Study Assesses Incentives, Development Strategies for Peruvian Mature Heavy Oil
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Mature heavy-oil fields in the northern Peruvian jungle have produced oil for more than 40 years under primary recovery mechanisms (cold methods). The complete paper explores technical and economic development options to produce heavy-oil resources at commercial rates and showcases three optimization scenarios of higher recovery efficiency aimed at increasing net present value at the basin level.
The constant decline of medium- and light-oil production in most Peruvian fields in recent years, along with the increase in domestic demand, indicates that innovative redevelopment strategies should be implemented for recent large heavy-oil discoveries in the Marañon Basin.
The Norperuano pipeline in its current condition and egress capacity allows exploitation of proved developed producing volumes of Blocks 64, 192, 8, and 95 but constrains the commerciality and development possibilities for Block 67 (Piraña, Dorado, and Paiche fields) and Block 64 (Situche field), which jointly could produce up to 70,000 B/D between 2027 and 2029. The main issue is the present constraint for transportation and blending of heavy oil and diluents. Therefore, an infrastructure revamp is necessary. The authors believe that capital expenditure (CAPEX) to carry out these improvements and expansions is necessary and must be addressed between the operators in the area and the Peruvian government while considering all social and current environmental issues.
Analysis of Production Performance and Recovery
Most Peruvian heavy-oil fields have been discovered in the Marañon Basin. Production history indicates a strong waterdrive mechanism by which oil production declines as water rate increases, while reservoir pressure is sustained with a less than 20% pressure decrease.
Generally speaking, Marañon wells have been drilled following slant trajectories and are only completed with slotted liners without a selective completion. Consequently, no method exists to isolate water zones or encroachment, and oil productivity and relative permeability to oil decrease rapidly as water cut increases.
Horizontal wells have been proposed for the Bretaña heavy-oil field in Block 95. This field is similar to the Jibaro and Jibarito fields in Block 192, with completions featuring autonomous inflow-control devices (AICDs) to delay water breakthrough while improving production performance and increasing oil recovery. Another alternative suggested to increase recovery factor and prevent water breakthrough is dual completion with electrical submersible pumps (ESPs). This completion type has been envisioned for Block 192.
On a well-by-well basis, increasing the recovery factor by implementing new technologies is possible. On a transportation-and-gathering basis, however, issues remain in the basin. A production deferment of at least 7% has been the result of several factors, including a lack of appropriate well-service programs to replace ESPs and clean boreholes, inadequate infrastructure, deteriorating roads accessing the fields, the lack of a supply-change-management program, and a lack of appropriate management of social and environmental issues. CAPEX allocations to the Norperuano pipeline would minimize this problem at the basin level and might solve delay issues at the field level for all blocks.
Hydrocarbon Potential of Mature Heavy-Oil Fields in Peru
Most Marañon production comes from the Vivian and Chonta formations. Predominantly, heavy to medium oil is produced from Vivian, while medium to light oil is produced from Chonta. Most mature fields are in Blocks 192 and 8. Conversely, Blocks 67 and 95 are in the early production stage. Currently, because of the lack of diluent and infrastructure, reserves in Block 67 have been reclassified as Contingent Resources. Block 64 produces light oil that potentially could be used as diluent in Block 67. The true potential of the basin would be a direct result of optimizing the streams from all blocks.
To explore this potential synergy, a reserves model of the entire basin had to be built. Technical, geological, and economic data were provided, including official reports and production databases. For this study, the blocks considered for the model were 64, 192, 67, 8, and 95. Block 39 was not considered because it is still in an exploration phase at the time of writing.
Work Flow To Improve Development
Phase 1: Technical Volumes Audit and Reserves-Estimation Methodology. A special level of granularity was applied to evaluation of reserves volumes in Block 192. The methodology consisted of a quick review of the geology as a first step, followed by decline-curve-analysis forecasting with a volumetrics check component (Fig. 1). Production forecasts were created with oil cuts of approximately 2% owing to waterdrive behavior. Water disposal and reinjection were assumed to be technically feasible in all cases and for all reserve wedges. An increase in the variable oil cost because of water injection was considered year over year. Proved Developed Producing (PDP), Proved (P)+PDP, and P+P+PDP declines were forecast, and workovers were scheduled on the basis of technical information submitted to the government. Declines and volumes were created in a similar fashion for all blocks.
The current Proved and Provable Reserves (2P) forecast peaks at approximately 45,000 B/D in 2021, but the fields do not reach their full potential because of the lack of pipeline capacity. No economics or cash flows were run with these in the 2P base-case model because they are a function of operational-expenditure optimization and pipeline revamp. A contingent wedge for Block 8 was also generated, though resources are not significant. A possible wedge was also generated for the base case; production surpasses 100,000 B/D. The economics of the base-case model are detailed in the complete paper.
Phase 2: Infrastructure, Norperuano Pipeline Revamp, and Blending. The Norperuano pipeline was designed in the late 1970s to transport 200,000 B/D of medium oil at 26.6 °API. Currently, the crude oil flowing has an average gravity of 17.9 °API at 60°F, which constrains the pump rate to 45,000 B/D. This means that crude oil volumes are stored from 10 to 15 days in a tank farm, which increases operational costs that translate into higher transportation fees to operators.
To mitigate this issue, the authors have considered the option of upgrading the plant at Andoas Station and diluent loops connecting to Block 67, plus an additional infrastructural revamp. With the use of these or similar measures, egress capacity could increase considerably to a maximum pumping rate of 150,000 B/D and would eliminate storage fees for the whole basin. Additionally, it is believed that Contingent Resources in Block 64 will be able to be exploited. Total transportation costs for Block 67 would be cut almost in half. After a Norperuano revamp, transportation costs are expected to decrease significantly. If the Peruvian government assumes the total burden of the pipeline revamp, payout occurs in 2030 for the 2P case and in 2027 for the 3P case, resulting in approximately $2 billion cumulative cash flow plus the tangible value of the infrastructure by 2040. The cumulative cash flow generated by all blocks is estimated to be approximately $7.5 billion by 2040 compared with $3 billion without infrastructure investment.
Phase 3: Royalty and Fiscal Regime Framework and Incentives. Summary of Royalties in Peru. Supreme Decree 017-2003-EM adds two methodologies to the Peruvian Organic Law of Hydrocarbons 26221 to determine royalty percentage to be paid for the previous year for an area under an exploration or exploitation contract. If the operator’s economic obligations are not paid in kind, then the operator will select the royalty methodology to be used once a Declaration of Commercial Discovery has been submitted to the government; the selection will be a function of the operator’s own estimation of future investments, expenses, and revenue. Once this selection has been made, no further changes are permitted.
These two methodologies to calculate the royalty percentage are
- Sliding scale (a function of fiscalized oil production)
- By economic results (a function of cumulative revenue and expenses up to the end of a given period)
Corporate Tax. Generally, corporate tax is 30% for exploration and production companies in Peru. Corporate taxes generate a solid cash stream compared with royalties, because the latter can be minimized to a certain extent by operators by using one of the two methodologies. After the economic cases have been run, it is observed that if the government assumes the burden of the pipeline revamp by itself, a favorable environment is created to grow the basin and becomes attractive to operators on a free cash-flow basis.
- Cold-production reservoir-management strategies to revitalize mature heavy-oil fields in Peru would include automation of production systems to extend the lifetime of artificial lift and reduce production deferment, horizontal drilling with selective completion schemes to increase oil recovery and delay water breakthrough, and a continuous surveillance program to monitor waterdrive mechanism and identify bypassed oil.
- Synergy between operators in the Marañon Basin is feasible on an economic basis.
- A pipeline revamp will allow exploitation of heavy-oil resources from Block 67 becoming reserves in the 2P scenario.
- A Norperuano revamp will make the basin more attractive and can be financed with tax money generated within the basin.
- Egress-capacity additions outweigh any recovery-factor optimization or royalty relief.
Study Assesses Incentives, Development Strategies for Peruvian Mature Heavy Oil
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