Upstream Fiscal Regime Incentives for Captured CO₂-EOR

Abstract

Several preliminary scoping studies have identified a significant potential for captured CO₂ for enhanced oil recovery (EOR) projects outside North America. In countries where severe upstream fiscal terms can constitute an obstacle for such projects when they are profitable before tax, incentives should be considered. We compare several incentive schemes by running simulations on a realistic CO₂-EOR project inspired by the Denver unit of the Wasson US field. The economic approach is based on incremental net present values (NPV). This requires dual simulations of a base case and a CO₂-EOR case because the calculus is not linear and cannot be run on a single incremental costs and production case. The design of the incentive package is challenging for the host country. The incentive package should sufficiently improve the company NPV without reducing the State NPV in most situations that are likely to occur. By looking at both oil company and host country incremental NPV, we show that improvements in cost deductions, through accelerated capital expenses depreciation and uplift, are better suited for the host country than tax rate reductions. We also explore an upstream tax recycling scheme for financing CO₂ purchase costs.

Appendices

Appendix 1.1: What Is CO₂-Enhanced Oil Recovery?

In primary recovery, oil is recovered from the natural energy of the reservoir. In secondary recovery, energy is added to the reservoir by injecting fluids such as water or natural gas. Under both recovery techniques, more than 50% of the oil still remains in the reservoir. To recover more oil, other recovery techniques, called enhanced oil recovery or tertiary recovery can be implemented.

CO₂ injection, which can be miscible or immiscible, is one of the tertiary oil recovery technologies used to produce oil that would not be recovered by primary or secondary recovery methods.

In miscible CO₂ flooding, CO₂ in a supercritical state is injected into oil reservoirs and the pressure is kept above the oil-CO₂ minimum miscibility pressure (MMP). Most currently producing CO₂-EOR fields are under miscible flooding because oil recovery rates are higher than under immiscible flooding. CO₂ flooding experience from a studied sample of 31 US fields shows that in suitable reservoirs, the recovery of OOIP can improve recovery by 5 to 20% [1].

In some cases, the reservoir may need to be re-pressurized to reach the MMP. Once in the reservoir, CO₂ has a secondary recovery impact, but also mixes with the oil, reducing its viscosity and improving its displacement to the production well. In addition, it reduces the interfacial tension between oil and water and this increases the amount of mobile oil. A typical CO₂ flooding cycle starts with a pure CO₂ injection phase. After a certain response time, oil production increases, reaches a short peak period and quickly declines due to CO₂ breakthrough: As CO₂ is much more mobile than the oil and water present in the reservoir, some of the injected CO₂ “breaks through” from injection wells into the production wells without contacting oil in the reservoir. A water alternating gas (WAG) phase is then initiated in order to reduce CO₂ breakthrough. It consists of injecting successive slugs of water and CO₂. When the injected CO₂ does not contribute anymore to significantly increase oil production, the operator goes back to water injection until the end of the field’s life. Depending on the characteristics of the reservoir, other CO₂ injection sequences may be considered.

During all these phases, the produced fluids are water, oil, and a gas stream of CO₂ and reservoir gases. Part of the injected CO₂ remains in the reservoir. The produced CO₂ is separated from the gas stream at surface facilities. It is then compressed and reinjected in the reservoir, reducing the need for external CO₂. An environmental benefit of this recycling is that virtually none of the injected CO₂ is released into the atmosphere. But, as Faltinson et al. [4] point out, an overall assessment should be conducted in order to also evaluate the amount of CO₂ that the EOR project emits during its implementation and operational phases.

CO₂-EOR projects have so far been implemented on mature oil fields at a late stage of production under secondary recovery water flooding. A small-scale pilot CO₂-EOR project may precede the CO₂-EOR full-scale project. A CO₂-EOR execution plan comprises the installation of new equipment and a modification of existing wells and equipment and if necessary, the drilling of new wells. New wells can either be injectors or producers. The plan includes the construction of a recycling plant comprising CO₂ separation and compression units and the laying of CO₂ distribution lines to the injection wells. The existing surface equipment and completion of operational existing wells may need an upgrade to handle the production of CO₂-induced corrosive. Other upgrades of surface facilities may also be required due to the new operating conditions.

Appendix 1.2: Case Production Profiles

The case study oil field contains 117 million barrels (MMbbl) of original oil-in-place (OOIP) and has a hydrocarbon pore volume (HCPV) of 152 MMbbl (HPCV represents the pore volume of the reservoir occupied by hydrocarbons before the start of any production). At the start of the CO₂-EOR project, the field is under a water injection scheme with an injected volume of 22,000 barrels of water per day (bwpd) corresponding to 5.3 HCPV per year. The field is at an advanced stage of depletion and produces 1,885 barrels of oil per day (bopd) with a high (91%) water cut. The production and injection wells are vertical and arranged in contiguous five-spot patterns (i.e., four injectors and one producer per pattern). Each pattern is a square covering an area of 40 acres; production wells are located in the center of a square and injection occurs through wells located at the four corners. Figure 17 illustrates a similar pattern coverage on the Kinder Morgan SACROC field in Texas.

Fig. 17

Five-spot patterns of the SACROC field

The CO₂-Prophet simulations start from this point. The baseline case consists of resuming water injection without investing in CO₂-EOR. In the event of CO₂-EOR, seven miscible cases starting with a common pure CO₂ injection phase and followed by different WAG phases are also simulated. In each case, injected fluid volumes are equal to 5.3% HCPV per year and reach a total of 1.54 HCPV over the 29-year simulation period.

A CO₂-EOR case with a 2:1 WAG ratio phase, where two equal volumes of water for one of CO₂ are alternatively injected after the pure injection phase is described hereafter. The CO₂-EOR project is executed in two consecutive injection phases. In the first, pure CO₂ replaces the previously injected water. The mass rate of the injected CO₂ is 0.92 million tons/year and corresponds to the capacity of current anthropogenic CO₂ capture plants. Pure CO₂ is injected over 20 months up to a total of 0.1 HCPV. The CO₂ mixes with the oil, reducing its viscosity, which improves its mobility. Two years after the start of this phase, oil production progressively increases, reaching a peak of about 5600 bopd for a short period. A 2:1 WAG is then applied, corresponding to injecting 66% reservoir volumes of water and 33% of CO₂. Overall, the oil production slowly declines at an average rate of 4% after reaching its peak.

The CO₂ volume ratio during the WAG phase that follows the pure CO₂ injection phase is used to identify the seven simulated CO₂ injection plans. Figure 18 depicts, in reservoir barrels per day, the injection and production profiles of the different fluids during the three injection phases: the past water injection phase, the pure CO₂ phase and the WAG. The solid line corresponds to the oil production under CO₂-EOR. The dotted line corresponds to the decline-curve for oil production of the water injection only Baseline Plan, or the amount of oil expected to be produced in the absence of CO₂-EOR. The delivered CO₂ (purchased CO₂), indicated by the bars, declines over time as more CO₂ is produced and recycled for reinjection.

Fig. 18

Injected and produced volumes (reservoir barrels)

Figure 19 shows the daily rates of surface or stock tank oil barrels (STB) (at atmospheric pressure) in the 33% CO₂ scenario (dotted line). The total 32.4 MMbbl production of the CO₂-EOR case is the area below the dotted line. The solid line corresponds to the STB daily rate for the baseline water injection case. The 11.6 MMbbl total production of the Baseline water injection case is the lightly shaded area below the solid line. The incremental oil produced via CO₂-EOR production (dark shaded area) is obtained by the difference of the two production areas. It is equal to 20.8 MMbbl (32.4–11.6), which represents an 18% additional oil recovery factor.

Fig. 19

Oil production (surface barrels)

CO₂-Prophet uses a simplified material balance equation, where injected water plus injected CO₂ volumes are equal to the sum of oil, water, and CO₂ produced volumes at reservoir conditions. Over the 29-year time horizon, injected and produced volumes are both equal to 232 MMbbl reservoir barrels (Table 6). Water and CO₂ are the main volume flows in the reservoir. Assuming there are no CO₂ losses, delivered CO₂ is equal to stored CO₂, which reaches 44 MMbbl reservoir barrel or 5 million tons of CO₂ stored in the field over 29 years.

Table 6 Reservoir MMbbl corresponding to Fig. 18

The results of the present case study are compared with industry CO₂-EOR statistics published by the Oil and Gas Journal EOR Survey [9]. The peak production profile of the case study is in the mid-range of US fields. The peak oil production per active well (producer and injector) is 88 bopd (5600 bopd/(32 + 32) wells), which is higher than the survey average. With an incremental oil recovery factor of 18% (21 MMbbl/117 MMbbl), a CO₂ utilization of 0.23 tons of CO₂/bbl (5 million tons/21 MMbbl) and a 29% CO₂ retention factor measured in percent HCPV stored (44 MMbbl CO₂/152 MMbbl HCPV), the case study shows performance characteristics within the range of operating projects [1].

Appendix 1.3: Cost Estimation

Table 7 reports the estimated costs used for the Baseline plan and for seven CCO₂ plans.

Table 7 Capex and opex

Water Injection (Baseline Plan)

No capex is spent. Fixed opex are set at $8 million per year consisting mainly of salaries, maintenance, and work-over of 32 water injectors and 32 oil-producing wells. Variable opex are $0.50/bbl for handling produced liquids (water and oil) and $2/bbl for transporting oil to the sales point.

CCO₂ Plans

Capex ranges from $134 million to $184 million, depending on the CO₂ plan. The variable element is the cost of the recycling facility, which depends on the daily peak produced gas volume to process. This peak volume varies between 6 MMcf/d in the low CO₂ injection plan to 44 MMcf/d in the high CO₂ injection plan.

It is assumed that the trunk line delivering fresh captured CO₂ is paid for by the CO₂ supplier or by the State—i.e., it is not a cost to the oil producer. The CO₂ is supplied at the required conditions for injection into the field. The maximum rate of the delivered CO₂ volumes is 60 MMcf/d, corresponding to 1.1 million tons per year. These figures are representative of the mass of CO₂ that could be captured every year from a 150-MW coal plant or a 250-MW gas plant.

The producer’s investment program includes drilling 32 wells, work-over on 32 existing wells that can be kept, new surface facilities for the separation, compression of the produced CO₂ and injection of recycled CO₂, and an upgrade of existing facilities. The facilities are installed and operational in 2 years.

• Drilling 32 new wells: $105 million

  The existing depth-related KM model cost calculations for drilling and completion were updated by benchmarking against the QUE$TOR (2016b) cost estimation data. The drilling cost of a new well was estimated at $3.3 million for 5000-ft. reservoir depth.

• Rework of 32 existing wells: $8.3 million

  Well rework is assumed to be similar to the cost of well completion on a per-foot basis. This leads to cost of $0.26 million per well for a 5000-ft. reservoir depth.

• Surface work on all 64 operational wells: $2.6 million

  Cost are assumed as $60,000 per injector and $30,000 per producer.

• Surface facilities for recycling produced CO₂: from $8 million to $58 million

  Recycling comprises the separation and compression of CO₂ for reinjection into the field. We use a unit capex cost of $1.1 million per MMcf/d of peak produced and recycled CO₂ plus a 20% sizing factor based on data from NETL [11].

• Upgrade of existing surface facilities: $10 million

Fixed opex are estimated to be 10% higher than in the Baseline Plan plus a supplement reflecting 5% of the recycling facility cost. Variable unit opex are assumed identical to those of the baseline scenario, with an additional energy cost of $0.5/Mcf for the compression of recycled CO₂. Analysis of several CO₂-EOR projects indicates 6 kWh per Mcf of CO₂ is consumed for CO₂ compression.

In all the plans, when the field reaches its economic limit or the end of its 30-year technical life, whichever occurs first, production is halted and the field is abandoned. The economic limit is reached when sales no longer cover opex. Decommissioning costs are estimated at $36 million in the water injection case and $53 million in the CO₂ injection cases using the proprietary QUE$TOR cost estimation software.