ALBERT

Description: Posttransplantation lymphoproliferative disorder (PTLD) is a life-threatening Epstein-Barr virus (EBV)–associated B-cell malignancy occurring in 1% to 2% of renal transplantation patients. Host- and PTLD-related factors determining the likelihood of tumor response following reduction of immune suppression (IS) and antiviral therapy remain largely unknown. Standard therapy for PTLD is not well established. Eleven consecutive renal transplantation patients who developed EBV-positive PTLD 8 to 94 months after allografting were uniformly treated with acyclovir and IS reduction. All PTLDs were EBV-positive diffuse large B-cell lymphomas. Ten patients (91%) obtained a durable complete response (CR), and 9 (82%) have remained in continuous CR with a median follow-up of 29 months. Five patients (45%) lost their allograft. Of these, 4 patients had PTLD affecting the transplanted kidney. Peripheral blood CD8+ T cells increased significantly (P = .0078) from baseline in 8 responders available for analysis. One of 2 patients whose absolute CD8+ T-cell count subsequently dropped to baseline after IS reduction relapsed. The expanded CD8+ T cells from 2 responders specifically recognized an immunodominant peptide from the EBV lytic gene BZLF-1. Another lytic EBV gene, thymidine kinase, was expressed in all 8 PTLDs tested. IS reduction and antiviral therapy for PTLD after renal transplantation is a highly successful therapeutic combination, but the risk of graft rejection is significant, particularly in patients with PTLD involving the renal allograft. A sustained expansion of CD8+ T cells and a cellular immune response to EBV lytic antigens may be important for PTLD clearance in renal transplantation patients.

Description: Detailed biomarker and light hydrocarbon geochemistry confirm that the marine Mississippian Barnett Shale is the primary source rock for petroleum in the Fort Worth Basin, north-central Texas, although contributions from other sources are possible. Biomarker data indicate that the main oil-generating Barnett Shale facies is marine and was deposited under dysoxic, strong upwelling, normal salinity conditions. The analysis of two outcrop samples and cuttings from seven wells indicates variability in the Barnett Shale organic facies and a possibility of other oil subfamilies being present. Light hydrocarbon analyses reveal significant terrigenous-sourced condensate input to some reservoirs, resulting in terrigenous and mixed marine-terrigenous light hydrocarbon signatures for many oils. The light hydrocarbon data suggest a secondary, condensate-generating source facies containing terrigenous or mixed terrigenous-marine organic matter. This indication of a secondary source rock that is not revealed by biomarker analysis emphasizes the importance of integrating biomarker and light hydrocarbon data to define petroleum source rocks. Gases in the Fort Worth Basin are thermogenic in origin and appear to be cogenerated with oil from the Barnett Shale, although some gas may also originate by oil cracking. Isotope data indicate minor contribution of biogenic gas. Except for reservoirs in the Pennsylvanian Bend Group, which contain gases spanning the complete range of observed maturities, the gases appear to be stratigraphically segregated, younger reservoirs contain less mature gas, and older reservoirs contain more mature gas. We cannot rule out the possibility that other source units within the Fort Worth Basin, such as the Smithwick Shale, are locally important petroleum sources. Ronald Hill specializes in petroleum geochemistry and has more than 12 years of professional experience, which includes his years in ExxonMobil and Chevron. Currently, he is a research geologist for the U.S. Geological Survey. His interests include the investigation of shale-gas resources and the processes that control petroleum generation. He holds geology degrees from the Michigan State University (B.S. degree), the University of California, Los Angeles (Ph.D.), and a geochemistry degree from the Colorado School of Mines (M.S. degree). Dan Jarvie is an analytical and interpretive organic geochemist. He works on conventional hydrocarbon systems and has worked on unconventional shale-oil and shale-gas hydrocarbon systems since 1984 and the Barnett Shale since 1989. He earned a B.S. degree from the University of Notre Dame and was mentored in geochemistry by Wallace Dow and Don Baker of Rice University. He is the president of Humble Geochemical Services. John E. Zumberge is a cofounder of GeoMark Research in Houston and has been vice president since GeoMark was founded in 1991. He was manager of geochemical and geological research for Cities Service–Occidental, general manager for Ruska Laboratories, and director of geochemical services for Core Laboratories. He has global experience in petroleum geochemistry, focusing on crude-oil biomarkers. He obtained a B.S. degree in chemistry from the University of Michigan and a Ph.D. in organic geochemistry from the University of Arizona. Mitchell Henry received a Bachelor of Science degree in biology from Midwestern University, Wichita Falls, Texas, in 1969. He was awarded a Master of Science degree in Oceanography from Texas A&M University, College Station, Texas, in 1974, and earned a Ph.D. also from Texas A&M in 1982. He joined the U.S. Geological Survey in 1974 and retired from that organization in 2005. His primary interests were in remote sensing, direct detection of geochemical anomalies related to petroleum microseepage, and the application of computer analysis to basin studies. His most recent assignments were related to domestic and international petroleum resource assessments, basin analysis, and hydrocarbon source rock studies. Rich Pollastro received an M.A. degree in geology from the State University of New York at Buffalo in 1977. Rich joined the U.S. Geological Survey in 1978 and serves as a province geologist on the national and world energy assessment projects. His recent accomplishments include petroleum system assessments of the Fort Worth, Permian, and South Florida basins and the Arabian Peninsula.

Description: The Lower Cretaceous Mannville Group oil sands of northern Alberta have an estimated 270.3 billion m3 (BCM) (1700 billion bbl) of in-place heavy oil and tar. Our study area includes oil sand accumulations and downdip areas that partially extend into the deformation zone in western Alberta. The oil sands are composed of highly biodegraded oil and tar, collectively referred to as bitumen, whose source remains controversial. This is addressed in our study with a four-dimensional (4-D) petroleum system model. The modeled primary trap for generated and migrated oil is subtle structures. A probable seal for the oil sands was a gradual updip removal of the lighter hydrocarbon fractions as migrated oil was progressively biodegraded. This is hypothetical because the modeling software did not include seals resulting from the biodegradation of oil. Although the 4-D model shows that source rocks ranging from the Devonian–Mississippian Exshaw Formation to the Lower Cretaceous Mannville Group coals and Ostracode-zone-contributed oil to Mannville Group reservoirs, source rocks in the Jurassic Fernie Group (Gordondale Member and Poker Chip A shale) were the initial and major contributors. Kinetics associated with the type IIS kerogen in Fernie Group source rocks resulted in the early generation and expulsion of oil, as early as 85 Ma and prior to the generation from the type II kerogen of deeper and older source rocks. The modeled 50% peak transformation to oil was reached about 75 Ma for the Gordondale Member and Poker Chip A shale near the west margin of the study area, and prior to onset about 65 Ma from other source rocks. This early petroleum generation from the Fernie Group source rocks resulted in large volumes of generated oil, and prior to the Laramide uplift and onset of erosion (∼58 Ma), which curtailed oil generation from all source rocks. Oil generation from all source rocks ended by 40 Ma. Although the modeled study area did not include possible western contributions of generated oil to the oil sands, the amount generated by the Jurassic source rocks within the study area was 475 BCM (2990 billion bbl). Debra Higley has 5 years experience in uranium exploration and 26 years as a research geologist with the U.S. Geological Survey. Her research interests include reservoir characterization, petroleum system modeling, and petroleum resource assessment in basins in North and South America. She received her M.S. degree in geochemistry and Ph.D. in geology from the Colorado School of Mines, and her B.S. degree in geology from Mesa State College, Colorado. Mike Lewan is an organic geochemist and petroleum geologist for the Central Energy Resources Team of the U. S. Geological Survey (Denver, Colorado). Prior to his 17 years with the U.S. Geological Survey, he worked for 13 years at the Amoco Production Co. Research Center (Tulsa, Oklahoma) and 3 years with Shell Oil Co. Offshore E&P Office (New Orleans, Louisiana). He received his Ph.D. from the University of Cincinnati, M.S. degree from Michigan Technology University, and B.S. degree from Northern Illinois University. Laura Roberts graduated with a degree in geology from Colorado College. She is a recently retired emeritus scientist who had worked for the U.S. Geological Survey since 1977. Her research includes coal geology and coal resource assessment of the Fort Union Formation in the northern Powder River Basin, Montana, and the Cretaceous coals of the Colorado Plateau, and the burial and thermal history of petroleum source rocks in the Uinta-Piceance and Wind River basins. Mitchell Henry retired from the U.S. Geological Survey after 30 years of research in direct geochemical detection and remote sensing of hydrocarbons, and domestic and international petroleum resource assessments. He received his B.S. degree from Midwestern University and his M.S. degree and a Ph.D. from Texas A&M University.