Summary of Costs for CO2-EOR
CO2-EOR projects have been successfully pursued when oil prices were as low as $15 per barrel. Nonetheless, as oil prices increase, the economic viability of CO2-EOR improves. The relationship between the price of oil, the cost of CO2, and the volume of economically recoverable volumes of oil through the application of CO2-EOR are discussed later in this report.
The costs associated with a CO2-EOR project are site and situation-specific. Detailedstudies, project plans, and economic assessments are required to determine the economic viability of a specific CO2-EOR project. Costs for CO2-EOR operations can vary widely based on location, the geologic characteristics of the CO2-EOR target, the state of development/depletion of the target field, and the amount of CO2 required.
Implementing a CO2-EOR project is a capital-intensive undertaking, even though generally the single largest project expense is the purchase of CO2. Total CO2 costs (both purchase price and recycle costs) can amount to 25% to 50% of the cost per barrel of oil produced. As such, operators have historically strived to optimize and reduce the cost of its purchase and injection wherever possible.
However, CO2 costs are not the only costs affecting the economics of CO2-EOR projects. Up front expenditures also include mechanical integrity reviews of well bores and surface production facilities; pressure testing casing and replacing old tubing; installing new wellheads, flow lines, as well as addressing any potential local environmental concerns. In addition, large CO2 separation facilities must be built to separate, recycle, and compress CO2 recovered from produced oil for subsequent reinjection. New injection and production wells (to reduce pattern spacing) may need to also be drilled, and CO2 (and possibly water) distribution lines will need to be installed. Once injection begins, it can be a number of months before sufficient oil field pressure is reached and oil production can be realized.
However, these costs are comparable to conducting secondary oil recovery operations. In geologically and geographically favorable settings, and the cost increase specific to CO2-EOR operations would be relatively modest, especially relative to the total costs of the full CCS stream from capture to storage. Importantly, when the CO2 flood is started while secondary oil recovery operations are still underway, there could be the opportunity of sharing some field operating costs and utilizing water injection wells for CO2 injection, reducing capital costs. Moreover, incremental development costs associated with CO2-EOR in an existing field would be substantially less than in a new development.
Given this variability, caution should be exercised in quoting general cost numbers for CO2-EOR projects. Nonetheless, the key factors influencing the various categories of costs for a CO2-EOR project are summarized below.
- Well Drilling and Completion. New wells may need to be drilled to configure a CO2-EOR project into an injection/production pattern amenable for CO2-EOR production. Well drilling and completion costs are generally a function of location and the depth of the producing formations.
- Lease Equipment for New Producing Wells. The costs for equipping new production wells consists of a fixed costs for common items, such as free water knock-out, water disposal and electrification, and a variable cost component to capture depth-related costs such as pumping equipment.
- Lease Equipment for New Injection Wells. The costs associated with equipping new CO2 injection wells include gathering lines, a header, electrical service, and a water pumping system. These costs also include a fixed cost component and a depth-related cost component, which varies based on surface pressure requirements.
- Converting Existing Production Wells into Injection Wells. To implement a CO2-EOR project, it is generally necessary to convert some existing oil production wells into CO2 and water injection wells, which requires replacing the tubing string and adding distribution lines and headers. For existing fields, it can be assumed that all surface equipment necessary for water injection are already in place on the lease. Again, existing well conversion costs include a fixed cost component and a depth-related cost component, which varies based on the required surface pressure and tubing length.
- Reworking an Existing Waterflood Production or Injection Well for CO2-EOR (First Rework). For some existing wells, it may be necessary to rework them for CO2-EOR application. This requires pulling and replacing the tubing string and pumping equipment. These well reworking costs are depth-dependent.
- Annual O&M, Including Periodic Well Workovers. The annual operations and maintenance (O&M) costs associated with CO2-EOR projects include both normal oil field O&M costs along with additional costs specific to the application of CO2-EOR. To account for the O&M cost differences between traditional water flooding and CO2-EOR, two adjustments are usually considered. First, workover costs are, on average, about double for CO2-EOR because of the need for more frequent remedial well work. Second, traditional lifting costs should be subtracted from annual waterflood O&M costs to allow for the more rigorous accounting of liquid lifting volumes and costs for CO2-EOR.
- CO2 Recycle Plant Investment. Operation of CO2-EOR requires a recycling plant to capture, separate, and reinject the produced CO2. The size of the recycle plant is based on peak CO2 production and recycling requirements. The O&M costs of CO2 recycling are a function of energy costs.
- Fluid Lifting for CO2-EOR. Liquid (oil and water) lifting costs are calculated based on total liquid production. This cost includes liquid lifting, transportation and re-injection.
- CO2 Distribution. The CO2 distribution system is similar to the gathering systems used for natural gas. A distribution “hub” is constructed with smaller pipelines delivering purchased CO2 to the project site. The distribution pipeline cost is dependent on the injection requirements for the project, and the distance of the CO2-EOR project from the CO2 source.
Detailed documentation of the specific unit costs associated with of CO2-EOR can be found in a series of studies of the CO2-EOR potential of various U.S. basins sponsored by the U.S. DOE,32 and will not be reproduced here.
Despite the wide range in potential costs, Table 3 provides some illustrative costs associated with three representative CO2-EOR projects in the U.S., assuming that it costs $45 per metric ton for purchased CO2, and that “next generation” technology is deployed for EOR.
In general, oil prices have by far the largest impact on the economic viability of a CO2-EOR project. The second largest impact on economic viability tends to be associated with the cost of CO2 to the CO2-EOR operator.
In today’s CO2-EOR market place, the exact contract terms between buyers and sellers of CO2 are not generally disclosed. Historical CO2 pricing within the Permian Basin can be viewed as establishing the current standard for pricing for CO2 -EOR. When source fields and associated pipelines were completed in the early 1980s, CO2 delivered to the oil lease was priced at around $19 to $24 per metric ton. At the time, oil price expectations were optimistic. The oil price crash in 1986 changed this. New contracts had delivered CO2 prices of $9 to $11 per metric ton, and oil price escalators were incorporated into contract terms.
With the advent of the CO2 market supply deficiencies in the Permian Basin, index (base) prices have climbed, escalators start at higher levels, and CO2 prices are not capped like in the past. Some suppliers are keeping the CO2 for themselves whereas, in the past, some supplier competition was always present. Moreover, many current contracts were originally written without assuming today’s relatively higher anticipated oil prices. Should oil prices remain at sustainably higher levels, new contract terms may evolve. In today’s market, with oil prices in excess of $100 per barrel, delivered CO2 costs where some CO2 -EOR projects remain economically viable could be as high as $40 to $45 per metric ton.
On the other hand, under a market where CO2 emission reductions have value, “gas-on-gas” competition for new CO2 sources entering the market may put downward pressure on CO2 prices. If increasingly strict requirements are implemented for limiting CO2 emissions, particularly for new energy sources, producers/emitters of CO2 may become increasingly willing to provide CO2 supplies to CO2-EOR projects at competitive or even lower delivered CO2 costs. Assuming that such policies serve to reduce prices for delivered CO2 to merely the cost of compression and transportation, costs of CO2 on the order of $15 per metric ton are conceivable.
Table 3. Illustrative Costs for Representative CO2-EOR Projects in the U.S.
|Example EOR Field||EastReservoir||California Reservoir||Oklahoma Reservoir|
|Total Oil Production (Million Barrels)||112.0||140.0||81.3|
|Injected CO2 (Tonnes/Bbl)||0.24||0.28||0.23|
|Produced Oil (Bbls/ton of Captured CO2)||4.12||3.63||4.33|
|No of Patterns||24||40||257|
|Existing Injectors Used||24||7||0|
|Convertible Producers Used||0||0||0|
|New Injectors Drilled||0||0||257|
|Existing Producers Used||0||54||290|
|New Producers Drilled||0||54||290|
|API Gravity (o API)||43||24||37|
|Project Length (years)||34||29||23|
|Technology Case||Next Gen||Next Gen||Next Gen|
|Capital Costs ($Million, discounted)|
|New Well - D&C||$ 32.10||$ -||$ -|
|New Well - Next Generation D&C||$ 32.10||$ 80.31||$ 654.96|
|Reworks - Producers to Producers||$ -||$ 4.62||$ 27.80|
|Reworks - Producers to Injectors||$ -||$ 7.61||$ 63.99|
|Reworks - Injectors to Injectors||$ 2.11||$ 1.32||$ -|
|Surface Equipment (new wells only)||$ 14.15||$ 10.51||$ 79.55|
|Plugging Costs||$ 1.35||$ 19.23||$ 17.25|
|Sub Total||$ 81.81||$ 123.59||$ 843.54|
|$/Bbl||$ 2.12||$ 2.33||$ 23.76|
|CO2 Recycling Plant||$ 45.90||$ 66.94||$ 43.35|
|Trunkline Construction||$ 3.15||$ 3.15||$ 3.15|
|Next Generation Capex||$ 13.09||$ 19.37||$ 89.00|
|Cap Ex G&Amp;A||$ 28.79||$ 42.61||$ 195.81|
|Pipeline to Field||$ 54.30||$ 54.30||$ 54.30|
|Sub Total||$ 145.22||$ 186.37||$ 385.61|
|$/Bbl||$ 3.76||$ 3.52||$ 10.86|
|Total Capex||$ 227.03||$ 309.96||$ 1,229.15|
|$/Bbl||$ 5.88||$ 5.85||$ 34.61|
|O&M Costs ($/Bbl, discounted)|
|Operating & Maintenance||$ 0.73||$ 0.85||$ 6.33|
|Operating & Maintenance Next Gen||$ 0.07||$ 0.08||$ 0.63|
|Lifting Costs||$ 1.51||$ 3.19||$ 2.04|
|G&A||$ 0.45||$ 0.81||$ 1.67|
|Pipeline||$ 0.05||$ 0.05||$ 0.05|
|Total O&M Costs||$ 2.80||$ 4.98||$ 10.72|