with oil priced in relation to West Texas Intermediate’s value at the coast. Global exports to Asia previously were priced against North Sea Brent crude, but output there has been in decline, or Dubai crude, which is dominated by only a few participants. As new infrastructure is built in the US, carrying more crude to the coast, WTI priced at the Gulf of Mexico will only grow in stature as a pricing•benchmark.• Many analysts believe the shale boom is moderating because of the decline in oil prices since the start of the fourth quarter of 2018, and that the deceleration might continue through the rest of this year and into 2020. But production from the Permian Basin in particular has swamped available pipeline capacity to bring the oil to market, and several pipeline projects are scheduled to be completed this year and next, which should allow for even higher exports.

Editor's column After the oil price downturn, operators placed renewed emphasis on spending discipline, in drilling, project costs, and balance sheets. For some, that was a different metric: return to shareholders over production growth. During and after the prolonged decline in oil prices, which bottomed in 2016, larger operators did become more technologically proficient, increasing the efficiency of existing wells and learning to live with lower oil prices. With anticipation that $40-60/bbl oil might be the norm for years to come, they had no choice. But this was easier for larger companies than smaller independents ramping up shale output in places like the Permian Basin. This has put many independents in a tough spot. Bankruptcies are on the rise, and the future of unconventional production in the US, while spectacular, has some un answered questions going forward. The number of shale operators filing for Chapter 11 bankruptcy protection continues to grow, the latest being Sanchez Energy and Halcón Resources, both of which filed for protection in mid-August. From the beginning of 2015 to May 2019, 172 North American operators filed for bankruptcy. Many of the bankruptcies occurred in 2015–2016, but there were more in 2018 than 2017. “After years of high growth, the US unconventionals sector has yet to deliver cash flow or returns to investors across the full cycle. To achieve profitability, shale producers will need to transform their organizations and shift their strategic focus from growth to value creation,” consulting firm McKinsey said in a statement last month. During recent earnings calls, many independents in the unconventional sector sounded a note of pessimism about the current state of the business. US shale operators need to tap the brakes on production growth and focus even more on capital discipline in an oversupplied market, Continental Resources CEO Harold Hamm said at a recent industry conference. “Capital discipline is more important now than at any time I’ve seen it. We can oversupply the market, and we have,” Hamm said. In August, the International Energy Agency reported that demand growth for oil had hit its lowest level in more than a decade, going back to the recession of 2008. The demand slowdown was driven by fears of another global recession and the ongoing trade dispute between the US and China, which has hurt several industrial and manufacturing sectors. Oil prices have fallen steadily this year, about 20% since April. In a separate report, consultancy Rystad Energy said the oil market was going from “gloomy to gloomier” and questioned whether OPEC and the other major producers that have been reigning in supply since the oil crash could do much more at this point. But there are bright spots in other parts of the industry. “High-impact” exploration drilling activity increased significantly in the first half of 2019 with 51 exploration wells completed, compared with just 36 in the same period last year, according to Westwood Global Energy Group. Sixteen large discoveries have been made so far this year, with the largest discoveries all being gas at Dinkov (14 Tcf) and Nyarmeyskoye (4.3 Tcf) in the Kara Sea offshore Russia, and Glaucus (4.5 Tcf) in the Eastern Mediterranean offshore Cyprus. The largest oil discoveries were Yellowtail and Tilapia offshore Guyana, according to Westwood. It expects that another 35–40 high-impact exploration wells will be completed by the end of 2019, resulting in more than 85 for the year, a 35% increase from 2018.

Editor's column Five years since the start of the precipitous oil price drop that led to the industry’s worst recession since the 1980s, the oil market is still struggling with supply/demand balances and price stability. Recent oil market forecasts reach essentially the same conclusion: the market will remain oversupplied into 2020, weighing on prices for the short term. In early July, OPEC and other major producers decided to extend production cuts into 2020 in an attempt to keep oil prices steady as global demand growth appeared to be slowing and US unconventionals output continued to rise. Global oil demand is predicted to increase by more than 1 million B/D this year, but that is lower than OPEC and the International Energy Agency (IEA) had forecast at the beginning of this year. OPEC, Russia, and other producers agreed to cut overall output by 1.2 million B/D in January and met in July to reassess the market. Even with the supply cuts, oil prices have dropped since hitting a high of $75/bbl for Brent in April. Slower world economic growth and the US-China trade dispute have undercut prices along with the rise in US production. The 11 OPEC members that are participating in the deal actually exceeded their required cuts, reaching 143% of compliance in May, according to the Reuters news agency. The producers’ group formed after oil prices began to fall sharply in the summer of 2014, from over $100/bbl to eventually under $30/bbl because of a supply glut caused primarily from a huge increase in US unconventionals output. In the first half of this year, world supply exceeded demand by 900,000 B/D, according to the IEA, which means OPEC may need to lower its cumulative production to its lowest level in 17 years next year to keep markets balanced. “Clearly, market tightness is not an issue for the time being and any rebalancing seems to have moved further into the future,” the IEA said in its monthly report issued in July. Global oil demand growth in the first quarter of this year was the slowest since 2011 and rose less than expected in the second quarter, according to the IEA. In addition, non-OPEC production, led by US shale, continued to expand. The task by producers trying to keep the market in balance will be even tougher next year. The IEA lowered its forecast for 2020 and increased its projections for non-OPEC output. That means the oil needed from OPEC will again decline, to well below its current output rate. About 29.1 million B/D will be required from OPEC next year, compared with output of 29.9•million B/D currently. OPEC production is already running below normal given the voluntary cutbacks and the crisis in Venezuela. “The picture will evolve as 2019 progresses but in the near term the main focus remains (world) demand growth,” the IEA said. The US Energy Information Administration lowered its oil demand growth forecast to 1.1 million B/D in its latest Short-Term Energy Outlook, issued in July. A year ago, it predicted global growth of 1.4 million B/D. It now predicts that US oil production will average 12.4 million B/D this year and 13.3 million B/D next year.

Editor's column With the shale industry still awash in red ink, and oil prices falling, it may take more consolidation to try to bring some financial stability to the sector. The financing strategy of the shale sector has always differed from onshore conventional oil business models. The small and medium-sized independents that have dominated shale have operated with much higher levels of debt and, since the beginning of the unconventional rise, have operated with negative free cash flow. Although production has skyrocketed, profitability has not, and Wall Street investors have grown tired of financing a largely unprofitable piece of the oil and gas business. The International Energy Agency (IEA) predicted last year that the shale industry would finally achieve positive free cash flow this year as oil prices rebounded and new pipelines relieved bottlenecks that had depressed prices. But the sharp downturn in oil prices in the fourth quarter and the recent decline to near $50/bbl (WTI) has not helped. When the shale boom was taking off between 2010 and 2014, high oil prices led to huge financial backing. Investment quadruped during that period, according to the IEA, as oil production increased from 0.44 million B/D to 3.6 million B/D, the fastest oil growth since the advent of Saudi Arabia’s giant oil fields in the 1960s. When oil prices tanked beginning in 2014, shale firms, along with the rest of the industry, switched to sharply cutting costs and trying to instill capital discipline. It was too much for some. More than a hundred shale firms filed for bankruptcy during 2015–16. Banks became more reluctant to lend money, even after oil prices began to recover, leading to a wave of lending from private equity firms. Production from the sector continued to defy odds, but profitability was still not in sight. BP’s most recent bellwether Statistical Review of World Energy, released in June, noted that US oil and gas production growth accelerated in 2018 at another record pace. The production growth “exceeded any other country’s annual increase in our 50-year history” of publishing the review, said BP Chief Economist Dale Spencer. “Indeed, the US achieved a unique double-first last year, recording the single largest-ever annual increase by any country in both oil and gas production. In case there was any doubt, the US shale revolution is alive and kicking,” he said. Since 2012, US oil production, including natural gas liquids, has grown by more than 7 million B/D, “broadly equivalent to Saudi Arabia’s crude oil exports, an astonishing increase which has trans-formed both the structure of the US economy and global market dynamics,” he added. But how long this revolution can continue without solid economic footing is unclear. One trend under way is consolidation. Two years ago, many independents began selling off assets so they could continue drilling. Today, many are pursuing assets sales, drilling partnerships, and other alternative financing strategies, according to an article in The Wall Street Journal. A new wave of company consolidations and buyouts by larger firms may have started. Chevron attempted to buy Anadarko and its sizable presence in the Permian Basin but was beat out by Occidental. Although Shell and other majors have indicated that, while interested, current selling prices for some companies appear too steep, the Anadarko deal could be the first of many that attempts to bring some stability to the shale sector and increases the presence of larger, more diversified firms.

Editor's column Although the shale sector continues to thrive, the pace of deepwater E&P is now gradually picking up. Offshore is making a comeback after the harsh cutbacks that followed the oil price drop that began 5 years ago. The downturn saw declines in exploration spending, final investment decisions, and production. But it is now rebounding, as capital expenditure increases and a number of new finds in promising basins bolster optimism. A survey of industry executives released last month shows renewed confidence in exploration. Attractive plays in “deepwater sweet spots” such as Brazil, Guyana, Gulf of Mexico, and east Mediterranean are attracting the most attention from operators, according to the Wood Mackenzie survey of 258 executives involved in E&P. Noteworthy is the increasing amount of money being spent on digitalization in global exploration budgets. About half of operators’ budgets are going for drilling and a fourth for geological surveys, but digitalization now accounts for 8% of the total budget and will likely rise as new seismic processing techniques, artificial intelligence, and machine learning become basic tools for exploration. “Digitalization offers exploration the possibility of better resolution of the subsurface, better seismic modeling, and growing use of automated interpretation,” said Andrew Latham, Wood Mackenzie vice president of exploration. “The survey results back up our expectation that the exploration industry, led by the majors, will spend billions each year on digitalization.” Some 22% of the executives surveyed said exploration projects can break even with Brent in a $55–60/bbl price band while 18% would be happy with a $45–50/bbl price range. Before the oil price crash, companies saw a break-even Brent price of $80/bbl. A challenge for operators, especially since the oil price downturn, is keeping costs down. At a panel discussion at this year’s Offshore Technology Conference, representatives of operators noted that companies have made great strides in this area, largely driven by standardization and simplifying projects. US Gulf of Mexico breakeven costs are now as low as in the $30/bbl range, compared with a $50/bbl range a few years ago, according to one of the panelists, Chris Golden, a senior vice president for Equinor. A number of new discoveries show renewed interest in offshore, particularly Latin America. Shell plans to drill its first two deepwater wells offshore Mexico this December in the Perdido Basin, and will likely drill more next year, according to Martin Stauble, Shell’s vice president of exploration for North America and Brazil. Shell and ExxonMobil recently won acreage offshore Colombia, which is trying to revitalize its E&P, and a number of major operators have been active in Brazil licensing rounds. And Argentina’s held its first open bid round for offshore acreage in more than 20 years in April. ExxonMobil has also made a number of major discoveries offshore Guyana. Its Liza Phase 2 project received government and regulatory approvals in May and remains on track for first oil by early 2020 and will produce up to 220,000 B/D by mid-2022.

Editor's column Natural gas, often hailed as the bridge to an energy future that will include greater demand for alternative energy supplies, may be poised to overtake oil as the globe’s primary fuel source in the next decade. While the 20th century was the Age of Oil, the 21st century will be a combination of both old and new energy sources, Shell executive Maarten Wetselaar said at the recent CERA energy conference in Houston. Oil must now share the stage with gas and a variety of fuels, said Wetselaar, who is the company’s integrated gas and new energies director. The use of coal is projected to decrease in several developing countries trying to reduce carbon emissions, paving the way for increased use of gas and renewable energy for electricity. The European Union is threatening to fine its member nations that do not implement a carbon emissions strategy, and China is in the third year of a 5-year plan designed to limit fossil fuel consumption. Many other Asian countries are following suit. BP’s most recent Statistical Review of World Energy stated that in 2018 gas accounted for the largest gain in world energy consumption, followed by renewables and then oil. These developments, along with new supplies of gas produced by the US shale sector, is raising the status of gas from a regional fuel to a global commodity. Gas trade grew 6% last year, according to BP, with LNG trade surpassing traditional pipeline transactions. Historically, most gas has been transported by pipeline. But vast new sources of gas, from offshore Australia and US shale, have led to the building of LNG ports for export and the creation of new trade routes, principally to Asia. Four new liquefaction plants are being built along the Gulf Coast in the US, which only exported its first LNG cargo in 2016. In addition, Qatar plans to increase LNG output by more than 40% over the next 5 years, building four new LNG trains, according to consultancy DNV-GL. Global demand for LNG rose by 27 million tonnes last year to 319 million tonnes, according to Shell’s LNG Outlook. Demand is forecast to reach 384 million tonnes by 2020. But LNG buyers and sellers are still struggling with pricing. Gas has generally been sold through long-term contracts because of the absence of a spot trade. LNG has often been sold on oil-indices contracts, but the wide swings in oil prices don’t reflect LNG economics. Buyers would like more transparency to reflect regional supply/demand dynamics. A proposed gas cartel formed by some of the world’s largest gas producers—kind of a gas OPEC—has never gotten off the ground. An oil pricing service has introduced the Japan Korean Marker as a possibility, to be used for pricing Asian spot cargoes. And Cheniere and CME Group plan to develop a Henry Hub-indexed futures contract with physical delivery to the US Gulf Coast. The use of any nonoil-indexed mechanism will only increase the stature of LNG as a viable energy commodity.

Editor's column Another industry report issued last month touts the coming gains in US shale, predicting that the country will soon be the largest oil producer and possibly exporter in the world. The International Energy Agency’s (IEA) Oil 2019, a 5-year outlook on the global energy industry, touts the “second wave” of the shale sector, which will transform oil markets worldwide. The IEA says the US will lead the way in oil supply growth over the next 5 years because of continued growth in shale, primarily from the Permian Basin. By the end of that 5-year period, the US will surpass Russia and be close to Saudi Arabia in total oil exports. Although consumption from China will decline and the use of electric vehicles will grow, demand will be stronger for jet fuel and petrochemicals, leading to an annual global increase of 1.2 million B/D. US oil output will account for almost three-fourths of the supply increase over the period, growing a total of 4.4 million B/D, following a production increase of 2.2 million B/D in 2018. “The second wave of the US shale revolution is coming,” IEA Executive Director Fatih Birol said in releasing the report. US oil output, including natural gas liquids, will rise to 19.6 million B/D by 2024. Excluding liquids, oil production will increase from the current 11 million B/D to 13.7 million B/D. One transformation taking place in the US shale sector is the entry of majors. Independents have dominated the play so far, led by such companies as Pioneer and Apache. But the short-cycle production time and geopolitical safety is increasingly attracting interest from large firms such as ExxonMobil, Chevron, and ConocoPhillips. ExxonMobil and Chevron announced plans last month to increase spending even more in the Permian Basin over the next few years. Although the industry has consistently underestimated US shale growth, some producers and engineers have a more nuanced outlook for the sector. There are potential hurdles to overcome if shale is going to continue to be the star in the global supply picture. Steep decline curves, parent-child well interference (or frac hits), and perhaps even a lower inventory of high-quality drilling locations are concerns. The issue of frac hits dominated discussion at the recent SPE Hydraulic Fracturing Technology Conference. Parent-child well interactions may be lowering oil recovery factors from new child wells by 20–40% while also causing losses on older, yet less productive, parent wells, according to US and Canadian operators. That has led Mark Papa, one of the pioneers in US shale and chief executive officer of Centennial Development Resources, to become less optimistic about the future of US shale production. Frac hits and fewer high-quality drilling options may force a lower ceiling on shale, undermining these optimistic forecasts, which leads him to believe that the shale sector is already in its mature phase of producibility, he said during a panel discussion at the IHS Markit CERAWeek conference in Houston last month. But panelist Greg Powers, vice president of global innovation at Halliburton, cautioned that most of the learnings from shale to date have been experiential, not fundamental, and that a lot of the resource is still in the ground. In addition, he said, the chemistry of hydraulic fracturing is still a bit of a mystery. In other words, there is still much to figure out before concluding whether shale’s second act is its final one.

Editor's column Last year, the SPE Board of Directors approved a new 5-year Strategic Plan, a blueprint to provide guidance on how the association can meet the needs and expectations of its members and the industry over the next several years. The plan identified four strategic areas of emphasis to advance its vision in the near term: lifelong learning, knowledge transfer, membership engagement, and professional pride. It is the professional pride piece of that document that this issue of JPT is built around. The professional pride segment identifies objectives such as helping SPE members better understand and become more inspired by the industry’s contributions to society, demonstrating the benefits of oil and gas so members can communicate that positive value to the public, and highlighting industry achievements as well as contributions to sustainability and social responsibility. With that backdrop, the 45-page special section in this issue covers three main areas: What satisfaction do petroleum engineers receive from the work they do? What value does oil and gas bring to individuals and to society? What trends and challenges will help define the future work of petroleum engineers? JPT invited a variety of engineers to participate to ensure a broad perspective. In these pages, you will read about what practicing petroleum professionals value about their careers and what brings them the most reward; what specific contributions the industry is making to society, including some you might not regularly hear about in the media; some great individual and technical achievements; how to communicate these successes and contributions to an often skeptical public; and what issues the industry will confront in the coming years. One of these issues is climate change, and no report on the oil and gas industry’s future would be complete without some discussion of this topic. But there is not universal agreement—in the public, in the industry, or in these pages—on the best approach to take in addressing this issue. Nor is there agreement throughout the industry on future hydrocarbons demand and what role oil and gas will play in the global energy mix a decade or two from now. Industry reports from companies and consultancies often lay out different scenarios about hydrocarbon demand in the future and the “transition” to renewables. Some predict declines in crude demand for transportation because of the increased use of electric vehicles, while others see almost insatiable appetites for all forms of energy, both traditional and new. The oil and gas industry will likely look a lot different 10 or 20 years from now. But the role of petroleum engineers may not. The job of solving problems, figuring out how to get the most oil and gas out of the ground with the smallest environmental footprint, and ensuring that the world has sufficient energy to improve quality of life will continue.

Background Dyslipidemia is a risk factor for cardiovascular disease, with elevated low-density lipoprotein cholesterol (LDL-C) and decreased high-density lipoprotein cholesterol (HDL-C) recognized as risk factors for acute coronary events. Studies suggest an association between low cholesterol levels and poor outcomes in acute sepsis. We sought to determine the relationship between baseline cholesterol levels and long-term rates of sepsis. Methods We used data from the Reasons for Geographic and Racial Differences in Stroke (REGARDS) cohort, a population-based cohort of 30,239 community-dwelling adults. The primary outcome was first sepsis event, defined as hospitalization for an infection with the presence of ≥2 systemic inflammatory response syndrome criteria (abnormal temperature, heart rate, respiratory rate, white blood cell count) during the first 28 hours of hospitalization. Cox models assessed the association between quartiles of HDL-C or LDL-C and first sepsis event, adjusted for participant demographics, health behaviors, chronic medical conditions, and biomarkers. Results We included 29,690 subjects with available baseline HDL-C and LDL-C. There were 3423 hospitalizations for serious infections, with 1845 total sepsis events among 1526 individuals. Serum HDL-C quartile was not associated with long-term rates of sepsis (hazard ratio (HR) (95% CI): Q1 (HDL-C 5–40 mg/dl), 1.08 (0.91–1.28); Q2 (HDL-C 41–49 mg/dl), 1.06 (0.90–1.26); Q3 (HDL-C 50–61 mg/dl), 1.04 (0.89–1.23); Q4, reference). However, compared with the highest quartile of LDL-C, low LDL-C was associated with higher rates of sepsis (Q1 (LDL-C 3–89 mg/dl), 1.30 (1.10–1.52); Q2 (LDL-C 90–111 mg/dl), 1.24 (1.06–1.47); Q3 (LDL-C 112–135 mg/dl), 1.07 (0.91–1.26); Q4, reference). Conclusion Low LDL-C was associated with higher long-terms rates of community-acquired sepsis. HDL-C level was not associated with long-term sepsis rates. Electronic supplementary material The online version of this article (doi:10.1186/s13054-016-1579-8) contains supplementary material, which is available to authorized users.

Background and Purpose— Readmission within 30 days of hospital discharge for ischemic stroke is an important quality of care metric. We aimed to provide nationwide estimates of 30-day readmission in the United States, describe important reasons for readmission, and sought to explore factors associated with 30-day readmission, particularly the association with recanalization therapy. Methods— We conducted a weighted analysis of the 2013 Nationwide Readmission Database to represent all US hospitalizations. Adult patients with acute ischemic stroke including those who received intravenous tissue-type plasminogen activator and intra-arterial therapy were identified using International Classification of Diseases -Ninth Revision codes. Readmissions were defined as any readmission during the 30-day post-index hospitalization discharge period for the eligible patient population. Proportions and 95% confidence intervals for overall 30-day readmissions and for unplanned and potentially preventable readmissions are reported. Survey design logistic regression models were fit for determining crude and adjusted odds ratios and 95% confidence interval for association between recanalization therapy and 30-day readmission. Results— Of the 319 317 patients with acute ischemic stroke, 12.1% (95% confidence interval, 11.9–12.3) were readmitted. Of these, 89.6% were unplanned and 12.9% were potentially preventable. More than 20% of all readmissions were attributable to acute cerebrovascular disease. Readmitted patients were older and had a higher comorbidity burden. After controlling for age, sex, insurance status, and comorbidities, patients who underwent recanalization therapy had significantly lower odds of 30-day readmission (odds ratio, 0.82; 95% confidence interval, 0.77–0.89). Conclusions— Up to 12% of patients with ischemic stroke get readmitted within 30 days post-discharge period, and recanalization therapy is associated with 11% to 23% lower odds of 30-day readmission.

Epidemiologic and experimental evidence suggests that individuals with diabetes are at increased risk of infection. We sought to examine the association of diabetes and insulin therapy with hospitalization for infection and 28-day mortality.We performed a prospective cohort study using data from 30 239 community-dwelling participants aged ≥45 years enrolled in the REasons for Geographic and Racial Differences in Stroke (REGARDS) study. We defined diabetes as a fasting glucose level ≥126 mg/L (or ≥200 mg/L for those not fasting), the use of insulin or oral hypoglycemic agents, or self-reported history. We identified infection-related hospitalizations over the years 2003–2012. We fit Cox proportional hazards models to assess the association of diabetes with hazard rates of infection and logistic regression models for 28-day mortality.Among 29 683 patients from the REGARDS study with complete follow-up, 7375 had diabetes. Over a median follow-up period of 6.5 years, we identified 2593 first and 3411 total infection hospitalizations. In adjusted analyses, participants with diabetes had an increased hazard of infection (hazard ratio, 1.50; 95% confidence interval [CI], 1.37–1.64) compared with those without diabetes. Participants with diabetes hospitalized for infection did not have an increased odds of death within 28 days (odds ratio, 0.94; 95% CI, .67–1.32). Participants receiving insulin therapy had greater hazard of infection (hazard ratio, 2.18; 95% CI, 1.90–2.51) but no increased odds of mortality (odd ratio, 1.07; 95% CI, .67–1.71).Diabetes is associated with increased risk of hospitalization for infection. However, we did not find an association with 28-day mortality. Insulin therapy conferred an even greater risk of hospitalization, without increased mortality.

Background Emergency departments (EDs) play a growing role in hospital admissions for older adults, yet nationally representative data on predictors of admission from the EDs are limited. Methods We examined sociodemographic, clinical, and hospital characteristics associated with non-ICU admissions, using National Hospital Ambulatory Medical Care Survey data and multivariate Poisson regression models. Results There were an estimated 175 million ED visits by adults older than 65 years from 2001 to 2010. Overall, 32.5% were admitted to non-ICU beds. In multivariate analysis, non-ICU admission was associated with increasing age (16% higher per 10-year increase in age), white versus black race (35% vs 31%), and EDs in the Northeast (40%) or Midwest (38%) versus South (31%) or West (30%). Conclusion Non-ICU admission rates for older adults receiving care in U.S. EDs vary by age, race, and region. Understanding the reasons for these disparities in hospitalization rates may guide interventions to reduce hospitalizations in older adults.

In the United States, sepsis is a major public health problem accounting for over 200,000 annual deaths. The aims of this study were to identify U.S. counties with high sepsis mortality and to assess the community characteristics associated with increased sepsis mortality.We performed a descriptive analysis of 2003 through 2012 Compressed Mortality File data. We defined sepsis deaths as deaths associated with an infection, classified according to the International Classification of Diseases, 10th Version.Three thousand one hundred and eight counties in the contiguous U.S. counties, excluding Hawaii and Alaska.Using geospatial autocorrelation methods, we defined county-level sepsis mortality as strongly clustered, moderately clustered, and nonclustered. We approximated the mean crude, age-adjusted, and community-adjusted sepsis mortality rates nationally and for clustering groups. We contrasted demographic and community characteristics between clustering groups. We performed logistic regression for the association between strongly clustered counties and community characteristics. Among 3,108 U.S. counties, the age-adjusted sepsis mortality rate was 59.6 deaths per 100,000 persons (95% CI, 58.9-60.4). Sepsis mortality was higher in the Southern U.S. and clustered in three major regions: Mississippi Valley, Middle Georgia, and Central Appalachia. Among 161 (5.2%) strongly clustered counties, age-adjusted sepsis mortality was 93.1 deaths per 100,000 persons (95% CI, 90.5-95.7). Strongly clustered sepsis counties were more likely to be located in the south (92.6%; p0.001), exhibit lower education, higher impoverished population, without medical insurance, higher medically uninsured rates, and had higher unemployment rates (p0.001).Sepsis mortality is higher in the Southern United States, with three regional clusters: "Mississippi Valley," "Middle Georgia," and "Central Appalachia": Regions of high sepsis mortality are characterized by lower education, income, employment, and insurance coverage.

Background and Objective: Transcranial Doppler (TCD) is endorsed by the American Heart Association/American Stroke Association, the American Academy of Neurology, and the Neurocritical Care Society for use in aneurysmal subarachnoid hemorrhage (aSAH) for surveillance of cerebral vasospasm (CV). However, data on utilization of TCD for CV detection and monitoring in aSAH are lacking. We estimated the proportion of patients with aSAH receiving TCD monitoring using the Nationwide Inpatient Sample (NIS). Methods: Data from 2002-2011 NIS were used to calculate the number of discharges with a primary diagnosis of aSAH per 100,000 discharges. Descriptive analysis of nationwide trends in TCD prevalence was performed. Teaching hospitals were examined separately for TCD utilization rates and this was done biennially to prevent small numbers. Results: Between 2002 and 2011, a total of 256,089 patients were discharged with a diagnosis of aSAH of which 3,850 underwent TCD monitoring. aSAH accounted for an average of 67.1 discharges per 100,000 annually (95% CI 61.3-72.8) from 2002-2011. Of these, only 1.5% (95% CI 0.4-2.6) underwent TCD examination. In teaching hospitals, aSAH accounted for an average of 108.5 discharges per 100,000 biennially (95% CI, 96.2-120.8), of which 2% (95% CI 1.0-4.0) underwent TCD examination. TCD utilization increased from Conclusion: TCD is underutilized nationally in the care of aSAH. While the prevalence of TCD is low in teaching hospitals, it is nearly nonexistent in non-teaching hospitals.