Crude Oil fell to 64.78 USD/Bbl on July 1, 2025, down 0.50% from the previous day. Over the past month, Crude Oil's price has risen 3.62%, but it is still 21.77% lower than a year ago, according to trading on a contract for difference (CFD) that tracks the benchmark market for this commodity. Crude Oil - values, historical data, forecasts and news - updated on July of 2025.

This dataset contains information about world's oil production for 1965-2020. Data from BP. Follow datasource.kapsarc.org for timely data to advance energy economics research.Notes:* Includes crude oil, shale oil, oil sands and NGLs (natural gas liquids - the liquid content of natural gas where this is recovered separately).Excludes liquid fuels from other sources such as biomass and derivatives of coal and natural gas.# Excludes Estonia, Latvia and Lithuania prior to 1985 and Slovenia prior to 1990.

One of America's most serious energy problems is the premature abandonment of still-productive domestic oil fields. Already, over half of the crude oil discovered in the United States lies in fields that were abandoned when they became no longer Viable economically and the rate of abandonment is accelerating. As much as 70 percent of the Nation's remaining oil resources could be lost by shortly after the year 2000. The high capital costs of drilling wells and returning pumps, piping, tanks, and other equipment to these fields (and, in some cases, the difficulties of restoring production leases) make it unlikely that abandoned fields will ever be reopened, even if oil prices rise in the future. Unless slowed, the trend to abandonment will lead directly to further job losses and declining oil production.

Crude Oil Production in Venezuela increased to 1066 BBL/D/1K in May from 1051 BBL/D/1K in April of 2025. This dataset provides the latest reported value for - Venezuela Crude Oil Production - plus previous releases, historical high and low, short-term forecast and long-term prediction, economic calendar, survey consensus and news.

This project represents the data used in “Influences of potential oil and gas development and future climate on sage-grouse declines and redistribution.” The data sets describe greater sage-grouse (Centrocercus urophasianus) population change, summarized in different boundaries within the Wyoming Landscape Conservation Initiative (WLCI; southwestern Wyoming). Population changes were based on different scenarios of oil and gas development intensities, projected climate models, and initial sage-grouse population estimates. Description of data sets pertaining to this project: Greater sage-grouse population change (percent change) in a high oil and gas development, low population estimate scenario, and with and without effects of climate change. 1. Greater sage-grouse population change (percent change) over 50-years in a high oil and gas development, low population estimate scenario, and with effects of climate change under an RCP 8.5 scenario (2050) 2. Greater sage-grouse population change (percent change) in a low oil and gas development, high population estimate scenario, and with no effects of climate change (2006-2062) 3. Greater sage-grouse population change (percent change) over 50-years in a low oil and gas development, low population estimate scenario, and with effects of climate change under an RCP 8.5 scenario (2050) 4. Greater sage-grouse population change (percent change) in a moderate oil and gas development, high population estimate scenario, and with no effects of climate change (2006-2062) 5. Greater sage-grouse population change (percent change) in a high oil and gas development, low population estimate scenario, and with no effects of climate change (2006-2062) The oil and gas development scenario were based on an energy footprint model that simulates well, pad, and road patterns for oil and gas recovery options that vary in well types (vertical and directional) and number of wells per pad and use simulation results to quantify physical and wildlife-habitat impacts. I applied the model to assess tradeoffs among 10 conventional and directional-drilling scenarios in a natural gas field in southwestern Wyoming (see Garman 2017). The effects climate change on sagebrush were developed using the National Center for Atmospheric Research (NCAR) Community Climate System Model (CCSM, version 4) climate model and representative concentration pathway 8.5 scenario (emissions continue to rise throughout the 21st century). The projected climate scenario was used to estimate the change in percent cover of sagebrush (see Homer et al. 2015). The percent changes in sage-grouse population sizes represented in these data are modeled using an individual-based population model that simulates dynamics of populations by tracking movements of individuals in dynamically changing landscapes, as well as the fates of individuals as influenced by spatially heterogeneous demography. We developed a case study to assess how spatially explicit individual based modeling could be used to evaluate future population outcomes of gradual landscape change from multiple stressors. For Greater sage-grouse in southwest Wyoming, we projected oil and gas development footprints and climate-induced vegetation changes fifty years into the future. Using a time-series of planned oil and gas development and predicted climate-induced changes in vegetation, we re-calculated habitat selection maps to dynamically modify future habitat quantity, quality, and configuration. We simulated long-term sage-grouse responses to habitat change by allowing individuals to adjust to shifts in habitat availability and quality. The use of spatially explicit individual-based modeling offered an important means of evaluating delayed indirect impacts of landscape change on wildlife population outcomes. This process and the outcomes on sage-grouse population changes are reflected in this data set.

The Petroleum Recovery Research Center (PRRC), the only research center of its kind in New Mexico, is a scientific research organization dedicated to solving problems related to the oil and gas industry.

This dataset contains information about world's oil proved reserves for 1980-2020. Data from BP. Follow datasource.kapsarc.org for timely data to advance energy economics research.Notes:^ Less than 0.05.w Less than 0.05%.# Excludes Estonia, Latvia and Lithuania prior to 1996 and Slovenia prior to 1990.— 'Remaining established reserves', less reserves 'under active development'.Notes:Total proved reserves of oil - Generally taken to be those quantities that geological and engineering information indicates with reasonable certaintycan be recovered in the future from known reservoirs under existing economic and operating conditions. The data series for total proved oil does not necessarilymeet the definitions, guidelines and practices used for determining proved reserves at company level, for instance as published by the US Securities and Exchange Commission,nor does it necessarily represent BP’s view of proved reserves by country.Reserves-to-production (R/P) ratio - If the reserves remaining at the end of any year are divided by the production in that year, the result is the length of time that those remaining reserves would last ifproduction were to continue at that rate.Source of data - The estimates in this table have been compiled using a combination of primary official sources, third-party data from the OPEC Secretariat, World Oil, Oil &Gas Journal and an independent estimates of Russian reserves based on official data and Chinese reserves based on information in the public domain.Canadian oil sands 'under active development' are an official estimate. Venezuelan Orinoco Belt reserves are based on the OPEC Secretariat and government announcements.Reserves include gas condensate and natural gas liquids (NGLs) as well as crude oil.Annual changes and shares of total are calculated using thousand million barrels figures.

Crude Oil Production in Saudi Arabia increased to 9184 BBL/D/1K in May from 9005 BBL/D/1K in April of 2025. This dataset provides the latest reported value for - Saudi Arabia Crude Oil Production - plus previous releases, historical high and low, short-term forecast and long-term prediction, economic calendar, survey consensus and news.

This digital dataset contains historical geochemical and other information for 200 samples of produced water from 182 sites in 25 oil fields in Los Angeles and Orange Counties, southern California. Produced water is a term used in the oil industry to describe water that is produced as a byproduct along with the oil and gas. The locations from which these historical samples have been collected include 152 wells. Well depth and (or) perforation depths are available for 114 of these wells. Sample depths are available for two additional wells in lieu of well or perforation depths. Additional sample sites include four storage tanks, and two unidentifiable sample sources. One of the storage tank samples (Dataset ID 57) is associated with a single identifiable well. Historical samples from other storage tanks and unidentifiable sample sources may also represent pre- or post-treated composite samples of produced water from single or multiple wells. Historical sample descriptions provide further insight about the site type associated with some of the samples. Twenty-four sites, including 21 wells, are classified as "injectate" based on the sample description combined with the designated well use at the time of sample collection (WD, water disposal or WF, water flood). Historical samples associated with these sites may represent water that originated from sources other than the wells from which they were collected. For example, samples collected from two wells (Dataset IDs 86 and 98) include as part of their description “blended and treated produced water from across the field”. Historical samples described as formation water (45 samples), including 38 wells with a well type designation of OG (oil/gas), are probably produced water, representing a mixture of formation water and water injected for enhanced recovery. A possible exception may be samples collected from OG wells prior to the onset of production. Historical samples from four wells, including three with a sample description of "formation water", were from wells identified as water source wells which access groundwater for use in the production of oil. The numerical water chemistry data were compiled by the U.S. Geological Survey (USGS) from scanned laboratory analysis reports available from the California Geologic Energy Management Division (CalGEM). Sample site characteristics, such as well construction details, were attributed using a combination of information provided with the scanned laboratory analysis reports and well history files from CalGEM Well Finder. The compiled data are divided into two separate data files described as follows: 1) a summary data file identifying each site by name, the site location, basic construction information, and American petroleum Institute (API) number (for wells), the number of chemistry samples, period of record, sample description, and the geologic formation associated with the origin of the sampled water, or intended destination (formation into which water was to intended to be injected for samples labeled as injectate) of the sample; and 2) a data file of geochemistry analyses for selected water-quality indicators, major and minor ions, nutrients, and trace elements, parameter code and (or) method, reporting level, reporting level type, and supplemental notes. A data dictionary was created to describe the geochemistry data file and is provided with this data release.

This report is one of a series of publications resulting from a study of the feasibility of increasing domestic heavy oil production being conducted for the U.S. Department of Energy. This report summarizes available public information on the potential of heavy oil production in Alaska. Heavy oil (10' to 20' API gravity) exists and is produced on the North Slope of Alaska; but the technical, environmental constraints and high cost of transportation to refineries on the U.S. West Coast make the economics for producing significant volumes of heavy oil unfavorable. Volumes of proprietary data and feasibility studies exist within major companies, but only limited data is available in the public domain. Alaskan North Slope crude oil is marketed under the legislative constraints of having to be sold in the U.S., thus, it has to compete in the world market with a delivery constraint. California is the recipient and refines most of Alaska's current 1.7 million barrels per day oil production. Transportation, refining, and competition in the market limit development of Alaska's heavy oil resources. A number of enhanced oil recovery technologies for production of Alaska's heavy oil have been reported in the literature including gas, CO2, in situ combustion, and steam. Thermal production of heavy oil has been attempted but requires close spacing. Several light oil reservoirs, with reserves of >50 million barrels each, have been discovered and deemed non-commercial. Constraints on producing heavy oil in Alaska indicate that without significant economic incentives, very little of the heavy oil in Alaska will be produced and even then the cost may be prohibitively expensive leaving most of Alaska's heavy oil unproduced.

"Shown dramatically by the recent crisis involving petroleum and natural gas, shortages and rising prices foreshadow an end to unlimited consumption of natural resources at traditionally low prices. Alleviating these growing shortages of fossil fuels will require increased production from traditional sources and development of new sources. These new sources include tar sand, oil shale, and the in situ combustion of coal. The U.S. tar sand resource and related recovery technology has never been a target of a major research effort by the private sector, perhaps due in part to the fact that most of the known resource is on federal land. Due to this low level of activity by the petroleum industry to develop the domestic tar sand resource, the United States Department of Energy's Laramie Energy Technology Center (LETC) began in 1971 working with the tar sand resource in Utah. The initial work was with the defining, characterizing and analyzing of deposits and the determining of the most promising recovery methods for testing. Specifically the objectives were: 1. To determine the feasibility of in situ oil recovery methods applied to tar sand. 2. To establish a system for classifying tar sand deposits relative to those characteristics that would affect the design and operation of in situ recovery processes. The LETC tar sand activity has created the only multi-disciplined tar sand research staff in the United States. The LETC tar sand program technical staff members and support staff represent approximately 200 man years of tar sand research experience in resource characterization, resource recovery, product treatment, reservoir access, environmental mitigation, and control technology and compliance. The LETC assembled and managed tar sand data base is the only significant compilation of tar sand resource and technology data in the public sector. A program of informal data and information exchange has been developed and is maintained by the LETC technical program management staff between the LETC and all interested private and governmental concerns. The purpose of this report is to document all of the LETC tar sand activity on tar sand deposits in the Uinta Basin in Utah."

The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to about 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels of oil. This project is designed to characterize five shallow shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide-(CO2-) flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. The results of this project will be transferred to industry and other researchers through a petroleum extension service, creation of digital databases for distribution, technical workshops and seminars, field trips, technical presentations at national and regional professional meetings, and publication in newsletters and various technical or trade journals.

Supply and disposition characteristics such as production (fuels include heavy crude, synthetic crude, etc.), input to refineries, exports and others. The data are available at the national and provincial levels. Not all combinations necessarily have data for all years.

Crude Oil Production in Trinidad And Tobago decreased to 50 BBL/D/1K in February from 51 BBL/D/1K in January of 2025. This dataset provides - Trinidad And Tobago Crude Oil Production- actual values, historical data, forecast, chart, statistics, economic calendar and news.

Crude Oil Production in Pakistan increased to 68 BBL/D/1K in February from 62 BBL/D/1K in January of 2025. This dataset provides - Pakistan Crude Oil Production - actual values, historical data, forecast, chart, statistics, economic calendar and news.

The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox Basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to about 100 additional small fields in the Paradox Basin alone, and result in increased recovery of 150 to 200 million bbl of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide- (CO2-) flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox Basin within the Navajo Nation. The results of this project will be transferred to industry and other researchers through a petroleum extension service, creation of digital databases for distribution, technical workshops and seminars, field trips, technical presentations at national and regional professional meetings, and publication in newsletters and various technical or trade journals.

Raw data for the paper "Assessing hydrothermal liquefaction for the production of bio-oil and enhanced metal recovery from microalgae cultivated on acid mine drainage".

The oil and gas producing regions of Alaska have nearly 45 billion barrels of oil which will be left in the ground, or ?stranded?, following the use of today's oil recovery practices. A major portion of this ?stranded oil? is in reservoirs technically and economically amenable to enhanced oil recovery (EOR) using carbon dioxide (CO2) injection. This report evaluates the future oil recovery potential in the large oil fields of the North Slope and Cook Inlet regions of Alaska and the barriers that stand in the way of this potential. The report then discusses how a concerted set of ?basin-oriented strategies? could help Alaska's oil production industry overcome these barriers.

This dataset contains information about world's crude oil proved reserves. Data from BP. Follow datasource.kapsarc.org for timely data to advance energy economics research.Notes:* More than 500 years.^ Less than 0.05.w Less than 0.05%.# Excludes Estonia and Latvia in 2006.Total proved reserves of oil - Generally taken to be those quantities that geological and engineering information indicates with reasonable certainty can be recovered in the future from known reservoirs under existing economic and operating conditions. The data series for total proved oil does not necessarily meet the definitions, guidelines and practices used for determining proved reserves at company level, for instance as published by the US Securities and Exchange Commission, nor does it necessarily represent BP’s view of proved reserves by country.Reserves-to-production (R/P) ratio - If the reserves remaining at the end of any year are divided by the production in that year, the result is the length of time that those remaining reserves would last if production were to continue at that rate.Source of data - The estimates in this table have been compiled using a combination of primary official sources, third-party data from the OPEC Secretariat, World Oil, Oil & Gas Journal and independent estimates of Russian reserves based on official data and Chinese reserves based on information in the public domain.Canadian oil sands 'under active development' are an official estimate. Venezuelan Orinoco Belt reserves are based on the OPEC Secretariat and government announcements.Reserves include gas condensate and natural gas liquids (NGLs) as well as crude oil.Shares of total and R/P ratios are calculated using thousand million barrels figures.

The potential for oil and gas development in the greater Wattenberg area (GWA), which lies near the Front Range between Denver and Greeley, Colo., in the Denver Basin, is moderate to high for oil-and-gas-producing formations of Cretaceous age. The potential for development was determined by modeling existing production of oil and gas from these Cretaceous formations and evaluating where the remaining volume of hydrocarbons exceeds estimates of ultimate recovery from existing wells producing from these units. Although areas of varying potential exist for all producing formations, the likely areas of future oil and gas development would be where the potential exists for recovery of additional hydrocarbons from more than one producing formation. The recompletion of existing wells to tap into other formations, for additional oil and gas production, is likely where there is high potential for remaining producible hydrocarbons and especially where a significant number of wells exist. The model reveals that the Front Range project area between Denver and Greeley, Colo., has a high potential for both the drilling of new wells and the recompletions of existing wells. Because this is also an area of rapid and continuing urban growth, decisions regarding future land use will be improved with the understanding of where future oil and gas development could be expected in the Front Range of Colorado.