Farnsworth Field CO2-EOR Project: Performance Case History

Ampomah, William; Balch, Robert; Grigg, Reid B.; Will, Robert; Dai, Zhenxue; White, Mark D.

doi:10.2118/179528-ms

Cited by 46 publications

(41 citation statements)

References 24 publications

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“…1). History matching was used to calibrate the reservoir model using both primary and secondary oil recovery (production) data (Ampomah et al, 2016).…”

Section: Farnsworth 3-d Reservoir Modelmentioning

confidence: 99%

Uncertainty analysis of carbon sequestration in an active CO2-EOR field

Pan

McPherson

Dai

et al. 2016

International Journal of Greenhouse Gas Control

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a b s t r a c tEnhanced Oil Recovery (EOR) is perhaps the most feasible option for geologic CO 2 sequestration (GCS). However, the typical large extent of uncertainty in reservoir properties is a major obstacle to effective risk assessment of GCS. The primary objective of this study was to quantify uncertainties in key reservoir parameters for an active, commercial-scale CO 2 -EOR field. We selected the Morrow formation within the active Farnsworth Unit (FWU) EOR field in Texas for this case study. Critical for this study are historical and real-time CO 2 injection/production data as well as fundamental hydrologic and geologic characterization data from injection wells and three dedicated characterization/observation wells. We designed and applied a response surface methodology (RSM) integrated with Monte Carlo simulations to evaluate and quantify uncertainty. Previous sensitivity studies identified critical uncertain parameters including reservoir permeability, anisotropy ratio of permeability (k v /k h ), water-alternating-gas (WAG) time ratio, and initial oil saturation. Cumulative oil production, net CO 2 storage, net water stored (difference between the injection water and produced water), and reservoir pressure at the injection well were the primary dependent variables used to evaluate uncertainties of CO 2 storage associated with oil production and potential risk of reservoir pressure build-up. A 3-D static reservoir model was constructed based on the geology of the Farnsworth EOR site, serving as the basis for all multiple-realization reservoir simulations. After performing stepwise regression analyses, a series of response surface models of the dependent variables at each time step were constructed and validated using appropriate goodness-of-fit measures. Given the range of uncertainties in the independent variables, cumulative distribution functions (CDFs) and uncertainty bounds (5th and 95th percentiles) of output responses were estimated based on regression equations and Monte Carlo sampling. Forecasted cumulative oil production and net CO 2 storage varied from 54,696 bbl, and 22,784 t, respectively, at the 5th percentile to 203,989 bbl, and 39,525 t at the 95th percentile after 5 years. These results suggest that a significant proportion of forecasted output response uncertainty, including forecasted storage capacity, is propagated from parameter uncertainties. For this case study, response surface results suggest that maximum cumulative oil production could be achieved with permeability in a specific range (10.0-31.6 mD, which is close to the mean value of the actual strata). The pressure near the injection well exceeded 40 MPa, and 54 MPa at the 95th percentile after 1 and 5 years, respectively. The reservoir pressure fracturing threshold is just under 37 MPa in the FWU, indicating a significant risk of caprock fracturing in the low permeability zones due to pressure build-up.

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“…1). History matching was used to calibrate the reservoir model using both primary and secondary oil recovery (production) data (Ampomah et al, 2016).…”

Section: Farnsworth 3-d Reservoir Modelmentioning

confidence: 99%

Uncertainty analysis of carbon sequestration in an active CO2-EOR field

Pan

McPherson

Dai

et al. 2016

International Journal of Greenhouse Gas Control

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“…All CO 2 is derived from two anthropogenic sources: the Arkalon Ethanol Plant in Liberal, Kansas and the Agrium Fertilizer Plant in Borger, Texas. As of June 2018, 1,180,000 metric tons of CO 2 have been stored at FWU by the operator and since SWP started monitoring,~734,000 metric tons have been stored [10]. The Morrow B sandstone is the target reservoir for the FWU project, located at a depth between 7550 ft (2301 m) and 7950 ft (2432 m) and spanning approximately 28 square miles (72 km 2 ) with a mean thickness of 24.3 ft (7.4 m; Figure 1B,C; see also [7]).…”

Section: Morrow B Heterogeneitymentioning

confidence: 99%

“…Enhanced oil recovery (EOR) utilizing reservoir flooding with high density supercritical carbon dioxide (scCO 2 ) is a means to mitigate rising atmospheric carbon dioxide levels while extracting oil as an energy resource, with a net storage of carbon in geologic units (often termed carbon capture, utilization, and storage or CCUS). The focus of EOR/CCUS is on depleted oil reservoirs, and an example of this is the Farnsworth Unit (FWU) of West Texas (Figure 1), which has been in operation since the 1950s [1] and a target of EOR operations since 1984 [2]. The Southwest Regional Partnership on Carbon Sequestration (SWP) was established in 2003 by the US Department of Energy's National Energy Technology Laboratory, to study the feasibility of capturing and permanently storing CO 2 .…”

Section: Introductionmentioning

confidence: 99%

“…The Southwest Regional Partnership on Carbon Sequestration (SWP) was established in 2003 by the US Department of Energy's National Energy Technology Laboratory, to study the feasibility of capturing and permanently storing CO 2 . Part of the SWP's activities has been devoted to reservoir characterization, injection of scCO 2 , and monitoring CCUS efficiency at the Farnsworth Unit [2][3][4][5].…”

Section: Introductionmentioning

confidence: 99%

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Carbon Storage and Enhanced Oil Recovery in Pennsylvanian Morrow Formation Clastic Reservoirs: Controls on Oil–Brine and Oil–CO2 Relative Permeability from Diagenetic Heterogeneity and Evolving Wettability

et al. 2019

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The efficiency of carbon utilization and storage within the Pennsylvanian Morrow B sandstone, Farnsworth Unit, Texas, is dependent on three-phase oil, brine, and CO2 flow behavior, as well as spatial distributions of reservoir properties and wettability. We show that end member two-phase flow properties, with binary pairs of oil–brine and oil–CO2, are directly dependent on heterogeneity derived from diagenetic processes, and evolve progressively with exposure to CO2 and changing wettability. Morrow B sandstone lithofacies exhibit a range of diagenetic processes, which produce variations in pore types and structures, quantified at the core plug scale using X-ray micro computed tomography imaging and optical petrography. Permeability and porosity relationships in the reservoir permit the classification of sedimentologic and diagenetic heterogeneity into five distinct hydraulic flow units, with characteristic pore types including: macroporosity with little to no clay filling intergranular pores; microporous authigenic clay-dominated regions in which intergranular porosity is filled with clay; and carbonate–cement dominated regions with little intergranular porosity. Steady-state oil–brine and oil–CO2 co-injection experiments using reservoir-extracted oil and brine show that differences in relative permeability persist between flow unit core plugs with near-constant porosity, attributable to contrasts in and the spatial arrangement of diagenetic pore types. Core plugs “aged” by exposure to reservoir oil over time exhibit wettability closer to suspected in situ reservoir conditions, compared to “cleaned” core plugs. Together with contact angle measurements, these results suggest that reservoir wettability is transient and modified quickly by oil recovery and carbon storage operations. Reservoir simulation results for enhanced oil recovery, using a five-spot pattern and water-alternating-with-gas injection history at Farnsworth, compare models for cumulative oil and water production using both a single relative permeability determined from history matching, and flow unit-dependent relative permeability determined from experiments herein. Both match cumulative oil production of the field to a satisfactory degree but underestimate historical cumulative water production. Differences in modeled versus observed water production are interpreted in terms of evolving wettability, which we argue is due to the increasing presence of fast paths (flow pathways with connected higher permeability) as the reservoir becomes increasingly water-wet. The control of such fast-paths is thus critical for efficient carbon storage and sweep efficiency for CO2-enhanced oil recovery in heterogeneous reservoirs.

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“…Salinity is also neglected in the CO 2 injection process, as its influence on solubility is negligible. The permeability curves for oil-water and liquid-gas in this rock system are shown in Figure 1 [7].…”

Section: Reservoir Descriptionsmentioning

confidence: 99%

Applicability of an Artificial Neural Network for Predicting Water-Alternating-CO2 Performance

Van

Chon

2017

Energies

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The injection of CO2 as part of the water-alternating-gas (WAG) process has been widely employed in many mature oil fields for effectively enhancing oil production and sequestrating carbon permanently inside the reservoirs. In addition to simulations, the use of intelligent tools is of particular interest for evaluating the uncertainties in the WAG process and predicting technical or economic performance. This study proposed the comprehensive evaluations of a water-alternating-CO2 process utilizing the artificial neural network (ANN) models that were initially generated from a qualified numerical data set. Totally two uncertain reservoir parameters and three installed surface operating factors were designed as input variables in each of the three-layer ANN models to predicting a series of WAG production performances after 5, 15, 25, and 35 injection cycles. In terms of the technical view point, the relationships among parameters and important outputs, including oil recovery, CO2 production, and net CO2 storage were accurately reflected by integrating the generated network models. More importantly, since the networks could simulate a series of injection processes, the sequent variations of those technical issues were well presented, indicating the distinct application of ANN in this study compared to previous works. The economic terms were also briefly introduced for a given fiscal condition which included sufficient concerns for a general CO2 flooding project, in a range of possible oil prices. Using the ANN models, the net present value (NPV) optimization results for several specific cases apparently expressed the profitability of the present enhanced oil recovery (EOR) project according to the unstable oil prices, and most importantly provided the most relevant injection schedules corresponding with each different scenario. Obviously, the methodology of applying traditional ANN as shown in this study can be adaptively adjusted for any other EOR project, and in particular, since the models have demonstrated their flexible capacity for economic analyses, the method can be promisingly developed to engage with other economic tools on comprehensively assessing the project.

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Farnsworth Field CO2-EOR Project: Performance Case History

Cited by 46 publications

References 24 publications

Uncertainty analysis of carbon sequestration in an active CO2-EOR field

Uncertainty analysis of carbon sequestration in an active CO2-EOR field

Carbon Storage and Enhanced Oil Recovery in Pennsylvanian Morrow Formation Clastic Reservoirs: Controls on Oil–Brine and Oil–CO2 Relative Permeability from Diagenetic Heterogeneity and Evolving Wettability

Applicability of an Artificial Neural Network for Predicting Water-Alternating-CO2 Performance

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