Comparative Study of CO2 Storage Capacity Estimation in Depleted Oil & Gas Reservoir: A Case Study in Vermillion Basin Gulf of Mexico

Introduction

CO2 emissions are primarily caused by the combustion of fossil fuels, both in large combustion units like those used in electric power generation and in smaller, more dispersed sources like automobile engines and furnaces used in residential and commercial buildings. Some industrial and resource extraction processes, as well as open burning during land clearance, emit CO2. Global world CO2 emissions from fossil fuels in 1950 was about 6 billion tonnes of CO2 with Europe and United States accounting for more than 85% of emissions each year, but now emissions have skyrocketed to over 34 billion tonnes per year due to the rise in emissions in the rest of the world particularly in Asia, notably China and India. The US and Europe now account for just under one- third of emissions.

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Due to changing global climates caused by the uncontrolled emissions of greenhouse gases (GHG), the United States Department of Energy, Policymakers both in the U.S and around the world are now encouraging the deployment of Carbon Capture and Storage (CCS) technology to help curb CO2 emissions from fossil fuels.

Global assessments of CO2 storage opportunities involving large volumes of CO2 storage have focused on the options of geological storage such as depleted oil and gas reservoirs, deep saline formations and coal beds etc [2, 3, 4, 5].

Depleted oil and gas reservoirs are one the most sorted candidates for geologic CO2 storage because most Oil and Gas fields and basins have been previously studied and some are currently being studied, hence there are rich databases to support CO2 storage studies. Studies show that the trap mechanisms of most depleted oil and gas reservoirs demonstrate structural integrity and safety as they have been able to keep the hydrocarbons for millions of years without leaks. Also, there are numerous reservoir engineering software that can readily be modified to monitor CO2 if stored in depleted oil and gas reservoirs. Finally, the economics of injecting CO2 into depleted oil and gas reservoirs are relatively cost-effective when compared to other storage  options as there are existing infrastructure such as wells, pipelines, etc. to handle CO2 storage operations [6, 7].

Depleted oil and Gas CO2 storage sites can be located onshore or offshore; however, offshore storage sites have the advantages of lowered dangers of potential contaminating sources of water for drinking, reduced surface and mineral rights issues, and access to existing offshore infrastructure and pipeline transportation routes.

There are site selection criteria for geologic CO2 storage. Firstly, the storage formation has to be a seal mechanism and leak-free to prevent upward migration of CO2 to the surface thereby contaminating surface groundwater. The storage formation must be deep enough (> 800 m) to keep CO2 at a supercritical state as this allows for the storage of more CO2, and not exceeding 2500m for economic purposes. Also, the storage site of interest must be large enough to hold a sizable amount of injected CO2 [8, 9].

There is limited data on the assessment of CO2 storage capacity of depleted oil and gas fields, hence, this work will serve as a template for quick yet detailed and accurate estimates of CO2 storage capacity for potential depleted hydrocarbon sites. An accurate estimation of the storage capacity is required for the government’s energy- related policies and business decisions, the successful implementation of CCS technologies, and the assessment of the impact of CCS to the reduction of CO2 emissions.

In the following sections of this paper, an overview of the Vermilion basin in the Gulf of Mexico where potentially depleted oil and gas fields are located is presented. Methodologies for estimating CO2 storage capacity using volumetric, production, and correlation-based methods are also presented. A Case study for estimating CO2 Storage capacity in a depleted saturated oil reservoir with gas cap using all three methods is presented. Results comparing the estimates are made and finally, conclusion and recommendation are highlighted.

Field Overview Vermillion Basin, Gulf of Mexico

The Gulf of Mexico (GOM) is the third most prolific petroleum basin in the world formed because of the opening of the Atlantic Ocean. It is located at the southeast shores of the United States bordered by Texas, Louisiana, Mississippi, Alabama and Florida.

According to the Estimated Oil and Gas Reserves, Gulf of Mexico Region, December 31, 2019 report, there are a total of 1325 oil and gas fields in the federally regulated part of GOM with original reserves estimates of 26.77 bbl of Oil and 197.0 Tcf of gas. Cumulative Production from the fields accounts for 22.12 bbl of Oil and 190.9 Tcf of gas. There are 91l depleted fields which represent 68.8 percent of all fields and 414 active fields with estimated reserves of 4.65 bbl of Oil and 6.1 Tcf of gas [10].

Blocks in the Vermilion basin lie in the GOM approximately 102 miles from the coast of Louisiana in the continental shelf (Figure 2) below. The deposition of river-fed sediments on enormous volumes of a mobile substrate greatly influences the structural nature of GOM (salt). Growth faults and roll- over anticlines describe the trapping style in the Vermilion Basin.

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The Vermillion basin is predominantly a gas basin with pockets of oil and combination reservoirs (Oil reservoirs with initial gas cap). According to the (OWL, 2022) database, the basin contains 12 actively producing fields and 75 already depleted fields and has so far produced a cumulative oil production of 592MMbbl and a cumulative gas production of 16,751 Bcf. This makes it a prospective candidate for underground carbon sequestration.

Static CO2 Storage Capacity Estimation Approach

In this study, three approaches will be undertaken to estimate the static CO2 storage capacity of the depleted hydrocarbon reservoir. They include the. 1. Volumetric-based approach.

2. Production-based approach. 3. Correlation-based approach.

Volumetric Based Approach for CO2 Storage Capacity Estimation

The USDOE proposed a volumetric approach for CO2 storage capacity estimation. The volumetric estimate is based on the industry standard method for calculating OOIP and OGIP by the formation volume factor [12].

The volumetric-based equation is given below as.

$$ G _ {C O _ {2}} = A h \phi \left(1 - S _ {w i}\right) B \rho_ {C O _ {2}} E _ {R o i l / g a s} \tag {1} $$

2 CO G is the mass of CO2 (tonnes), A is the reservoir area (m_2), h is the net thickness (m), φ is the average effective porosity (fraction), _Swi is the initial water saturation (fraction), Boi is the initial oil or gas formation volume factor (m3/m3), Bgi is the initial gas formation volume factor (m3/m3), Where,

2 CO ρ is the standard CO2 density (Kg/_m_3), ERoil/gas is the CO2 storage efficiency (fraction), representing a fraction of the total pore volume from which oil and/or gas was produced and can be supplied with CO2. The CO2 storage efficiency can be calculated using reservoir simulations or CO2 - Enhanced Oil Recovery experience [12].

Another Volumetric method for estimating CO2 storage capacity in depleted hydrocarbon reservoirs was proposed by CSLF [13]. Petrophysical properties such as reservoir net thickness, porosity, water saturations, etc., depending on the field or basin of study can be obtained from publicly available databases such as Offshore Well and Lease (OWL), Strategic Online Natural Resources Information System (SONRIS), and Bureau of Ocean Energy Management (BOEM) etc.

The geothermal gradient of the reservoir of study can be estimated from the well log data, pressure gradient can be estimated from Bottom Hole pressure (BHP) reports, and they are available in public data sources. If temperature and pressure data at targeted depth for the given reservoir are not available as input for CO2 density estimation using the Peng-Robinson equation of state [14] or Modified Peng- Robinson equation, the temperature and pressure gradient can be utilized. There are also correlations for estimating CO2 density as a function of depth and temperature [15, 16] (Figure 3) below.

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In order to store CO2 in a number of depleted gas, oil, and combination reservoirs in the Gulf of Mexico, [7] carried out CO2 Injection modeling tests. The improved quantification of the CO2 storage amounts was addressed using the numerical simulator Cozsim and its graphical user interface Cozview, which were created [7]. Cozsim is a completely implicit, finite difference-based, extended black oil reservoir flow simulator that was created by NITEC LLC with support from the Department of Energy. It features three phases (oleic, gaseous, and aqueous), four components (oil, water, hydrocarbon gas, and carbon dioxide).

For the majority of the sands, 20,000 MSCF/d was the maximum carbon dioxide injection rate per well. This injection rate has no effect on the reservoir’s eventual CO2 storage volume; rather, it merely affects how long it takes for the reservoir to become full with carbon dioxide. These restrictions were applied to an estimated case until the minimum field injection rate limitation of 100 MSCF/d was met.

Consequently, a plot of CO2 storage efficiency was developed, ERoil/gas against Hydrocarbon recovery factor (HCRF) see Figure 4. E oil/gas is calculated using the USDOE equation (1).

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Mathematically, HCRF is expressed as

( ) ( ) ( ) ( )

. . 5.615 . . 5.615

Cum Oil Prod B Cum FreeGas Prod B HCRF OOIP B OGIP B

$$ \gamma = \frac {\left(C u m. O i l P r o d . \times B _ {0 i} \times 5 . 6 1 5\right) + \left(C u m. F r e e G a s P r o d . \times B _ {0 i}\right)}{\left(O O I P \times B _ {0 i} \times 5 . 6 1 5\right) + \left(O G I P \times B _ {g i}\right)} $$

0 i gi

0 i gi (2) Where OOIP is the Original Oil initially in place (STB), OGIP is the Original Gas initially in place (SCF), Boi and Bgi is the initial oil or gas formation volume factor (RBBL/STB and RCF/SCF), For the oil reservoirs, the HCRF is equal to the ratio of cumulative produced oil and OOIP as OGIP and Bgi are “0”. For the gas reservoirs, OOIP and Boi are “0,”.

Results

Volumetric-Based Approach

Parameters for input into the USDOE equation i.e Equation (1) such as gas cap area and thickness, oil area and thickness, oil and gas formation volume factors, porosity and residual water saturations data are obtained from Table 2.

Pressure and temperature values of about 2019 psia and 120°F were calculated at the average reservoir depth of 4087ft using pressure and temperature gradients of 0.494 psia/ft and 1.101°F/100ft respectively obtained from Table 2.

The Modified Peng-Robinson equation [18] uses the estimated pressure and temperature as input was used to estimate the CO2 density of 680.17 Kg/_m_3. see Figure 6 below, for graphical analysis of temperature, pressure, and CO2 density.

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CO2 Storage efficiency is obtained from Figure 4: the HCRF vs CO2 storage Efficiency factor plot for GOM reservoirs. From Equation 2, Hydrocarbon Recovery Factor (HCRF) was estimated to be 0.27. The low HCRF value is due to the very low recovery from the Oil portion of the reservoir caused by most of the production of the Gas cap and solution gas in the depletion drive mechanism. The CO2 storage Efficiency factor was found to be 0.32.

Using the volumetric-based equation from Equation (1), and corresponding reservoir parameters from Table 2, the deterministic Static CO2 storage capacity was determined to be 1.21 million Tons (Mt). To obtain a Stochastic Static CO2 storage capacity, we considered the range of porosity values from 0.29 to 0.37 and saturation range of 0.15 to 0.3 as seen by wells in the VR273_Q sand. The Area and height of the VR273_Q oil and Gas cap were varied by a ±5% from its base value in order to account for structural uncertainty see Table 3 for details. The estimated P90, P50 and P10 Stochastic Static CO2 storage capacity mass obtained are 1.04, 1.23 and 1.47 million Tons (Mt), respectively. Table 4 summarizes the estimated deterministic and Stochastic Static CO2 Storage capacity.

Discussion of Results

The three approaches for estimating the CO2 storage for depleted saturated oil reservoir with gas cap) shows similar results. The table below shows summaries of the results Table 5.

The CO2 storage capacity estimated by the production– based and correlation-based methods deviates from the estimated Volumetric Methods (P50) by 7.3% and 14.6% respectively. These deviations could be attributed to the petrophysical uncertainties arising from data gaps i.e., absence of well logs for some key wells. The volumetric estimation is subject to some degree of uncertainty due to the stochastic P50 approach. It takes into account a range of potential parameter values, recognizing the inherent variability in geological settings. Although the Correlation- based approach tends to overestimate volumes, estimates are reasonably accurate and use only production data. Reservoir and fluid properties data are not required for its use [21, 22].

Conclusion

Three methods for estimating Static CO2 storage Capacity namely the Volumetric, Production and Correlation methods were applied to the depleted combination reservoir (Oil with Gas cap) of VR273_Q in the Vermillion Basin, GOM. The estimates showed similar results, with little deviations attributed to petrophysical uncertainties arising from data gaps i.e., absence of well logs to key wells [23]. Material Balance concept is established between the estimated CO2 storage capacity by the Volumetric-based approach and Production-based approach as both methods show very similar results. The correlation-based method is very easy to use and relies only on production data, however it tends to overestimate the CO2 storage capacity slightly. Through this study, opportunities for accurately finding and quantifying potential CO2 storage sites within the GOM and worldwide abound. Finally, an accurate estimation of the storage capacity is required for the government’s energy-related policies and business decisions, the successful implementation of CCS technologies, and the assessment of the impact of CCS to the reduction of CO2 emissions etc.

Recommendations

Researchers can utilize this work as a template for quick yet detailed and accurate estimates of CO2 storage capacity using all three methods for potential depleted hydrocarbon sites.

The Correlation-based approach is reasonably accurate and can be used in the absence of reservoir and fluid properties data (only production data are needed). The Correlation-based approach used in this study is fitted for depleted gas, oil, and combination reservoir fields in Gulf of Mexico (GOM), researchers can focus on developing regional correlations for estimating CO2 storage capacity from other underground CO2 storage sources. Properties of depleted reservoirs frequently vary spatially. Refinement of storage capacity estimations can be achieved by accounting for these heterogeneities using advanced geological models. Additionally, Injecting CO2 may result in pressure variations and possible seismic hazards. For safe and efficient storage, geomechanical studies and wellbore integrity evaluations are essential.

Acknowledgement

We want to give our gratitude to Dr Fathi Boukadi for providing the necessary foundation to this work and for supervising this work and ensuring that it became a success and We also want to thank our colleagues for their useful discussions that helped to shape our thought in the work.

Conflict of Interest

The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.