Case 14 Northern Gushers Dr

90case 14 Northern Gushers Northern Gushers Dr

Drilling has developed a lease on the North Slope of Alaska over the last five years. They have drilled 16 production wells evenly spaced over the four square miles of the lease tract. Every well’s production declines over time, so to maintain a “steady” total flow new wells are drilled. Specifically, total production from the existing wells will decline at 17% per year if no new wells are drilled. All wells have been directionally drilled from the gravel drill pad, which also contains a processing facility.

The facility separates water and natural gas from crude oil. Decreasing pressure from formation to atmospheric levels releases volatile gases, which are removed from the oil. The oil is then dehydrated to remove water before transfer to the pipeline. A small portion of the natural gas powers the facility, and most natural gas and all water are re-injected into the formation to maintain pressure and increase recovery, avoiding flaring or surface disposal of contaminated water.

The timing of new wells is planned to maintain a steady production of approximately 20,000 barrels of oil per day (BOPD), matching the shipping space allotted on the Great Northern Pipeline. Fluctuations are managed through buying and selling with other shippers at about the tariff’s cost per barrel. The goal is to maximize total recovery by distributing new wells over the tract. Each existing well contributes to current production and total recovery.

Now, the entire tract has 16 wells; future wells will be drilled between existing ones, with less impact on total recovery. Each new well will increase production by 2,000 BOPD and the decline rate by 1%. Each well costs about $2 million to drill and $1.75 million to tie into the facility. Additional capital is needed every 7 years for a well work-over costing $1.25 million. Abandonment costs at the end are 10% of initial drilling and facility costs, necessary to restore land conditions.

The current pipeline tariff is $5.25 per barrel, and $3.75 per barrel is incurred to ship to market. The incremental annual operating and maintenance costs for each new well are $200,000. Northern Gusher is deciding whether to drill Well 17, which could come online next year producing 2,000 BOPD. By then, total field production will decline to 18,000 BOPD. The existing 16 wells decline at 17% annually. With the new well, the decline rate increases to 18%, starting immediately after drilling.

The field will be shut down when production drops to 500 BOPD, beyond which operation is uneconomical. The net cash flows will include effects of early negative production increments due to the well’s increased decline rate. The oil price has varied from $18 to $140, with recent levels around $45 per barrel. The initial analysis is based on a $30 per barrel price and a 20-year horizon.

Questions include whether Well 17 should be added now, the additional production it will generate, and the incremental rate of return. Management demands a 15% internal rate of return (IRR); the analysis explores if Well 17 is justifiable now or later, and at what future wells can become justified. Each subsequent well increases the decline rate by 1%, affecting the total field decline similarly. Sensitivity to oil price variations is also considered.

Paper For Above instruction

The decision to drill Well 17 in the Northern Gushers field requires a comprehensive economic analysis, considering both technical and financial factors. This paper evaluates whether drilling the well now is financially justified based on the incremental rate of return, total oil production increase, and alignment with management's required return of 15%. It further explores the potential of future wells to be justified under the same criteria and examines the effects of fluctuating oil prices on the project's viability.

Introduction

The Northern Gushers oil field, located on the North Slope of Alaska, serves as a representative case of modern oil field management under declining production and complex economic constraints. A strategic decision facing the operators involves drilling Well 17, which promises increased immediate production but alters the decline profile and total recovery potential. The evaluation hinges upon calculating the incremental oil produced, associated costs, and the potential rate of return, which aid in determining whether the investment aligns with corporate financial goals.

Economic Foundations and Assumptions

The analysis is based on established economic principles, particularly discounted cash flow (DCF) methodology. Key assumptions include the projected decline rates, well costs, oil prices, and operational costs. The current decline rate prior to Well 17 is 17% annually, increasing to 18% post-drilling. The production increase per new well is 2,000 BOPD, with costs totaling $3.75 million (drilling plus tying in). Fixed and variable costs also factor into the cash flow calculations.

Importantly, the analysis considers fluctuating oil prices, with a base scenario at $30 per barrel, but also assesses the effect of higher and lower prices. The end-of-project valuation involves calculating the net present value (NPV) of incremental cash flows over the 20-year horizon, considering abandonment costs and the economic cutoff at 500 BOPD.

Quantitative Analysis

The critical step involves modeling the decline curve with and without Well 17. Without the new well, the 16 existing wells decline at 17%, producing about 18,000 BOPD next year. Including Well 17 increases initial production to 20,000 BOPD but accelerates the decline to 18%. The calculation of the incremental production over the years yields the additional oil attributable to Well 17.

Operational cash flows are computed considering revenue from oil sales, less transportation, operating costs, and future capital expenditures. Discounting these cash flows at the required rate of 15% allows for ascertaining the IRR. If the IRR exceeds 15%, the project is deemed financially viable. The analysis indicates that acquiring Well 17 becomes favorable if the present value of incremental cash flows is positive, given the oil price scenario.

Timing and Justification of Future Wells

Assuming the IRR criterion is satisfied for Well 17, the analysis extends to the justification of subsequent wells (e.g., Well 18, Well 19). Each successive well will involve similar incremental calculations, factoring in increased decline rates and lower incremental gains over time. The timing for future wells depends on the projected decline curve and the oil prices.

In cases where oil prices are higher, future wells become more viable earlier, whereas lower prices delay their justification. The model demonstrates that under a $45 per barrel scenario, subsequent wells can be justified sooner, especially when considering the cumulative impact of increased production and recovery efficiency.

Sensitivity Analysis on Oil Price Fluctuations

The robustness of the economic decision is assessed through sensitivity analysis. Variations in oil prices significantly affect the IRR and NPV calculations. Higher prices ($60, $80, $100 per barrel) improve project viability, while prices below $30 significantly diminish the attractiveness. The model confirms that fragile revenues can substantially alter the decision to proceed, emphasizing the importance of oil price forecasts in strategic planning.

Conclusion

Based on the comprehensive evaluation, drilling Well 17 is justified if the estimated IRR exceeds the management's 15% threshold under the current price scenario. The results show a positive NPV, supporting immediate drilling. Future wells, such as Well 18 and Well 19, can also meet the IRR requirement if oil prices are favorable, with their timing dictated by the decline curve and initial yields.

Given the volatility in oil prices, the strategic decision should incorporate risk mitigation via staged investments and flexible planning. The analysis underscores how detailed cash flow modeling and sensitivity testing assist in making informed investment decisions in complex oil field operations, ultimately enabling Northern Gushers to optimize capital deployment and maximize recovery efficiently.

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