Ccs- Sequestration Off-shore New Jerssy

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Carbon Capture and Sequestration: Ascertaining CO2Storage Potential,Offshore New Jersey, USAAlan Lee Brown, Eric H. Berlin, Robert J. Butsch, Ozgur Senel, Joseph Mills, and Arutchelvi Harichandran;Schlumberger Carbon Services; James Wang, Schlumberger Data Consulting Services

Copyright 2011, Offshore Technology Conference

This paper was prepared for presentation at the Offshore Technology Conference held in Houston, Texas, USA, 25 May 2011.

This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not beenreviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, itsofficers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission toreproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright.

Abstract

The onshore area of the Northeastern United States is lacking in reservoir intervals appropriate for storing large volumes ofcarbon dioxide (CO2). It is proposed that the geologic conditions found offshore of the Eastern Seaboard are conducive to the

safe storage of large volumes of CO2 generated from anthropogenic activities in the region (Schrag, 2009). Little subsurfaceinvestigation has occurred in this area since it was initially explored for hydrocarbons in the mid-1970s. Can newer dataevaluation techniques be applied to older data to ascertain the CO2 storage potential of the Atlantic Outer Continental Shelf?

Schlumberger Carbon Services recently performed an initial site evaluation of storage potential for CO2within theCretaceous intervals near the Baltimore Canyon Trough utilizing vintage wireline, core, and 2D seismic data to develop ageocellular model to simulate CO2 injection and storage. The evaluation site is centered approximately on the COST B-2 well,

located about 70 miles offshore of New Jersey and drilled as a stratigraphic test in 1976. The COST B-2 well and others drilledin the late 1970s and 80s penetrated a Lower Cretaceous interval abundant in channel and mouth-bar sands deposited in a

wave-dominated delta-front to nearshore depositional environment. Petrophysical analysis of available wireline data indicatesthese sands exhibit porosity and permeability ranges adequate for the potential injection of CO2. Additonally, log analysisindicates laterally extensive and vertically thick marine shales overly these potential reservoir intervals and provide anappropriate seal across the region. This petrophysical analysis was integrated with interpretations from available twodimensional seismic lines to investigate the spatial potential of the targeted sediments to store large volumes of injected CO2.

Introduction

In order to properly assess the potential for CO2 storage of any specific geologic formation at any specific geologic site, theprimary attributes for the subsurface interval being investigated must be evaluated for storage potential. We will explainanalysis of the key variables associated with the construction of a subsurface model that can adequately evaluate the potential

Storage Capacity, Injectivity, and Containmentfor CO2 storage. The site being investigated in this study is located withinthe United States (U.S.) Atlantic Outer Continental Shelf (OCS), approximately 70 miles east of the upper New Jerseycoastline in the vicinity of the COST B-2 well (Figure 1). For this initial assessment, vintage wireline, core, and twodimensional (2D) seismic data, acquired during exploration for hydrocarbons in the late 1970s and early 1980s at or near theproposed site, were utilized to develop a geocellular earth model and reservoir simulation model so that injection rates, plumesize, well design, and construction costs could be estimated.

Available Data

For this study, limitations in time and budget precluded acquisition of new subsurface data in the area of investigation.

The preliminary site evaluation was completed utilizing vintage wireline, core, and seismic data available publicly through theMinerals Management Service (MMS) now the Bureau of Ocean Energy Management, Regulation and Enforcement

(BOEMRE). Minimal digital data exists in the region. Log and seismic data are available primarily in both hardcopy andraster formats. Raster files are the graphic images of the original processed seismic data. These files are accompanied by

header files that define the spatial coordinates of the seismic lines. dmigeo, a marine and geophysical project management


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company, compiled all wireline and seismic data available from the MMS into a digital format recognizable to Petrel* seismicto simulation software. EMTUK Inc developed a velocity model for time/depth analysis of the seismic data. SchlumbergerCarbon Services independently evaluated the quality and accuracy of the efforts of dmigeo/Emtuk Inc and confirmed thattheir processes were satisfactory for use in the initial site evaluation.

This phase of the study took about six to eight weeks and was accompanied by some initial 2D reservoir injectionmodeling, which was based on a petrophysical analysis of the COST B-2 well along with associated general regional

information. The subsurface reservoir model was updated as new data came in without introducing delays to the project. This

process is outlined with results to-date below.

Geologic setting

The primary geologic intervals of interest in this study include the Logan Canyon (and potentially the Naskapi andMissisauga) equivalent sands within the Lower Cretaceous intervals of the Baltimore Canyon Trough (BCT) (Figure 2). Thesesands were interpreted to have been deposited primarily as channel and mouth-bar sediments within a wave dominated deltafront to near-shore environment. The Logan Canyon unit at the top of the Lower Cretaceous Interval was deposited across thearea as a geologic-time transgressive sand and is overlain by a thick regional shale section deposited during overall sea levelrise. The Logan Canyon Sandstone is approximately 600 feet (ft) thick, located at a subsea depth of approximately 8100 ft near

the COST B-2 well. Across most of the continental shelf, the Lower Cretaceous units have minmal dip; except in localizedstructures to be discussed later.

Wellbore Data and Analyses

This study focused on the area around the COST B-2 well, drilled as part of a stratigraphic test conducted in the early1970s during initial hydrocarbon exploration on the Eastern Atlantic shelf in federal offshore MMS acreage (Figure 3). Wholecore and sidewall cores were obtained in the COST B-2 well. Analysis of continuous core retrieved from the top of the LoganCanyon section at 8,238 to 8,268 ft found that these sediments were predominantly a medium- to coarse-grained, poorly tomoderately well sorted sandstone with calcite cement (Smith, 1976). The presence of glauconite in the sandstone is a good

indication of a marine depositional setting. However, the presence of thin lignite coal lenses suggested that the interval wasprobably subearially exposed at times. Schlumberger Carbon Services interpreted the section to have been deposited in a

coastal environment that had fluxuating but relatively shallow water depths. Other sandstones sampled deeper in the interval,primarily by sidewall cores, have similar grain size distributions and are also interpreted as shallow marine in origin.

The range of porosities measured in the upper most sandstone of the Lower Creataceous interval in the COST B-2 wholecore ranged from 3.6 to 28 percent with an average of 16.9 percent. Permeability from the same core varied in range from 0.07to 1,220 millidarcies with an average of 76 millidarcies (Smith, 1976) (USGS Open File Report 76-774). Cores taken deeperin the COST B-2 well (at 9,280 ft) showed similar depositional features and similar ranges in porosity and permeability.

Results of sidewall core analysis from the COST B-2 well are also reported in the USGS Report. The results of these coreanalyses indicate that the sandstones evaluated in the study area posses the moderately to very good porosity and permeabilty

ranges required for potential CO2storage and injection.Additional analyses reported from whole and sidewall cores taken from other wells in the study area found similar grain

size and petrophysical parameter distributions noted in the COST B-2 well report. These analyses, combined with openholewireline measurement acquired in the study area, indicate that there are many sandstone reservoirs possessing the requiredporosity and permeability ranges necessary for large scale CO2storage capacity. The most uncertain characteristic of thesection is the actual reservoir sand distribution patterns which ultimately control the lateral continuity of the individual sand

bodies for the storage and their associated shale seals.In addition to the acceptable reservoir CO2 storage characteristics of the Lower Cretaceous interval there are indications of

the section having satisfactory vertical and lateral shale confining units. There are several extensive marine shale units withinand above the Lower Cretaceous Logan Canyon group. These marine shales are considered to be very good seals for trappingany vertical CO2movement after injection. The development of many transgressive-regressive sedimentation cycles associatedwith rapid sea-level changes during the Cretaceous System have been presented in numerous studies, (Vail and others, 1977;Scott, 2007). These depositional patterns develop very extensive intervals of marine shales within and between key zones in

the stratigraphic section. Within the Lower Cretaceous interval there are several 10-100 foot thick marine shales that will actas internal baffles to vertical CO2movement,. These are generally referenced as 4

thand 5thorder cycles deposited over tens of

thousands of years and indicate rapid geologic deposition with limited lateral extent. Above the top of the Logan Canyonsection, there exists a massive section of highly impermeable mudstone and shale. Extending above this extensive shale unitare other sandstone intervals that could act as secondary trapping intervals for injected CO2. These units are covered by anadditional extensive marine shale unit that would add further sealing capability.

A new petrophysical analysis of the COST B-2 log data was performed in this study. This petrophysical analysis wascalibrated to the reported core analysis which was documented in (Smith, 1976). Figure 4 presents these results along with a

generalized, stratigraphic well displaying potential sequestration intervals and associated confining units that would preventCO2migration to shallower intervals. The primary deep sequestration targets are:


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Secondary Confining Unit is a major marine seal at the top of the upper Cretaceous interval deposited during a major sealevel rise. The interval is from 5200 ft to just above 6000 ft subsea in the COST B-2 well.

Secondary Reservoir is within the upper Cretaceous sediments and represents a series of marine sands and delta front tonear shore sediments deposited during a relative sea level fall that had several small order sea level rising events creatinginternal seal/silt seals of varying extent. In general, the sands are of fair to good porosity and are found at just above 6000 ft to6800 ft subsea in the COST B-2 well.

Primary Confining Unit is a major marine flooding interval approximately 1200 ft thick as defined in the COST B-2 well.This is an extensive event that occurred at the top of the Lower Cretaceous sediments on global basis. It ranges in depth fromapproximately 6900 ft to 8200 ft subsea at the COST B-2 well. This represents a major seal to vertical CO2movement.

Primary Reservoir is the Lower Cretaceous interval in the COST B-2 well and begins at approximately 8200 ft subsea atthe top of the regionally designated Logan Canyon sand. This is the top most sand in the section. It represents a transgressivesand package that can be regionally correlated and was deposited as sea level rose rapidly at the end of the Lower Cretaceous.The overall section is more than 2000 ft thick and has multiple sands that could serve as injectable storage intervals for CO2.

Conceptual Geologic Modeling Results

Earlier reports provided sufficient information on the general structure and overall stratigraphic distribution of the keyintervals of interest. Utilizing the gathered data, modern wireline log analysis techniques, and 3D seismic-to-simulationvisualization analysis tools, Schlumberger Carbon Services was able to construct a new and more accurate regional geologic

model. Figure 5 presents a 3D representation of the 2D seismic line distributions across the area. The major regional structuralsurfaces ultimately used in our model were interpreted from this data. Figure 6 presents one of the east-to-west seismic linesnear the COST B-2 well location. In the general area, the seismic character represents a structurally stable section with littleevidence of faulting. Depositional patterns appear relatively continuous across the prospective site.

There are 5 regional surfaces (Figure 7) which were interpreted from the seismic data. Figures 8 and 9 show the positionsof several key cross sections linked to wells associated with the COST B-2 location.

The COST B-2 well was drilled as a stratigraphic test to acquire as much of the potential stratigraphic depositional

layering as possible away from any structural traps in the area that might have accumulated hydrocarbons. These structuralelements were identified utilizing the 2D seismic acquired in the 1970s (Smith, 1976) (USGS 76-774). The position of the

COST B-2 well presented in Figure 10 validates the current structural positioning of the well and the associated stratigraphicsection. The impact of these structures both on influencing depositional patterns and potential hydrocarbon entrapment wereimportant in the analysis performed in the 1970s. For this study, the influence on deposition by these structures is of equalimportance as well as how the structures would influence CO2 movement if eventual injection into those sediments occurred.

Figure 11, presents some aspects of how the pattern of deposition was influenced by these structures. This cross section is

presented in a stratigraphically oriented layout with the structural components modified by flattening the section along asurface assumed to be deposited across the area along a very shallow dip similar to the present offshore shelf profile. The topsurface in the section is positioned at the Logan Sand equivalent and is then flattened across the profile to represent a lowangle depositional surface. This technique modifies the structural component to its possible size and position during thedeposition of the sediments below the Logan Sand level. Correlations across the profile representing depositional sequencesthought to be deposited at relatively equivalent times present some evidence that these structures influenced deposition byshowing some intervals thinning to the west (left side of Figure 11). This initial evaluation and correlation of the sedimentaryintervals away from the COST B-2 well allows the construction of a likely framework of connectivity of the sands consideredfor injection in yellow and the associated seals or baffles of shales controlling both lateral and vertical migration path ways for

any injected CO2.Utilizing this initial base case relationship of the possible correlations laterally between specific sedimentary intervals, the

petrophysical analysis of logs and core data from several wells in the area can be integrated into the developing geologicmodel. These analyses are presented in their wellbore positions in Figure 12. Above the Logan Sand the shales represent a

major transgressive marine shale deposited during a period of major sea level rising and creating a tremendous vertical andlateral seal to CO2 migration.A regional stratigraphic and structural framework can be constructed from the seismic and log data analyses. Figure 13 is

a 3D representation of the base case relationships. From this 3D framework a coherent spatial distribution model fordistributing reservoir parameters associated with the Capacity, Injectability,and Containmentcan be inferred.

Beyond the Base Case Geologic Model

Continuing geologic investigations (started but not fully incorporated into the simulation focus of this study) investigatedpossible predictions of the lateral variations in depositional facies within each correlated wellbore interval. In this phase of theinvestigation the initial base case geologic intervals were utilized and integrated with analog data describing general channelthickness and widths that could be associated with depositional patterns thought to have developed in the Lower Cretaceous.It is assumed that the depositional patterns across the continental shelf during this geologic time were generally from the north-northwest. Variations were anticipated within individual zones, but were expected to be confined to this general transport

quadrant source direction. This directionality combined with the channel facies analogs was incorporated into modeling a base


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case geologic layering framework pattern to distribute petrophysical properties away from the log based control points.Additional information from dipmeter data acquired in several of the wells was also utilized to establish a heterogeneousdepositional pattern. This data allowed the channels to be varied within the zone layering. This additional modeling developeda representative pattern spatially distributing inferred channel sands within the layering established in the base case wellborecorrelation analysis. (Figures 14 through18)

The spatial variation in the number and complexity of the channels are valid only at the individual wells and are generated

laterally purely as a geostatistical distribution. This pattern represents one of many possible outcomes that could be developed

away from the established well control based on modeling of anolog patterns from previous studies.Figures 17 and 18 present the modeled placement of the petrophysical attributes from the wellbore analyses. Figures 19

and 20 show the layering from the model associated with just the upper section of the study interval close to the Logan sand.The brown zone at the very top represents the overlying marine transgressive flooding event that defines the seal above thepossible injection zones. While the zones within the model are layered to better represent the internal variation of the porosity

and permeability distributions of the reservoir, the overlying seal is treated as one non-permeable interval for modelingpurposes.

For the results presented, only the sufaces associated with the primary correlation markers were used to establish theporosity and permeability distribution. Further study will be required to evaluate possible variations that could occur in thepotential reservoir and seal distributions established in the base case geologic model.

SimulationThe geologic model described in the previous section provides the spatial framework for reservoir simulation modeling

CO2 injection into the proposed Lower Cretaceous interval associated with the study site near the COST B-2 well. This sectionwill give a brief overview of the base case used for the initial simulation analysis.

A reservoir model is used to design a suitable injection well configuration, test the overall formation with respect to CO2injectivity, and estimate the likely spatial extent of the injected CO2. This is completed in an iterative manner through closeintegration of the geocellular model, developed within the reservoir analysis tools and their closely linked simulation toolcounterparts in the Petrel seismic-to-simulation process. The development of the plume through the planned injection periodand beyond is highly dependent on the distribution of reservoir properties including porosity and permeability in thegeocellular model developed from the available subsurface information and the accuracy with which the fluid andpetrophysical attributes can be linked spatially. To this end, an initial base case dynamic model was developed to simulate the

fluid flow in the reservoir formation.The reservoir simulation work in this study utilized proven simulation software widely used in the petroleum industry

for modeling fluid flow in porous media. This simulator is a compositional finite difference simulator which predicts fluidflow as a result of injection and/or production activities as a fluid is withdrawn from or injected into a subsurface reservoir. In

this study, the reservoir pore space is occupied by brine. The injection fluid is supercritical CO2.The following are the assumptions associated with the CO2storage analysis for this study:

The salts (NaCl, CaCl2and/or CaCO3) are assumed to stay in the liquid phase.

The gas density is obtained by an accurately tuned cubic equation of state.

The brine density is first approximated by the pure water density (Kell, 1975) and then corrected for salt and CO 2effectsby (Zaytsev, 1993).

The CO2gas viscosity is calculated from (Zaytsev, 1993) and (Fenghour, 1999).

The Lower Cretaceous interval simulated in this study is approximately 2300 ft thick and was penetrated from 8,100 ft to10,400 ft tvd subsea at the Cost B-2 well. The formation pressure gradient, as determined by RFT* repeat formation testertests on the COST B-2 well (Smith, 1976), is 0.435 psi/ft. The temperature gradient as indicated in the COST B-2 report is 1.5deg/100 ft. Based on these gradients, at the model datum depth of 8,500 ft, the pressure and temperature are set to 3,697 psia

and 170

o

F respectively. In the simulated development, injection is assumed to start with four wells at the planned offshoreplatform complex in the first month of Year 0. This is followed by the addition of another four injection wells at a subsea drillcenter (SSDC) in the first month of Year 3. In the first three years, total injection rate is assumed to be 16,500 tons/day (or 6million tons per year). This is to be increased to the full plateau rate of 33,000 tons/day (or 12 million tons per year). Theplateau rate is expected to be maintained for the next 47 years. The simulation proceeds for another 100 years beyond this todetermine the movement of the plume after injection has stopped.

The static base case geologic model that has been previously described covers an area of approximately 40 miles x 45miles. The total dimensions of the model are 342 x 282 x 165 making a total of 16 million cells. Figure 21 shows the three-dimensional geologic model grid with each grid cell measuring 1,000 ft x 1,000 ft horizontally and layer thickness ranging

from 0.25 ft to 9.5 ft. Figure 22 shows this model with the porosity values populated.The static model was upscaled to a coarser grid in order to perform dynamic simulations. The criteria for the coarse grid

are as follows:

Preserve the horizontal resolution of the static grid in an area large enough to cover the possible extent of the CO2plume.


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The total area of the geological grid is largely preserved by placing grid cells outside the fine grid area that areprogressively spaced at larger intervals toward the edge of the model. These grid cells act primarily as a sink for the

pressure pulse over the simulated period.

The major geological zones (Table 1) in the geological model are preserved and subdivided vertically into layers withaverage thickness ranging from 45 ft to 60 ft (except for Zone 17 that has a total average thickness of 31 ft). In otherwords, the number of grid layers in each geological zone depends on its average thickness.

This resulted in a coarse simulation grid shown in Figure 23 with irregular grid spacing. Dimensions of the final grid forsimulation are 63x83x47 with a total of 232,000 active grid cells and the central area covered by grid cells of 1,000 ft x 1,000ft in size (identical to those in the fine static grid). This way a balance is struck between the need for good resolution where theCO2injection takes place and reasonable computational time for quick turnarounds during the iterative design process. Afterfinalizing the coarse grid structure, porosity (PHIE) was upscaled with cell volume weighted arithmetic averaging andpermeability (PermKCal) was upscaled with cell volume weighted geometric averaging and flow based techniquesrespectively. In this way, the pore volume distribution in the fine grid is preserved. On the other hand, the flow based

technique for upscaling permeability involves applying constant pressures to opposite faces of each individual grid cell. Itsother four sides are subject to no-flow boundary conditions. A total flux through the grid cell in the direction of the pressuredrop is then computed, joining the mid-points of the block faces in the direction of flow. The effective permeability is thenestimated by solving the same problem with constant permeabilities chosen to give the same flux. As a simple validation,synthetic porosity and permeability logs made out of the 165-layer fine grid and the 47-layer coarse grid are compared to thecorresponding COST B-2 well petrophysical logs in Figure 24 and Figure 25. These figures show the trends observed in thelog data have been reasonably honored.

Based on petrophysical analysis, the initial fluid in the pore space is estimated to be brine at a salinity of 90,000 ppm (by

weight). The salt content is included in the model as a separate solid component. Currently, the analysis option allows thedesignation of the salt as one or more of three possible salt types (sodium chloride, calcium chloride and calcium carbonate).In this study it is assumed to be purely sodium chloride (NaCl). In the actual model input, see Table 2, the initial fluid isspecified to be 97.3% water and 2.7% NaCl (by molar content).

As part of the initialization process, the model is filled up with the fluid (brine) at pressure and temperature levelspreviously mentioned. By defining the datum temperature and pressure, the simulator simply determines the pressure of cellsat other depths by performing a hydrostatic correction based on the density of the fluid (in this case, water with salt at 90,000

ppm) at subsurface conditions.In addition, a mechanism has been incorporated into the simulation model for avoiding the possibility of fracturing the

reservoir formation. This was implemented by introducing a well injection pressure limit as one of the constraints for thesimulation of the injection process. In the absence of more reliable information, this limit is determined with the use of aconservative maximum fracture pressure gradient of 0.65 psi/ft. Figure 26 shows the relationship of the fracture pressure limitdetermined with this gradient value and the initial formation pressure that is determined by the normal hydrostatic gradient.Based on this, the reservoir pressure is constrained to an overall increase of a maximum of approximately 1,800 psi and 2,200psi at the top and bottom of the targeted reservoir formation, respectively.

At the range of pressure and temperature throughout the flow system, the CO2is either a liquid or a supercritical fluid. TheCO2starts as a supercritical fluid at the pipeline onshore inlet. As it is transported in the pipeline along the 39 F seafloor, it is

cooled down to the liquid phase partway down the pipeline and remains in this phase as it is injected downhole until arrivingin the reservoir formation where it is heated up to become a supercritical fluid again. The overall effects of these phasechanges warrants additional investigation.

During the course of this study the number of injector wells needed for the volumes of CO2delivered were studied and thedifferent results evaluated. The ranges of outcomes from those analyses are not presented here. Only a single final case of upto 8 wells in two different facilities configurations is documented in this paper. These results are shown in Figure 27 as theextents of the plume in a plan view over the period of injection and post-injection modeling and referenced to the general

location of the COST B-2 Well. The simulation results presented cover 50 years of injection and another 100 years afterinjection is completed (Figure 28). It predicts the resulting plume to cover a total area of just under 50 square miles. It shouldbe noted that the spatial distribution of the actual plume (as compared to the current modeled results) will depend on the truedistribution of the reservoir properties, geology, final well configuration, and other important parameters.

Conclusions

The geologic and reservoir simulation modeling performed for this assessment show there is high potential for CO2sequestration in the study area. Geologic and petrophysical evaluation of the Lower Cretaceous interval in the study area nearthe COST B-2 well support previous summations that the area could support large volumes of injected CO2. Older wirelinetool measurements and associated core analyses from wells within a study area can be used to define the range of interval

storage and seal attributes for porosity and permeability both vertically in the associated wells and laterally as correlationsupport between wells. Older 2D seismic sections across a study area can be successfully integrated into a modern digital

geocellular framework to support a more precise evaluation of storage and seal potential. Reservoir modeling indicates that 4


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or more injection wells will likely be required for the CO2volume proposed (6 MMT/Yr). Additional wells may be requiredshould volumes of CO2from other sources be added to the delivery stream..Initial assessments of the range of uncertaintiesassociated with the geologic framework and varying CO2 injection volumes can be performed with limited initial data whenthe analyses are performed in a multi-discipline integrated workflow environment. This work represents only an initial siteevaluation of a potential area for CO2 storage utilizing modern geologic investigative techniques applied to legacy data.Acquisition of modern data is a critical step should such a project be undertaken.

Nomenclature

* Mark of Schlumberger

References

1. Atlantic OCS Area Activities. (n.d.). Retrieved from Minerals Management Service:http://www.gomr.mms.gov/homepg/offshore/atlocs/atlocs.html

2. dmigeo website. (2009, Dec 15). Retrieved from http://www.dmigeo.com/html/home.html3. Fenghour, A. W. (1999). The viscosity of carbon dioxide.J. Phys. Chem. Ref. Data, Volume 27, No. 1.4. IHS. (n.d.). Retrieved from energy.ihs.com: http://energy.ihs.com/5. Kell, G. a. (1975). Reanalysis of the density of liquid water in the range 0-150C and 0-1 kbar.J. Chem Physics Vol 62

No. 9.6. Libby-French, J. (1984). Stratigraphic Framework and Petroleum Potential of Northeastern Baltimore Canyon

Trough.AAPG.7. McIntyre. (1976).AAPG Memoir 60.AAPG.8. MMS Well Data Query. (n.d.). Retrieved from MMS.gov: https://www.gomr.mms.gov/WebStore/master.asp9. Schrag, DP. Storage of Carbon Dioxide in Offshore Sediments. Science, 325, 1658-1659, 200910. Scott, R. W., 2007, Cretaceous Rudists and Carbonate platforms: Environmental Feedback, in Scott., ed., SEPM

Special Pub No. 87, p. 25711. Smith, M. A. (1976). Geological and Operational Summary COST NO. B-2 WELL, Baltimore Canyon Trough Area,

Mid-Atlantic OCS.United States Geological Survey.12. Spycher, N. a. (n.d.). CO2-H2O mixtures in the geological sequestration of CO2. II. Partioning in chloride brines at

12-100C and up to 600 bar. Geochimica et Cosmochimica Acta, Volume 69, No. 13, 3309-3320, 22005.13. United States Geological Survey. (2004). USGS Publications. Retrieved from

http://pubs.usgs.gov/of/2004/1441/images/pdf/fig1.pdf14. Vail, P. R., Mitchum, R. M., Jr., and Thomson, S., III, 1977, Seismic stratigraphy and global changes of sea level,

part 4: Global cycles of relative changes of sea level, in Payton, C. E., ed., Seismic StratigraphyApplications toHydrocarbon Exploration: American Association of Petroleum Geologists Memoir 26, p. 83-97.

15. Zaytsev, I. a. (1993).Properties of aqueous solutions of electrolytes.CRC Press.

Tables

Table 1 Layer average thickness and properties of the fine and coarse grids

Fine Grid Average Properties Coarse Grid

Zone Layers Thickness Porosity Permeability Layers Average layer(ft) (fraction) (md) Thickness (ft)

18 10 97.4 0.085 4.5 2 48.717 4 31.2 0.160 4.2 1 31.216 5 105.8 0.142 32.2 2 52.915 6 99.7 0.127 44.5 2 49.9

13 6 227.6 0.157 27.1 4 56.912 8 137.2 0.151 19.4 3 45.711 6 104.7 0.096 56.1 2 52.410 13 252.0 0.090 21.8 5 50.49 12 249.5 0.125 38.6 5 49.98 6 137.7 0.090 1.8 3 45.97 8 144.6 0.097 51.2 3 48.26 6 107.1 0.046 7.3 2 53.55 12 92.6 0.044 3.0 2 46.34 6 236.0 0.095 14.2 4 59.03 7 88.3 0.103 10.1 2 44.12 15 148.0 0.104 17.0 3 49.31 25 96.8 0.124 32.2 2 48.4

Total 165 2356.4 0.106 13.9 47 2356.4


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Table 2 Model initial fluid (formation water) composition

Proportion by weight Molecular weight Proportion by mole

Water 1.00 18.01 97.3%

Sodium Chloride 0.09 (or 90,000 ppm) 58.44 2.7%

Figures

Figure 1 Regional Site location ~70 miles east of the upper New Jersey coastline in approximately 100+ feet of water on the OuterContinental Shelf of the Eastern United States.

Figure 2 Generalized Stratigraphic Section (Libby-French, 1984; (modified from Jansa and Wiedmann, 1982))


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Figure 3 Site Specific Overview Well Data in Area.


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Figure 4 COST B-2 well wireline log analysis defining major seals and potential storage intervals.


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Figure 5 A 3D presentation of the 2D seismic line distribution and several key regional surfaces. The Green arrow in the lower right

corner points to the North.

Figure 6 West to east 2D seismic line 125a from MMS archive website. The shaded green area delineates the primary zone of interest

in the Lower Cretaceous section. Note the different areas along the wellbore and the relationship of the sands and shales to the

seismic signature.


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Figure 7 A regional perspective with the COST B-2 well positioned below the white star. Five surfaces interpreted from seismic data:

blue = water bottom; green = Middle Eocene seismic marker; red = the Middle Cretaceous Lower Aptian seismic marker; yellow = the

top of the Jurassic Kimmeridgian seismic marker; purple = the seismic marker at or near basement (dmigeo, 2009).

The key zone of interest in this study is the Lower Cretaceous red horizon.


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Figure 8 A vertical view looking down on the primary red regional surface. The blue zone represents a 40 by 30 mile area around the

COST B-2 well used for construction of the geo-cellular model used in the CO2injection simulation modeling.


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Figure 9 A profile view of the 3D image in Figure 10. Note the COST B-2 well drilled between the two small structures to either side.

The vertical purple line illustrates the position of the profiles across the area and shows their intersections relative to the

regionally interpreted seismic surfaces. The color patterns in the vertical wellbores associated with these cross sections

represent major sands (yellow) and shales (red).


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Figure 10 Oriented in a west to east profile, the stratigraphic cross section representing the 5 key wells that were drilled on thestructures adjacent to the COST B-2 well and reinterpreted for this study.


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Figure 11 Correlation of 5 key wells in the west to east cross section. This image presents the recent petrophysical analysis of the

well and core data with the large vertical red intervals representing areas of predicted high permeability and therefore

injectability. The top surface in the section is positioned at the Logan Sand equivalent, The display is flattened across the

interpretation removing the structural component and representing the possible deposition of the sediments filling the

basin below. The larger red blocky log profiles in each well represent areas of predicted high permeability and therefore

injectability. The purple intervals with smaller lateral block layering represent seals of varying lateral extent within the

section below the Logan Sand.


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16 OTC 21995

Figure 12 A 3D presentation of the 2D seismic line distribution and several key regional surfaces. The Green arrow in the lower right

corner points to the North.

Figure 13 Multi-layered geologic model constructed from wells and 2D seismic within the vicinity of the COST B-2 well locationapproximately 30x30 miles square. Note, the section is exaggerated vertically at 1x50 and is viewed from the west (onshoreto offshore).


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OTC 21995 17

Figure 14 - This display shows the base case fluvial channel system model used to populate the geocellular model. This surface is

from the top layer of the interval at the Logan Canyon Sand equivalent.

Figure 15 - This Display is a window slice through the base case model showing approximately 2300 ft of possible injection zones

below the Logan Canyon Sand interval. The slice is from east-to-west looking to the south from the north, note green arrow

in lower right corner shows this projection is different orientation than other figures projected.


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18 OTC 21995

Figure 16 - This display shows several fence cross sections through the model and the ties to wellbores used to interpret the interval

lithologies. The image demonstrates the confidence in the base case model in distributing the facies from the wellbore

control points across the intervening areas to define the possible injection and distribution options. Note the direction of

the display west-to-east looking from south to north.

Figure 17 - This presents a west to east structural cross section of the study area showing the modeled distribution of permeabilityacross the base case model. Note the high permeability zones in yellow and light green, and the low permeability zones in purple.This conforms to the basic fluvial system model constructed for the base case.


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OTC 21995 19

Figure 18 - This display presents a zoomed out west to east structural cross section of the study area and shows the ties between the

wellbore data, the surface channel distribution across the model, and the internal structure as rendered by the geostatistical

distribution of the base case information.


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20 OTC 21995

Figure 19 east-west cross section looking from the north of subject area. The thick brown layer depicts the shale thickness

overlaying the targeted injection zones.

Figure 20 south-north cross section looking from the east of subject area. The thick brown layer depicts the shale thickness

overlaying the targeted injection zones.


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OTC 21995 21

Figure 21 Static base case geocellular framework.

Figure 22 Static base case geocellular framework with porosity distribution utilizing 5 Hudson Canyon wells.


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22 OTC 21995

Figure 23 Coarse simulation grid with porosity distribution.

Figure 24 Comparison between log- and grid-based synthetic porosity distributions at the COST B-2 well.

FineGrid

(165layers)CoarseGrid

(47layers)


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OTC 21995 23

Figure 25 Comparison between log and grid based synthetic log permeability distributions at the COST B-2 well.

Figure 26 Illustration of the method used to determine the maximum pressure to avoid reaching frac pressure (a conservative ture

pressure gradient was used).

FineGrid

(165layers)CoarseGrid

(47layers)


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Figure 27 Predicted CO2plume size progression through time (plan view).

Figure 28 Predicted CO2plume size progression through time steps in simulation run in both plan and profile views.

Year5

Year10

Year35

Year50(endofinjection)

Year150

0 1 2 3 4 5miles

Year3

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Ccs- Sequestration Off-shore New Jerssy

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