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Collaborating Authors
Advanced Resources International
Be a Good Geoscientist First, and the Rest Will Follow
Roth, B. L. (Advanced Resources International) | Hills, D. J. (Advanced Resources International)
Abstract This paper seeks to demonstrate the application of learnings from the oil and gas industry, specifically in the field of geoscience, as they relate to applications within the growing industry of Carbon Capture, Utilization and Storage (CCUS). Additionally, this paper will highlight how current educational programs are already geared to produce a talent pipeline for young professionals beginning their careers in the CCUS field or for later career professionals who are looking to transition into CCUS. To demonstrate the stated objectives, the fundamental theories and knowledge required to operate as a successful geoscientist in the oil and gas industry will be presented. This will include a discussion of basic skills and working knowledge as well as an introduction to various software utilized extensively within the oil and gas industry. This provides context illustrating where the geoscience community has been and the prior focus of many geoscience education pipelines. Then, a comparison of the oil and gas workflows to CCUS workflows will be made to demonstrate that the skills and techniques are aligned. Example workflows from our experience developing CCUS projects will be presented with a focus on the geologic characterization, such as generating subsurface geologic and structural models and developing reservoir models to predict plume migration. It will be made clear that the fundamentals of these workflows and the skills necessary to implement them are essentially the same. Both oil and gas and CCUS workflows utilize the same basic knowledge and geologic understanding (e.g., reservoir porosity, permeability, volumetrics), the same data (e.g., geophysical well logs, seismic reflection surveys, geologic core analysis) and even the same software. This demonstrates the direct application of knowledge and workflows that were previously gatekept by the oil and gas community and highlights their significance in ability to be applied to new opportunities. The discussion presented in this paper clearly identifies the overlap of experience gained throughout the detailed history of oil and gas exploration and its direct application to the burgeoning world of CCUS from the perspective of geologic characterization. The examples provided herein also demonstrate that the pipeline for creating new talent already exists with emphasis on learning the fundamentals of geoscience, and the specific application of those skills can be enacted seamlessly within the CCUS community.
- North America > United States > Texas (0.68)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.69)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.46)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Mississippi > Paluxy Field (0.89)
- North America > United States > Mississippi > East Gulf Coast Tertiary Basin > Tuscaloosa Marine Shale Formation (0.89)
- North America > United States > Louisiana > East Gulf Coast Tertiary Basin > Tuscaloosa Marine Shale Formation (0.89)
Building an EPA Class VI Permit Application
Koperna, G. (Advanced Resources International) | Riestenberg, D. (Advanced Resources International) | Leierzapf, J. (Advanced Resources International) | Roth, B. (Advanced Resources International) | Esposito, R. (Southern Company Research and Environmental Affairs) | Sams Gray, K. (Southern States Energy Board)
Summary To accelerate the commercialization of carbon capture and storage (CCS), the US Department of Energy (US DOE) is building on decades of characterization efforts and pilot-scale projects through their CarbonSAFE program. Administered through their National Energy Technology Laboratory, this program seeks to bring fully integrated projects to the sector that can store more than 50 million tonnes of CO2 over a 30-year period. The program, which was enacted before the enhancement of Internal Revenue Code Section 45Q, is in the capture assessment, characterization, and permitting phase. The objectives of this paper are to discuss (a) the injection permitting requirements of the CarbonSAFE projects; (b) information gathering in support of the permit; (c) the timelines of field development and permit-related activities; (d) the major technical components of the field development plan; and (e) early feedback from the regulators toward acceptance of the permit. In Mississippi, more than 30,000 acres have been characterized by six deep characterization wells, a deep groundwater well, and 92 line miles of 2D seismic as part of the CarbonSAFE Project ECO2S. During the acquisition of seismic data, all receiver lines were live, which resulted in the generation of a pseudo-3D seismic design. The incorporation of a 3D seismic survey was not included as part of this project due to logistical difficulties presented by the undulating, wooded surface terrain. A suite of openhole geophysical logs was taken from each well, allowing for a detailed interpretation of prospective storage reservoirs and confining intervals to complement the analysis carried out on the 290 ft of a whole core that was cut through the prospective confining zone and storage reservoir. The detailed geologic and reservoir data were assembled and entered into a 3D model to assess the injection capacity and the area of review (AoR). This information fed into the detailed corrective action, monitoring, testing, and postinjection site care (PISC) modeling. The results have been exceptional. The geologic assessment has revealed three primary storage targets, ranging in depth from 3,500 ft to 6,000 ft. These storage reservoirs net 1,300 ft of sandstone, with mean porosity and permeability of 29% and 3.6 darcies, respectively. Together, these reservoirs have storage capacities that may exceed 20 million tonnes per square mile, making this a gigatonne prospect. Forward modeling of the project resulted in an AoR of 16 sq miles, injecting about 8000 t/d, for 30 years, via two deep injection wells. The excellent confining characteristics of the caprock, relatively simple geologic structure, and lack of historical well drilling activity in this area provide excellent containment of the injected CO2. Based on this work, the project has proposed 20 years of PISC. To date, only two US CO2 injection permits have been granted. These projects relied on a singular capture point feeding a singular sequestration point (source to sink), and considerations have not been made to garner CO2 emissions from other industrial sources. The Kemper County Storage Complex is a first-of-its-kind storage hub concept that looks to develop an area capable of storing significant quantities of CO2 from the region. Also, this work will show how characterization efforts, geological and numerical modeling efforts, and plan development were constructed in support of permit and incentives acceptance.
- Geology > Geological Subdiscipline > Geomechanics (0.94)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.69)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Sabine Uplift > Paluxy Formation (0.99)
- North America > United States > Mississippi > East Gulf Coast Tertiary Basin > Tuscaloosa Marine Shale Formation (0.99)
- North America > United States > Louisiana > East Gulf Coast Tertiary Basin > Tuscaloosa Marine Shale Formation (0.99)
- (4 more...)
Building the Permit for the First Carbon Storage Hub in the United States
Koperna, George (Advanced Resources International) | Riestenberg, David (Advanced Resources International) | Leierzapf, Jeremy (Advanced Resources International) | Esposito, Richard (Southern Company Research and Environmental Affairs) | Sams Gray, Kimberly (Southern States Energy Board) | Roth, Benjamin (Advanced Resources International)
Abstract To accelerate commercialization of Carbon Capture and Storage (CCS), the U.S. Department of Energy is building on decades of characterization efforts and pilot-scale projects through their CarbonSAFE program. Administered through their National Energy Laboratory, this program seeks to bring fully integrated projects to the sector that can store more than 50 million tonnes of CO2 over a 30 year period. The program, enacted prior to the enhancement of Internal Revenue Code Section 45Q, is in the capture assessment, characterization, and permitting phase. The objectives of this paper are to discuss a) the injection permitting requirements of the CarbonSAFE projects; b) information gathering in support of the permit; c) the timelines of field development and permit-related activities; d) the major technical components of the field development plan; and e) early feedback from the regulators towards acceptance of the permit. In Mississippi, over 30,000 acres have been characterized by six deep characterization wells, a deep groundwater well, and more than 90 line-miles of 2D seismic as part of the CarbonSAFE Project ECO2S. A suite of openhole geophysical logs were taken from each well, allowing for detailed interpretation of prospective storage reservoirs and confining intervals to complement the analysis carried out on the 290 feet of whole core that was cut through the prospective confining zone and storage reservoir. The detailed geologic and reservoir data was assembled and input into a 3D model to assess injection capacity and the Area of Review (AoR). This information fed into the detailed corrective action, monitoring, testing, and Post Injection Site Care (PISC) modeling. The results have been exceptional. The geologic assessment has revealed three primary storage targets, ranging in depth from 3,500 to 6,000 ft. These storage reservoirs net 1,300 feet of sandstone, with mean porosity and permeability of 29% and 3.6 Darcies, respectively. Together, these reservoirs have storage capacities that may exceed 20 million tonnes per square mile, making this a gigatonne prospect. Forward modeling of the project resulted in an AoR of 17 sq miles, injecting about 8,000 tonnes per day, for 30 years, via two deep injection wells. The excellent confining characteristics of the caprock, relatively simple geologic structure, and lack of historical well drilling activity in this area provide excellent containment of the injected CO2. Based on this work, the Project has proposed 20 years of PISC. To date, only two U.S. CO2 injection permits have been granted. These projects relied on a singular capture point feeding a singular sequestration point (source to sink) and considerations have not been made to garner CO2 emissions from other industrial sources. The Kemper County Storage Complex is a first-of-its-kind storage hub concept that looks to develop an area capable of storing significant quantities of CO2 from the region. Also, this work will show how characterization efforts, geological and numerical modeling efforts, and plan development were constructed in support of permit and incentives acceptance.
- Geology > Geological Subdiscipline > Geomechanics (0.69)
- Geology > Geological Subdiscipline > Stratigraphy (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.47)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Sabine Uplift > Paluxy Formation (0.99)
- North America > United States > Mississippi > East Gulf Coast Tertiary Basin > Tuscaloosa Marine Shale Formation (0.99)
- North America > United States > Louisiana > East Gulf Coast Tertiary Basin > Tuscaloosa Marine Shale Formation (0.99)
- North America > United States > Mississippi > Upper Tuscaloosa Field (0.89)
Using Simplified Data Analytics for Defining Optimum Well Completions Early in the Life of a Shale Oil Play
Kuuskraa, Vello A. (Advanced Resources International) | Murray, Brett (Advanced Resources International)
Abstract Objectives/Scope The Mowry Shale oil play, located in the southwestern portion of the Powder River Basin, Wyoming, is in its early stages of development. As of the end of 2019, only 42 horizontal wells have been placed on production in this play, with 18 of these drilled in a higher shale maturity, higher productivity "core area". An important objective of the operators in this emerging shale oil play is to identify, as early and as efficiently as possible, optimum well completion practices. Under a traditional approach, operators often drill and complete hundreds of wells testing alternative completion practices to reach an optimum design. This results in the drilling and completion of many sub-optimum wells and less than optimum deployment of scarce capital investment. To address this issue, the paper examines two questions -- To what extent could Simplified Data Analytics, undertaken early in the life of a shale oil play, substitute for this traditional approach for defining optimum well completion design? And, could Simplified Data Analytics provide a reliable method for projecting the performance of newly drilled and future wells? Methods/Procedures/Process The paper discusses the methodology for successful use of Simplified Data Analytics for assessing optimum well drilling and completion practices in the Mowry Shale, including; (1) taking out, to the extent practical, the effects of geology by partitioning the Mowry Shale play; (2) establishing a reliable measure of well performance; and (3) rigorously correcting the production and well completion data to assure a quality dataset. To illustrate Simplified Data Analytics, the paper uses a dataset of 18 horizontal Mowry Shale wells drilled in a geologically distinct portion of the Powder River Basin. Results The paper starts by tabulating "time slices" of well performance and well drilling and completion (D&C) practices. These "time slices" show that Mowry Shale well performance has improved notably in the past several years, in line with advancing and more intensive well D&C practices. Simplified Data Analytics is then used to develop an algorithm that incorporates three key well D&C practices--lateral length, number of frac stages, and proppant concentration--to : (1) define optimum practices for the Mowry Shale in one of the "core areas" of the Powder River Basin, and (2) project how newly drilled wells in this "core area" should perform given their D&C practices. The accuracy and value of the Simplified Data Analytics methodology will be tested against the performance of newly drilled Mowry Shale wells. Novel/Additive Information The application of Simplified Data Analytics to the Mowry Shale may also provide insights of value to producers in other shale oil plays. Appropriately applied, it provides a transparent and "easy-to-use" methodology for early identification of optimum well completion practices in alternative geologic settings.
- North America > United States > Montana > Powder River Basin (0.99)
- Oceania > Australia > Victoria > Bass Strait > Gippsland Basin (0.98)
- North America > United States > Wyoming > Powder River Basin > NPR-3 > Mowry Formation (0.94)
- (5 more...)
An adaptable technique for comparative image assessment: Application to crosswell electromagnetic survey design for fluid monitoring
Commer, Michael (Lawrence Berkeley National Laboratory) | Alumbaugh, David L. (Lawrence Berkeley National Laboratory) | Wilt, Michael (Lawrence Berkeley National Laboratory) | Cihan, Abdullah (Lawrence Berkeley National Laboratory) | Um, Evan S. (Lawrence Berkeley National Laboratory) | Petrusak, Robin (Advanced Resources International) | Birkholzer, Jens T. (Lawrence Berkeley National Laboratory)
ABSTRACT Reservoir integrity stewardship accompanying carbon capture and sequestration considers fluid extraction and reinjection as a risk-mitigating method against overpressuring that could lead to caprock damage and ensuing leakage. Crosswell electromagnetics offers a technically viable monitoring method with the spatial volume coverage necessary for reservoir-encompassing pressure management. However, a certain logistic dilemma for deep gas sequestration into saline and thus electrically conductive aquifers is that crosswell magnetic-field measurements underperform in the imaging of more resistive plume bodies, further exacerbated when vertical arrays intersect, as opposed to surround, plumes. Comparative synthetic-data plume imaging of such scenarios rates the information content of magnetic-field versus electric-field 3D crosswell layouts for reservoir and infrastructure conditions of a representative pilot site in a coastal area in Florida. The image quality of the resulting plume replications can be ranked numerically through a newly proposed semblance qualifier, appraising the model goodness of fit to a given reference. In contrast to common least-squares measures for goodness of fit, the semblance formulation uses classifying logistic function types, thus enabling a better distinction of predefined anomaly features.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Geology > Petroleum Play Type (0.34)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/4 > Snorre Field > Statfjord Group (0.99)
- (10 more...)
Perspectives on Emerging Domestic Unconventional Plays
Kuuskraa, Vello (Advanced Resources International) | Malone, Taylor (Advanced Resources International) | Murray, Brett (Advanced Resources International)
Background The pioneering shale gas plays -- the Barnett and Fayetteville -- have become increasingly mature and today are several years past their prime. From a peak of 5.7 Bcfd in 2012, the Barnett has declined to 3.5 Bcfd of natural gas production (wet) in early 2017. Similarly, natural gas production from the Fayetteville Shale, that maintained its peak production of 2.8 Bcfd from 2012 through 2014, has declined to 1.7 Bcfd in early 2017, Exhibit 1. The pioneering shale/tight oil plays - - the Bakken and Eagle Ford that sparked the "tight oil" revolution - - each now contain over 10,000 horizontal wells that have significantly depleted their core ("sweet spot") areas. The combination of "core" area resource depletion, lower oil prices, and the subsequent sharp drop in rigs has caused oil production from these two shale oil plays to also enter decline, Exhibit 2. At some point, even the massive Marcellus/Utica shale gas plays and the equally massive Permian shale/tight oil resources will become mature with their "core" areas fully developed. As such, the question becomes - - what set of shale and tight formation plays and resources will emerge to replace these increasingly mature, pioneering plays, enabling domestic shale gas and shale/tight oil production to continue to grow? Perspective on Emerging Unconventional Resources Our perspective is that new domestic unconventional shale and tight sand resources will continue to emerge, but often following pathways other than the classical "new discoveries and rediscoveries." While "newly discovered and rediscovered" shale and tight oil and gas plays will emerge from the innovative minds of unconventional oil and gas explorers, much of the new shale and tight resource will stem from alternative pathways. Alternative Pathway #1. Looking In Your Own Back Yard. The first alternative pathway for adding unconventional resources is the search for additional productive horizons in existing basins, such as the Meramec Formation above the Cana-Woodford Shale in the Anadarko Basin and the Moorfield Shale below the Fayetteville Shale in the Arkoma Basin. Currently, the most extreme opportunities for "looking in your own backyard" involves "dealing with a stacked deck" - - the host of shale and tight sand plays in the Permian Basin.
- North America > United States > Oklahoma (1.00)
- North America > United States > Arkansas > Washington County > Fayetteville (0.66)
- North America > United States > Texas > Reeves County (0.16)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (42 more...)
The Grand Challenge of Carbon Capture and Sequestration
Koperna, George J. (Advanced Resources International) | Gupta, Neeraj (Battelle Institute) | Godec, Michael (Advanced Resources International) | Tucker, Owain (Shell) | Riestenberg, David (Advanced Resources International) | Cumming, Lydia (Battelle)
Carbon capture and sequestration (CCS) is designed to reduce atmospheric emissions of greenhouse gases (GHGs). The CCS process captures carbon dioxide (CO2) generated at large-scale industrial sources (power plants, refineries, gasification facilities, etc.) and transports it to an injection site to be permanently stored in the subsurface. With extensive research linking GHG concentrations in the atmosphere to observed changes in global temperature patterns, CCS technology could play an important role in policy efforts to limit the global average temperature rise. Even with the wealth of experience already in place within the oil and gas industry, the obstacles to advancing CCS to the forefront of GHG mitigation technologies remain significant. Large-scale CO2 injection projects remain primarily in the realm of commercial CO2-EOR (enhanced oil recovery) projects. The key challenges to enabling CCS include cost-effective capture and transport of industrial CO2, clear access to pore space for CO2 storage in geologic formations, proven methodologies for demonstrating storage integrity, and dissemination of best practices. SPE members can play a significant role in addressing these challenges. Cost-Effective Capture of Power Sector and Industrial CO2 A major technical challenge facing capture at electric generating facilities is that the CO2 concentration in large-volume flue streams is quite low. Current removal technologies include techniques that apply amines, chilled ammonia, membranes, and ionic liquids to strip the CO2 from the flue stream. However, these technologies were developed to handle smaller-scale operations and higher-CO2-purity streams. When applied to large electric generating plants, process efficiency is reduced, and the energy penalty associated with the capture process drives up costs, increasing the levelized cost of electricity by 50% or more, depending on local factors. Also, to accommodate the substantial volumes of the CO2 and flue gas at full-scale industrial sources, the removal technologies require significant scale up and footprint for deployment. While early movers are developing large-scale capture demonstrations such as SaskPower’s Boundary Dam Project, Southern Company’s Kemper Energy Facility (Fig. 1), and NRG’s Petro Nova Facility, we are still very early on the “learning curve.” Support for more development of next-generation capture technologies and large demonstrations is required to push us down the cost curve. This involves reducing the cost of materials and construction, parasitic costs related to energy for operations, compression, and operation and maintenance costs.
Taking CO2 Enhanced Oil Recovery to the Offshore Gulf of Mexico: A Screening-Level Assessment of the Technically and Economically Recoverable Resource
DiPietro, Phil (US Department of Energy National Energy Technology Laboratory) | Kuuskraa, Vello (Advanced Resources International) | Malone, Taylor (Advanced Resources International)
Summary This paper evaluates the recoverable crude-oil resource associated with applying carbon dioxide (CO2) enhanced oil recovery (EOR) to reservoirs in the offshore Gulf of Mexico (GOM). By use of data maintained by the Bureau of Ocean Energy Management (BOEM), a database containing 531 oil fields with total oil originally in place (OOIP) of 69 billion bbl was used for the study. A total of 391 fields, representing 35% of the OOIP, were screened out at as not amenable to CO2 EOR because of size, residual oil saturation (ROS), and/or well spacing. For the remaining 140 oil fields (containing 696 reservoirs), the data elements required to model a CO2-EOR flood, such as sweep efficiency and heterogeneity, were derived by use of a variety of methods. Crude-oil production and CO2-demand profiles were produced from streamtube finite-difference simulations for each oil-bearing reservoir. The study assumes that groups of proximate fields will be served by an anchor CO2-supply pipeline (1 billion scf/yr of CO2) at a levelized transportation cost of USD 1.06/Mscf of CO2 (equivalently USD 20/t of CO2). The economic determinations are derived from a crude-oil price of USD 90/bbl, CO2 price of USD 1.59/Mscf (USD 30/t of CO2) at the capture facility plant gate, 18.75% royalty, and a 20% rate of return before taxes. BOEM projects that 182 billion bbl of OOIP remains undiscovered, 2.5 times the discovered resource. The BOEM database of discovered fields cuts off after 2008, and a portion of the undiscovered resource, 40 billion bbl of OOIP, has since been announced as discovered. Data from the analysis of discovered oil fields were used to estimate the expected CO2 EOR from the undiscovered oil fields. Under the current CO2-EOR technology scenario, the economically recoverable resources (ERR) are 0.8 billion bbl, a small fraction of the technically recoverable resource (TRR) of 23.5 billion bbl. The average efficiency of CO2 use in the ERR oil fields is estimated to be 7.2 Mscf/bbl and the associated demand for CO2 supply is 5.8 Tcf. Under a scenario with next-generation CO2-EOR performance, the ERR increases significantly to 14.9 billion bbl and 74 Tcf of CO2 demand, consistent with an improved use efficiency of 5.0 Mscf of CO2/bbl. Thirty-five percent of the total ERR estimate is from discovered fields, whereas the remaining 65% is from undiscovered fields.
- North America > United States > Louisiana (1.00)
- North America > United States > Texas (0.94)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Santos Basin > Block BM-S-11 > Tupi Field > Lula Formation (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Santos Basin > Block BM-S-11 > Tupi Field > Guaratiba Formation (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Santos Basin > Block BM-S-11 > Tupi Field > Cernambi Formation (0.99)
- (9 more...)
Taking CO2 Enhanced Oil Recovery to the Offshore Gulf of Mexico
DiPietro, Phil (U.S. DOE National Energy Technology Laboratory) | Kuuskraa, Vello (Advanced Resources International) | Malone, Taylor (Advanced Resources International)
Abstract This paper evaluates the recoverable crude oil resource associated with applying carbon dioxide enhanced oil recovery (CO2 EOR) to reservoirs in the offshore Gulf of Mexico (GOM). Using data maintained by the Bureau of Ocean Energy Management (BOEM), a database containing 531 oil fields with a total original oil in-place (OOIP) of 69 billion barrels was used for the study. A total of 391 fields, representing 35% of the OOIP, were screened out at as not amenable to CO2 EOR based on size, residual oil saturation, and/or well-spacing. For the remaining 140 oil fields (containing 696 reservoirs), the data elements required to model a CO2 EOR flood, such as sweep efficiency and heterogeneity, were derived using a variety of methods. Crude oil production and CO2 demand profiles were produced from stream-tube finite-difference simulations for each oil-bearing reservoir. The study assumes that groups of proximate fields will be served by an anchor CO2 supply pipeline (one billion scf per year CO2) at a levelized transportation cost of $1.06/MscfCO2 (equivalently 20$/mtCO2). The economic determinations are based on a crude oil price of $90/bbl, CO2 price of $1.59/Mscf (30 $/MtCO2) at the capture facility plant gate, 18.75% royalty, and a 20% rate of return before taxes. BOEM projects that 182 billion barrels of OOIP remain undiscovered, two and a half times the discovered resource. Data from the analysis of discovered oil fields was used to estimate the expected CO2 EOR oil recovery from the undiscovered oil fields. Under the current CO2 EOR Technology scenario, the economically recoverable resources (ERR) is 0.8 billion barrels, a small fraction of the technically recoverable resource (TRR) of 23.5 billion barrels. The average efficiency of CO2 use in the ERR oil fields is estimated to be 7.2 Mscf/bbl and the associated demand for CO2 supply is 5.8 TCF. Under a scenario with Next Generation CO2 EOR performance, the ERR increases significantly to 14.9 billion barrels and 74 TCF of CO2 demand, consistent with an improved use efficiency of 5.0 MscfCO2/bbl.
- North America > United States > Louisiana (1.00)
- North America > United States > Texas (0.69)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Santos Basin > Block BM-S-11 > Tupi Field > Lula Formation (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Santos Basin > Block BM-S-11 > Tupi Field > Guaratiba Formation (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Santos Basin > Block BM-S-11 > Tupi Field > Cernambi Formation (0.99)
- (5 more...)
NETL CO2 Injection and Storage Cost Model
Grant, Timothy C (DOE/NETL) | Morgan, David (DOE/NETL) | Godec, Michael Lewis (Advanced Resources International Inc.) | Lawrence, Richard (Advanced Resources International) | Valenstein, Jason (Booz Allen Hamilton, Inc.) | Murray, Robert (Booz Allen Hamilton, Inc./NETL)
Abstract The U.S. Department of Energy's National Energy Technology Laboratory (NETL) has developed a model to estimate the costs of sequestering captured CO2. This model includes costs from initial regional geologic evaluation through site characterization, permitting, injection/MVA operations, postinjection site care to final site closure and transfer to long-term stewardship. Differences in storage costs across different geologic formations are driven by two basic factors: injectivity which determines the number of injection wells drilled to accommodate a given rate of CO2 injection and the volume of CO2 to be sequestered which determines, per in-situ reservoir parameters, the areal extent of the plume and hence the Area of Review of a Class VI well permit. The AoR defines the areal extent of MVA activities which dominates costs during injection and post-injection operations. The basic framework for this model provides costs for compliance with various sections of EPA's Class VI regulation and Subpart RR of the GHG Reporting Program. Cost analysis at two levels is provided by this model: site specific where the modeler can enter their own reservoir and cost data and regional in the form of cost supply curves. A geologic and cost database was developed to support this model. Published analyses of storage cost to date have been very general, providing estimates for site characterization or overall costs but few details. While storage costs are a small percentage of overall CCS costs, they represent a significant investment. Getting to the point of injection operations will take tens of millions of dollars. Model results indicate that operation/post-closure MVA costs will represent some 70 percent of overall storage costs. Also, the financial mechanisms used to establishing Financial Responsibility prior to permitting may represent a significant cost. A detailed understanding of overall storage costs is critical for investors and policy planners. This model can be combined with a simple pipeline costing model that is part of NETL's current Transport, Storage, and Monitoring Cost Model as well as with NETL's Capture-Transport-Storage pipeline model capable of modeling CO2 pipeline networks. This model can be combined with NETL's Power Supply Financial Model for cost analysis across the CCS value chain. Introduction The National Energy Technology Laboratory (NETL) has developed a CO2 Transportation & Storage cost model. This model represents further development of NETL's existing model, Estimating Carbon Dioxide Transportation and Storage Costs.i Recently, NETL developed a Capture-Transport-Storage (CTS) model to model pipeline development for transportation of captured CO2 from source to sink. NETL also has a Power Supply Financial Model (PSFM)ii to model the cost of capture for an IGCC or Super-critical PC plant.
- North America > United States > Texas (0.28)
- North America > United States > Colorado (0.28)
- North America > Canada > Alberta (0.28)
- (2 more...)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (0.68)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming > Wind River Basin > Madison Formation (0.99)
- North America > United States > South Dakota > Williston Basin (0.99)
- North America > United States > North Dakota > Williston Basin (0.99)
- (17 more...)