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Mahendra K. Verma

Publications and source records attributed to Mahendra K. Verma.

At least 19 recordsLinked to original sources
USGS2019

A probabilistic assessment methodology for carbon dioxide enhanced oil recovery and associated carbon dioxide retention

The U.S. Energy Independence and Security Act of 2007 authorized the U.S. Geological Survey (USGS) to conduct a national assessment of the potential volume of hydrocarbons recoverable by injection of carbon dioxide (CO 2 ) into known oil reservoirs with historical production. The implementation of CO 2 enhanced oil recovery (CO 2 -EOR) techniques could increase the U.S. recoverable hydrocarbon resource base. Use of anthropogenic CO 2 in the CO 2 -EOR process could reduce the amount of CO 2 released to the atmosphere by allowing a percentage of the injected CO 2 to remain in reservoir pore space once occupied by produced oil and water or by CO 2 dissolution in oil and water in the reservoir. The USGS has developed a new methodology for the national assessment of technically recoverable oil resources that may be produced by using current CO 2 -EOR technologies. The methodology relies on a proprietary reservoir-level database, the comprehensive resource database (CRD). The CRD incorporates commercially available geologic and engineering data, and USGS-defined play averages or province averages of reservoir data were used to populate incomplete records. Values from the CRD are used to estimate the original oil in place ( OOIP ) for each reservoir. The inputs are reviewed by USGS geologists, particularly when play or province averages have been used. Monte Carlo simulation is used to produce a numerical probability distribution for the OOIP for each reservoir, with the mean defined as the value of the OOIP in the CRD. A reservoir model (CO 2 Prophet, developed for the U.S. Department of Energy by Texaco, Inc.) is used to determine the incremental recovery factors for oil during the CO 2 -EOR process, on an individual reservoir basis. The model is also used to estimate the volume of CO 2 remaining in the reservoir after the CO 2 -EOR process is complete. Empirical decline curve analysis and comparison with data from published papers and reports on CO 2 -EOR projects are utilized to substantiate the simulation results. Numerical distributions of recovery factors are prepared for variations in the reservoir lithology (clastic or carbonate). The distribution of incremental oil is computed by multiplying the appropriate probability distribution of recovery factors by the individual reservoir distribution of the OOIP . A way to estimate the CO 2 remaining in the reservoir after the completion of the CO 2 -EOR process is also included in the methodology. Assessment results will be aggregated to play, petroleum province, regional, and national scales. This assessment methodology has been tested on the Horseshoe Atoll, Upper Pennsylvanian-Wolfcampian play in the Permian Basin Province in Texas; the play consists of 27 reservoirs having at least 2 billion barrels of OOIP that are amenable to the CO 2 -EOR process. The play was selected as a test case because CO 2 -EOR production data and published reports are available for several reservoirs within the play. Preliminary estimates of oil recoverable by implementation of miscible CO 2 -EOR are comparable to those reported in the literature and obtained by reservoir decline curve analysis.

Scientific Investigations Report↗
USGS2019

Carbon dioxide enhanced oil recovery and residual oil zone studies at the U.S. Geological Survey

The U.S. Geological Survey (USGS) is preparing a national resource assessment of the potential hydrocarbons recoverable after injection of carbon dioxide (CO2) into conventional oil reservoirs in the United States. The implementation of CO2-enhanced oil recovery (CO2-EOR) techniques can increase hydrocarbon production, and lead to incidental retention of CO2 in reservoir pore space allowing long-term storage of anthropogenic CO2. A Comprehensive Resource Database (CRD) containing proprietary data on location, geologic, petrophysical, and reservoir parameters, plus production and well counts for major oil and gas reservoirs in onshore areas and State waters of the conterminous United States and Alaska, was developed to support the USGS assessment. Residual oil zones (ROZs) also can provide potential pore space for long-term storage of anthropogenic CO2. However, ROZs are not included in the upcoming USGS national CO2-EOR assessment because assessment methods for ROZs still are being developed. Additional ROZ CO2-EOR and CO2 retention data and reservoir simulations are needed to calibrate national ROZ assessment estimates.

Conference Paper↗
USGS2018

Material balance approach for determining oil saturation at the start of carbon dioxide enhanced oil recovery

Oil producers have been using enhanced oil recovery methods, including (1) thermal recovery for heavy oil and (2) carbon dioxide enhanced oil recovery (CO 2 -EOR) for medium or light oil, to maximize oil recovery from existing reservoirs. The CO 2 -EOR method is widely used for recovering additional oil after waterflood, which leaves behind a large volume of oil in the reservoir. Completing a CO 2 -EOR feasibility study requires values of various geologic, petrophysical, and reservoir properties, as well as production data. Most of the required data are available except for two critical parameters: (1) the oil saturation at the start of CO 2 -EOR and (2) the oil recovery factor. Several methods, including core analysis, open-hole and cased-hole well logging, well-to-well tracer tests, and material balance, have been deployed to determine the residual oil saturation after waterflood (at which the relative permeability to oil nears zero) or remaining oil saturation after waterflood, equal to the oil saturation at the start of CO 2 -EOR. This report presents the material balance approach, which is less expensive than other approaches and provides reasonably accurate values of oil saturation at the start of CO 2 -EOR, and therefore is more useful when assessing a large number of reservoirs.

Open-File Report↗
USGS2017

General introduction and recovery factors

Introduction The U.S. Geological Survey (USGS) compared methods for estimating an incremental recovery factor ( RF ) for the carbon dioxide enhanced oil recovery (CO 2 -EOR) process involving the injection of CO 2 into oil reservoirs. This chapter first provides some basic information on the RF , including its dependence on various reservoir and operational parameters, and then discusses the three development phases of oil recovery—primary, second­ary, and tertiary (EOR). It ends with a brief discussion of the three approaches for estimating recovery factors, which are detailed in subsequent chapters.

Scientific Investigations Report↗
USGS2017

Summary of the analyses for recovery factors

Introduction In order to determine the hydrocarbon potential of oil reservoirs within the U.S. sedimentary basins for which the carbon dioxide enhanced oil recovery (CO 2- EOR) process has been considered suitable, the CO 2 Prophet model was chosen by the U.S. Geological Survey (USGS) to be the primary source for estimating recovery-factor values for individual reservoirs. The choice was made because of the model’s reliability and the ease with which it can be used to assess a large number of reservoirs. The other two approaches—the empirical decline curve analysis (DCA) method and a review of published literature on CO 2 -EOR projects—were deployed to verify the results of the CO 2 Prophet model. This chapter discusses the results from CO 2 Prophet (chapter B, by Emil D. Attanasi, this report) and compares them with results from decline curve analysis (chapter C, by Hossein Jahediesfanjani) and those reported in the literature for selected reservoirs with adequate data for analyses (chapter D, by Ricardo A. Olea). To estimate the technically recoverable hydrocarbon potential for oil reservoirs where CO 2 -EOR has been applied, two of the three approaches—CO 2 Prophet modeling and DCA—do not include analysis of economic factors, while the third approach—review of published literature—implicitly includes economics. For selected reservoirs, DCA has provided estimates of the technically recoverable hydrocarbon volumes, which, in combination with calculated amounts of original oil in place (OOIP), helped establish incremental CO 2 -EOR recovery factors for individual reservoirs. The review of published technical papers and reports has provided substantial information on recovery factors for 70 CO 2 -EOR projects that are either commercially profitable or classified as pilot tests. When comparing the results, it is important to bear in mind the differences and limitations of these three approaches.

Scientific Investigations Report↗
USGS2017

A database and probabilistic assessment methodology for carbon dioxide enhanced oil recovery and associated carbon dioxide retention in the United States

The U.S. Geological Survey (USGS) has developed an assessment methodology for estimating the potential incremental technically recoverable oil resources resulting from carbon dioxide-enhanced oil recovery (CO 2 -EOR) in reservoirs with appropriate depth, pressure, and oil composition. The methodology also includes a procedure for estimating the CO 2 that remains in the reservoir after the CO 2 -EOR process is complete. The methodology relies on a reservoir-level database that incorporates commercially available geologic and engineering data. The mathematical calculations of this assessment methodology were tested and produced realistic results for the Permian Basin Horseshoe Atoll, Upper Pennsylvanian-Wolfcampian Play (Texas, USA). The USGS plans to use the new methodology to conduct an assessment of technically recoverable hydrocarbons and associated CO 2 sequestration resulting from CO 2 -EOR in the United States.

Energy Procedia↗
USGS2015

Fundamentals of carbon dioxide-enhanced oil recovery (CO 2 -EOR): a supporting document of the assessment methodology for hydrocarbon recovery using CO 2 -EOR associated with carbon sequestration

The objective of this report is to provide basic technical information regarding the CO 2 -EOR process, which is at the core of the assessment methodology, to estimate the technically recoverable oil within the fields of the identified sedimentary basins of the United States. Emphasis is on CO 2 -EOR because this is currently one technology being considered as an ultimate long-term geologic storage solution for CO 2 owing to its economic profitability from incremental oil production offsetting the cost of carbon sequestration.

Open-File Report↗
USGS2014

U.S. Geological Survey carbon sequestration: Geologic research and assessments

In 2007, the U.S. Energy Independence and Security Act authorized the U.S. Geological Survey (USGS) to conduct a national assessment of geologic storage resources for anthropogenic carbon dioxide (CO 2 ) and to evaluate the national technically recoverable hydrocarbon resources resulting from CO 2 injection and storage through CO 2 -enhanced oil recovery (CO 2 -EOR). In addition, the USGS is addressing several other areas of carbon sequestration research that include study of natural CO 2 and helium reservoirs as analogues for anthropogenic CO 2 storage, the economics of CO 2 storage and CO 2 -enhanced oil recovery, and induced seismicity associated with CO 2 geologic storage.

Energy Procedia↗
USGS2012

Assessment of remaining recoverable oil in selected major oil fields of the San Joaquin Basin, California

The U.S. Geological Survey (USGS) recently completed an estimate of volumes of technically recoverable, conventional oil that could eventually be added to reserves in nine selected major oil fields in the San Joaquin Basin in central California. The mean total volume of potential oil reserves that might be added in the nine fields using improved oil-recovery technologies was estimated to be about 6.5 billion barrels of oil.

California↗
USGS2012

Assessment of remaining recoverable oil in selected major oil fields of the Permian Basin, Texas and New Mexico

The U.S. Geological Survey (USGS) recently completed an estimate of technically recoverable, conventional oil in selected oil fields in the Permian Basin in west Texas and southeastern New Mexico. The mean total volume of potential additional oil resources that might be added using improved oil-recovery technologies was estimated to be about 2.7 billion barrels of oil.

New Mexico;Texas↗
USGS2012

Assessment of potential additions to conventional oil and gas resources of the world (outside the United States) from reserve growth, 2012

The U.S. Geological Survey estimated volumes of technically recoverable, conventional petroleum resources resulting from reserve growth for discovered fields outside the United States that have reported in-place oil and gas volumes of 500 million barrels of oil equivalent or greater. The mean volumes were estimated at 665 billion barrels of crude oil, 1,429 trillion cubic feet of natural gas, and 16 billion barrels of natural gas liquids. These volumes constitute a significant portion of the world's oil and gas resources.

Fact Sheet↗
USGS2012

Calculation of hydrocarbon-in-place in gas and gas-condensate reservoirs - Carbon dioxide sequestration

The Energy Independence and Security Act of 2007 (Public Law 110-140) authorized the U.S. Geological Survey (USGS) to conduct a national assessment of geologic storage resources for carbon dioxide (CO 2 ), requiring estimation of hydrocarbon-in-place volumes and formation volume factors for all the oil, gas, and gas-condensate reservoirs within the U.S. sedimentary basins. The procedures to calculate in-place volumes for oil and gas reservoirs have already been presented by Verma and Bird (2005) to help with the USGS assessment of the undiscovered resources in the National Petroleum Reserve, Alaska, but there is no straightforward procedure available for calculating in-place volumes for gas-condensate reservoirs for the carbon sequestration project. The objective of the present study is to propose a simple procedure for calculating the hydrocarbon-in-place volume of a condensate reservoir to help estimate the hydrocarbon pore volume for potential CO 2 sequestration.

Open-File Report↗
USGS2011

Development of an assessment methodology for hydrocarbon recovery potential using carbon dioxide and associated carbon sequestration-Workshop findings

The Energy Independence and Security Act of 2007 (Public Law 110-140) authorized the U.S. Geological Survey (USGS) to conduct a national assessment of geologic storage resources for carbon dioxide (CO 2 ) and requested that the USGS estimate the "potential volumes of oil and gas recoverable by injection and sequestration of industrial carbon dioxide in potential sequestration formations" (121 Stat. 1711). The USGS developed a noneconomic, probability-based methodology to assess the Nation's technically assessable geologic storage resources available for sequestration of CO 2 (Brennan and others, 2010) and is currently using the methodology to assess the Nation's CO2 geologic storage resources. Because the USGS has not developed a methodology to assess the potential volumes of technically recoverable hydrocarbons that could be produced by injection and sequestration of CO 2 , the Geologic Carbon Sequestration project initiated an effort in 2010 to develop a methodology for the assessment of the technically recoverable hydrocarbon potential in the sedimentary basins of the United States using enhanced oil recovery (EOR) techniques with CO 2 (CO 2 -EOR). In collaboration with Stanford University, the USGS hosted a 2-day CO 2 -EOR workshop in May 2011, attended by 28 experts from academia, natural resource agencies and laboratories of the Federal Government, State and international geologic surveys, and representatives from the oil and gas industry. The geologic and the reservoir engineering and operations working groups formed during the workshop discussed various aspects of geology, reservoir engineering, and operations to make recommendations for the methodology.

Fact Sheet↗
USGS2011

New U.S. Geological Survey method for the assessment of reserve growth

Reserve growth is defined as the estimated increases in quantities of crude oil, natural gas, and natural gas liquids that have the potential to be added to remaining reserves in discovered accumulations through extension, revision, improved recovery efficiency, and additions of new pools or reservoirs. A new U.S. Geological Survey method was developed to assess the reserve-growth potential of technically recoverable crude oil and natural gas to be added to reserves under proven technology currently in practice within the trend or play, or which reasonably can be extrapolated from geologically similar trends or plays. This method currently is in use to assess potential additions to reserves in discovered fields of the United States. The new approach involves (1) individual analysis of selected large accumulations that contribute most to reserve growth, and (2) conventional statistical modeling of reserve growth in remaining accumulations. This report will focus on the individual accumulation analysis. In the past, the U.S. Geological Survey estimated reserve growth by statistical methods using historical recoverable-quantity data. Those statistical methods were based on growth rates averaged by the number of years since accumulation discovery. Accumulations in mature petroleum provinces with volumetrically significant reserve growth, however, bias statistical models of the data; therefore, accumulations with significant reserve growth are best analyzed separately from those with less significant reserve growth. Large (greater than 500 million barrels) and older (with respect to year of discovery) oil accumulations increase in size at greater rates late in their development history in contrast to more recently discovered accumulations that achieve most growth early in their development history. Such differences greatly affect the statistical methods commonly used to forecast reserve growth. The individual accumulation-analysis method involves estimating the in-place petroleum quantity and its uncertainty, as well as the estimated (forecasted) recoverability and its respective uncertainty. These variables are assigned probabilistic distributions and are combined statistically to provide probabilistic estimates of ultimate recoverable quantities. Cumulative production and remaining reserves are then subtracted from the estimated ultimate recoverable quantities to provide potential reserve growth. In practice, results of the two methods are aggregated to various scales, the highest of which includes an entire country or the world total. The aggregated results are reported along with the statistically appropriate uncertainties.

Scientific Investigations Report↗
USGS2008

Engineering and Economics of the USGS Circum-Arctic Oil and Gas Resource Appraisal (CARA) Project

This Open-File report contains illustrative materials, in the form of PowerPoint slides, used for an oral presentation given at the Fourth U.S. Geological Survey Workshop on Reserve Growth of petroleum resources held on March 10-11, 2008. The presentation focused on engineering and economic aspects of the Circum-Arctic Oil and Gas Resource Appraisal (CARA) project, with a special emphasis on the costs related to the development of hypothetical oil and gas fields of different sizes and reservoir characteristics in the North Danmarkshavn Basin off the northeast coast of Greenland. The individual PowerPoint slides highlight the topics being addressed in an abbreviated format; they are discussed below, and are amplified with additional text as appropriate. Also included in this report are the summary results of a typical ?run? to generate the necessary capital and operating costs for the development of an offshore oil field off the northeast coast of Greenland; the data are displayed in MS Excel format generated using Questor software (IHS Energy, Inc.). U.S. Geological Survey (USGS) acknowledges that this report includes data supplied by IHS Energy, Inc.; Copyright (2008) all rights reserved. IHS Energy has granted USGS the permission to publish this report.

Open-File Report↗
USGS2008

Reserve Growth of Alberta Oil Pools

This Open-File Report is based on a presentation delivered at the Fourth U.S. Geological Survey Workshop on Reserve Growth on March 10-11, 2008. It summarizes the results of a study of reserve growth of oil pools in Alberta Province, Canada. The study is part of a larger effort involving similar studies of fields in other important petroleum provinces around the world, with the overall objective of gaining a better understanding of reserve growth in fields with different geologic/reservoir parameters and different operating environments. The goals of the study were to: 1. Evaluate historical oil reserve data and assess reserve growth. 2. Develop reserve growth models/functions to help forecast hydrocarbon volumes. 3. Study reserve growth sensitivity to various parameters ? for example, pool size, porosity, oil gravity, and lithology. 4. Compare reserve growth in oil pools/fields of Alberta provinces with those from other large petroleum provinces.

Open-File Report↗
USGS2006

Reserve Growth in Oil Fields of West Siberian Basin, Russia

Although reserve (or field) growth has proven to be an important factor contributing to new reserves in mature petroleum basins, it is still a poorly understood phenomenon. Limited studies show that the magnitude of reserve growth is controlled by several major factors, including (1) the reserve booking and reporting requirements in each country, (2) improvements in reservoir characterization and simulation, (3) application of enhanced oil recovery techniques, and (4) the discovery of new and extensions of known pools in discovered fields. Various combinations of these factors can affect the estimates of proven reserves in particular fields and may dictate repeated estimations of reserves during a field's life. This study explores the reserve growth in the 42 largest oil fields in the West Siberian Basin, which contain about 55 percent of the basin's total oil reserves. The West Siberian Basin occupies a vast swampy plain between the Ural Mountains and the Yenisey River, and extends offshore into the Kara Sea; it is the richest petroleum province in Russia. About 600 oil and gas fields with original reserves of 144 billion barrels of oil (BBO) and more than 1,200 trillion cubic feet of gas (TCFG) have been discovered. The principal oil reserves and most of the oil fields are in the southern half of the basin, whereas the northern half contains mainly gas reserves. Sedimentary strata in the basin consist of Upper Triassic through Tertiary clastic rocks. Most oil is produced from Neocomian (Lower Cretaceous) marine to deltaic sandstone reservoirs, although substantial oil reserves are also in the marine Upper Jurassic and continental to paralic Lower to Middle Jurassic sequences. The majority of oil fields are in structural traps, which are gentle, platform-type anticlines with closures ranging from several tens of meters to as much as 150 meters (490 feet). Fields producing from stratigraphic traps are generally smaller except for the giant Talin field which contains oil in Jurassic river-valley sandstones. Principal source rocks are organic-rich marine shales of the Volgian (uppermost Jurassic) Bazhenov Formation, which is 30-50 m (98- 164 feet) thick. Bazhenov-derived oils are mostly of medium gravity, and contain 0.8-1.3 percent sulfur and 2-5 percent paraffin. Oils in the Lower to Middle Jurassic clastics were sourced from lacustrine and estuarine shales of the Toarcian Togur Bed. These oils are medium to low gravity, with low sulfur (less than 0.25 percent) and high paraffin (commonly to 10 percent) contents. Among the 42 fields analyzed for reserve growth, 30 fields are located in the Middle Ob region, which includes the Samotlor field with reserves of more than 25 BBO and the Fedorov field with reserves of about 5 BBO. Data used in the study include year of discovery, year of first production, annual and cumulative production, and remaining reserves reported by Russian reserve categories (A+B+C1 and C2) in January of each year. Correlation of these Russian resource categories to U.S. categories of the Society of Petroleum Engineers classification is complex and somewhat uncertain. Reserve growth in oil fields of West Siberia was calculated using a newly developed Group Growth method, which requires that the total reserve (proven reserve plus cumulative production) of individual fields with an equal length of reserve record be added together starting with discovery year or the first production year. Then the annual growth factor (AGF), which is the ratio of total reserves of two consecutive years, is calculated for all years. Once AGFs have been calculated, the cumulative growth factor (CGF) is calculated by multiplying the AGFs of all the previous years. The CGF data are used to develop reserve growth models. The West Siberian oil fields show a 13-fold reserve growth 20 years after the discovery year and only about a 2-fold growth after the first production year. This difference is attributed to extensive exploration and field delineation activities between the discovery and the first production years. Because of uncertainty in the length of evaluation time and in reported reserves during this initial period, reserve growth based on the first production year is more reliable for model development. However, reserve growth models based both on discovery year and first production year show rapid growth in the first few years and slower growth in the following years. In contrast, the reserve growth patterns for the conterminous United States and offshore Gulf of Mexico show a steady reserve increase throughout the productive lives of the fields. The different reserve booking requirements and the lack of capital investment for improved reservoir management and production technologies in West Siberian fields relative to U.S. fields are the probable causes for the difference in growth patterns. Reserve growth models based on the first production year predict that the reserve growth potential in the 42 largest oil fields of West Siberia over a five-year period (1998-2003) ranges from 270-330 million barrels or 0.34-0.42 percent per year. For a similar five-year period (1996-2001), models for the conterminous United States predict a growth of 0.54-0.75 percent per year. This abstract presents the contents of a poster prepared for the AAPG Hedberg Research Conference on Understanding World Oil Resources, November 12-17, 2006 - Colorado Springs, Colorado. A paper 'Reserve Growth in Oil Fields of West Siberian Basin, Russia' was published in Natural Resources Research, v. 12, no. 2, June, 2003.

Open-File Report↗