Geochemical Changes in Response to CO2 Injection in a CO2-EOR Complex in Northern Michigan

Given the growing interest in the capture and utilization of CO2 in recent years, several technologies have emerged that seek to generate CO2 in-situ at a low cost. There are promising developments, which allow capturing CO2 with sufficient purity to be used for EOR. Oxycombustion has high potential in the region as this technology benefits from gas production with a high CO2 content, which significantly reduces the cost of capture. Additionally, carbon dioxide separation techniques such as air capture, fuel cells, amines, and membranes are considered. Argentina has several fields, which produce gas with high CO2 content benefiting Oxycombustion economics. The paradigm change not only occurs in technology but also in the implementation schemes. The vast majority of the development of CO2 EOR are carried out in the USA with very low CO2 costs and high availability. When considering the costs of CO2 per ton (metric ton) that could be obtained in Argentina, and financial variables such as high discount rates, it is clear that the injection model has to be optimized for these conditions. In order to optimize profitability, it is crucial to improve the payout time and the usage of CO2. In one hand, smaller slugs lead to better CO2 utilization rates (oil produced/CO2 injected) while larger slugs lead to faster oil production response. We observed that due to the high discount rates in the area, faster production response has a higher economic impact that sweep efficiency or breakthrough times. It seems to be better to sacrifice overall recovery factor in order to extract oil as soon as possible. Optimal injection schemes where found for different scenarios. Additionally, starting the project early is a key parameter for both technical and economic success. Another key technical difference is that the available CO2 volume for injection is constant due to the nature of these capture techniques. Unlike purchasing CO2 from a pipeline, where gas can be purchased as needed, Oxycombustion (or other capture methods) produces a continuous stream limiting injection flexibility. All produced CO2 must be injected as it is being produced and, until production gas reaches a CO2 content high enough to assure MMP, CO2 injection stream cannot exceed the maximum CO2 capture capacity. CO2 EOR has significant advantages over Chemical EOR due to its significant recovery factors and early response. Additionally, this technology applies to reservoirs of low permeability and / or high temperature where the polymer can have problems of injectivity or degradation.

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Application of CO2 injection monitoring techniques for CO2 EOR and associated geologic storage

SSRN Electronic Journal ◽

10.2139/ssrn.3812730 ◽

2021 ◽

Author(s):

Lu Jin

Keyword(s):

Co2 Injection ◽

Monitoring Techniques ◽

Geologic Storage ◽

Co2 Eor

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Achieving ~1 Million Metric Ton CO2 Stored; Measurement and Accounting for Net CO2 Injection in a CO2-EOR Complex

SSRN Electronic Journal ◽

10.2139/ssrn.3366040 ◽

2019 ◽

Author(s):

Sanjay Mawalkar ◽

Andrew Burchwell ◽

Neeraj Gupta ◽

Matt Place ◽

Mark Kelley ◽

...

Keyword(s):

Co2 Injection ◽

Co2 Eor

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Optimization Wells Placement Policy for Enhanced CO2 Storage Capacity in Mature Oil Reservoirs

Energies ◽

10.3390/en13164054 ◽

2020 ◽

Vol 13 (16) ◽

pp. 4054

Author(s):

Michał Kuk ◽

Edyta Kuk ◽

Damian Janiga ◽

Paweł Wojnarowski ◽

Jerzy Stopa

Keyword(s):

Carbon Dioxide ◽

Carbon Dioxide Emissions ◽

Storage Capacity ◽

Co2 Storage ◽

Oil Field ◽

Ecological Effect ◽

Co2 Injection ◽

Reservoir Properties ◽

Injection Wells ◽

Co2 Eor

One of the possibilities to reduce carbon dioxide emissions is the use of the CCS method, which consists of CO2 separation, transport and injection of carbon dioxide into geological structures such as depleted oil fields for its long-term storage. The combination of the advanced oil production method involving the injection of carbon dioxide into the reservoir (CO2-EOR) with its geological sequestration (CCS) is the CCS-EOR process. To achieve the best ecological effect, it is important to maximize the storage capacity for CO2 injected in the CCS phase. To achieve this state, it is necessary to maximize recovery factor of the reservoir during the CO2-EOR phase. For this purpose, it is important to choose the best location of CO2 injection wells. In this work, a new algorithm to optimize the location of carbon dioxide injection wells is developed. It is based on two key reservoir properties, i.e., porosity and permeability. The developed optimization procedure was tested on an exemplary oil field simulation model. The obtained results were compared with the option of arbitrary selection of injection well locations, which confirmed both the legitimacy of using well location optimization and the effectiveness of the developed optimization method.

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Simulation Study of CO2 Huff-n-Puff in Tight Oil Reservoirs Considering Molecular Diffusion and Adsorption

Energies ◽

10.3390/en12112136 ◽

2019 ◽

Vol 12 (11) ◽

pp. 2136 ◽

Cited By ~ 2

Author(s):

Yuan Zhang ◽

Jinghong Hu ◽

Qi Zhang

Keyword(s):

Molecular Diffusion ◽

Co2 Storage ◽

Oil Production ◽

Oil Reservoirs ◽

Co2 Injection ◽

Tight Oil ◽

Strong Basis ◽

Well Production ◽

Co2 Eor ◽

Tight Oil Reservoirs

CO2 injection has great potentials to improve the oil production for the fractured tight oil reservoirs. However, Current works mainly focus on its operation processes; full examination of CO2 molecular diffusion and adsorption was still limited in the petroleum industry. To fill this gap, we proposed an efficient method to accurately and comprehensively evaluate the efficiency of CO2-EOR process. We first calculated the confined fluid properties with the nanopore effects. Subsequently, a reservoir simulation model was built based on the experiment test of the Eagle Ford core sample. History matching was performed for the model validation. After that, we examined the effects of adsorption and molecular diffusion on the multi-well production with CO2 injection. Results illustrate that in the CO2-EOR process, the molecular diffusion has a positive impact on the oil production, while adsorption negatively impacts the well production, indicating that the mechanisms should be reasonably incorporated in the simulation analysis. Additionally, simulation results show that the mechanisms of molecular diffusion and adsorption make great contributions to the capacity of CO2 storage in tight formations. This study provides a strong basis to reasonably forecast the long-term production during CO2 Huff-n-Puff process.

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Assessing geochemical reactions during CO2 injection into an oil-bearing reef in the Northern Michigan basin

Applied Geochemistry ◽

10.1016/j.apgeochem.2018.12.008 ◽

2019 ◽

Vol 100 ◽

pp. 380-392 ◽

Cited By ~ 1

Author(s):

Susan A. Welch ◽

Julie M. Sheets ◽

Matthew C. Place ◽

Matthew R. Saltzman ◽

Cole T. Edwards ◽

...

Keyword(s):

Co2 Injection ◽

Michigan Basin ◽

Geochemical Reactions ◽

Northern Michigan

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Application of Full Waveform Inversion to Time-Lapse Walkaway Vertical Seismic Profile Data for CO2-EOR Monitoring in Abu Dhabi: A Feasibility Study on Field and Synthetic Data

10.2118/208007-ms ◽

2021 ◽

Author(s):

Takuji Mouri ◽

Aijiro Shigematsu ◽

Yuki Nakamura ◽

Ayato Kato ◽

Masaru Ichikawa ◽

...

Keyword(s):

Data Analysis ◽

Field Data ◽

Time Lapse ◽

Abu Dhabi ◽

Co2 Injection ◽

Vsp Data ◽

Co2 Eor ◽

Velocity Changes ◽

Borehole Seismic ◽

Field Data Analysis

Abstract This study aims to investigate the feasibility of CO2-EOR monitoring by full waveform inversion (FWI) of time-lapse VSP data in an onshore CO2-EOR site in Abu Dhabi. CO2-EOR monitoring using conventional time-lapse surface seismic in onshore oil fields in Abu Dhabi is often technically challenging for two main reasons. The first is that elastic property change in response to pore fluid substitution is relatively small because the elastic modulus of the reservoir rock frame is far larger than that of the pore fluids. The second is the low repeatability of time-lapse survey data due to high amplitude surface-related noise which varies temporally. However, seismic monitoring with FWI of time-lapse borehole seismic data may offer a solution for these issues. FWI is capable of detecting small velocity changes such as those associated with pore fluid substitution. Furthermore, borehole seismic surveys may provide more highly repeatable, higher quality data compared to surface seismic surveys because borehole seismic data is less affected by surface-related noise. This study consists of two parts, a field data analysis and a synthetic study. In the field data analysis, we studied the resolution and repeatability of FWI results at field-data quality, including the presence of actual noise using time-lapse VSP data. VSP data was acquired at the very early stage of EOR and there was no CO2 injection in the time between the two time-lapse VSP surveys. As a result, a high-resolution P-wave velocity model, consistent with a sonic log, was obtained. The P-wave velocity model also revealed excellent repeatability between the two survey data sets. In the synthetic study, time-lapse FWI was performed using synthetic VSP data representing pre- and post- CO2 injection periods. The results of the synthetic study showed that even in the presence of realistic 4D noise, which was estimated in the field data analysis, FWI successfully delineated the distribution of velocity changes caused by CO2 injection when the cross-sectional area of the injection-induced velocity changes were larger than the resolution of the FWI results. With these results, we demonstrated that FWI using time-lapse VSP data was applicable for CO2-EOR monitoring in the field as long as the criteria were met. This conclusion encourages the application of FWI using time-lapse VSP data for CO2-EOR monitoring in onshore Abu Dhabi.

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Analysis of Vertical Permeability and Its Influence on CO2 EOR and Storage in a Carbonate Reservoir

10.2118/205995-ms ◽

2021 ◽

Author(s):

Bo Ren ◽

Jerry Jensen ◽

Larry Lake ◽

Ian Duncan ◽

Frank Male

Keyword(s):

Oil Recovery ◽

Oil Production ◽

Distribution Functions ◽

Carbonate Reservoir ◽

Cumulative Distribution ◽

Co2 Injection ◽

Buoyant Flow ◽

Co2 Eor ◽

Co2 Flow ◽

And Storage

Abstract The objective of this study is to improve understanding of the geostatistics of vertical (bed-normal) permeability (kz) and its influence on reservoir performance during CO2 enhanced oil recovery (EOR) and storage. kz is scrutinized far less often than horizontal permeability (kx, ky) in most geological and reservoir modeling. However, our work indicates that it is equally important to understand kz characteristics to better evaluate their influence on CO2 EOR and storage performance prediction. We conducted this study on about 9,000 whole-core triaxial permeability (kx, ky, kz) measurements from 42 wells in a San Andres carbonate reservoir. We analyzed kz data, including heterogeneity, correlation, and sample sufficiency measures. We analyzed wells with the largest and smallest fractions of points with kz > kmax = max(kx, ky), to explore geological factors that coincided with large kz. We quantified these geological effects through conditional probabilities on potential permeability barriers (e.g., stylolites). Every well had at least some whole-cores where kz > kmax. This is a statistically justifiable result; only where Prob(kz > kmax) is statistically different from 1/3 are core samples non-isotropic. In conventional core data interpretation, however, modelers usually assume kz is less than kmax. For the well with the smallest fraction (11%) of cores where kz > kmax, the cumulative distribution functions differ and coincides with the presence of stylolites. We found that kz is about twice as variable as kx in many wells. This makes kz more difficult to interpret because it was (and usually is) heavily undersampled. To understand the influence of kz heterogeneity on CO2 flow, we built a series of flow simulation models that captured these geostatistical characteristics of permeability, while considering kz realizations, flow regimes (e.g., buoyant flow), CO2 injection strategies, and reservoir heterogeneity. CO2 flow simulations showed that, for viscous flow, assuming variable kx similar to the reservoir along with a constant kz/kx = 0.1 yields a close (within 0.5%) cumulative oil production to the simulation case with both kx and kz as uncorrelated variables. However, for buoyant flow, oil production differs by 10% (at 2.0 hydrocarbon pore volume HCPV of CO2 injected) between the two cases. Such flows could occur for small CO2 injection rates and long injection times, in interwell regions, and/or with vertically permeable conduits. Our geostatistical characterization demonstrates the controls on kz in a carbonate reservoir and how to improve conventional interpretation practices. This study can help CO2 EOR and storage operators refine injection development programs, particularly for reservoirs where buoyant flow exists. More broadly, the findings potentially apply to other similar subsurface buoyancy-driven flow displacements, including hydrogen storage, geothermal production, and aquifer CO2 sequestration.

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Time-lapse Borehole Gravity Imaging of CO2 Injection and Withdrawal in a Closed Carbonate Reef

Geophysics ◽

10.1190/geo2020-0650.1 ◽

2021 ◽

pp. 1-96

Author(s):

Alain Bonneville ◽

Andrew J. Black ◽

Jennifer L. Hare ◽

Mark E. Kelley ◽

Mathew Place ◽

...

Keyword(s):

Three Dimensional ◽

Time Lapse ◽

Carbonate Reservoir ◽

Co2 Injection ◽

High Quality ◽

Permeability Model ◽

Porosity And Permeability ◽

And Storage ◽

Northern Michigan ◽

Over Time

Three borehole gravity (BHG) surveys were performed in 2013, 2016, and 2018 to monitor the changes in gravity/density as a result of the injection and withdrawal of carbon dioxide (CO2) into and out of the Dover 33 carbonate reservoir reef in Northern Michigan. The observed gravity changes and inferred density changes have been modeled to determine the flow and storage zones of the injected CO2 in the reef. The high quality and low level of uncertainty of the data collected make them useful for delineating the CO2 plume position over time and for identifying the oil sweeping extent and mechanisms in the Dover 33 reef. The time-lapse gravity results indicate the effects of the changing CO2 mass within the reservoir, consistent with increasing mass from 2013 to 2016 (following CO2 injection) and a decreasing mass from 2016 to 2018 (after CO2 withdrawal). Three-dimensional imaging of fluid migrations in the reef has been obtained by coupling the time-lapse BHG results to a 3D porosity and permeability model. This coupled approach allows the evaluation of the volume of the reef affected by the injection of CO2 between 2013 and 2016, the efficiency of the oil sweeping between 2016 and 2018, and the location of the residual CO2 plume in the reef after 2018.

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