When the purpose of an economic analysis is to help make a decision, there are several key managerial indicators or economic parameters that are considered. Although there are many parameters that can be considered (see Thompson and Wright, Chap. Net present value is the sum of the individual monthly or yearly net cash flows after they have been discounted with Eq.1. In Table 1, the three columns labeled "Discounted Net Cash Flow" show this calculation at annual discount rates of 10, 20, and 34.3%. The net present values (NPV) at these discount rates are $99,368, $51,950, and $0, respectively.
Figure 1.1 – Calculation of periodic net cash flow for a royalty tax system (like the U.S.), adapted from Thompson and Wright. Gross production is the volume of oil/gas that is projected to be produced during the particular month or year being calculated. Gross production is one of the most important numbers entering the net cash flow calculation and, simultaneously, one of the most difficult to determine accurately. Much of the science and art of petroleum engineering is involved in estimating these numbers for future time periods. Usually the decline curves that are used to forecast future revenues are based on production rather than sales. If there is significant shrinkage, that should be taken into account before calculating the cash flows. Typical causes of shrinkage include lease use of gas for heater treaters or compressor fuel. Gross sales is the volume of oil/gas that is projected to be sold during the time period. If shrinkage is negligible, gross sales will equal gross production. Typically, the people who drill and operate a well do not own the minerals they are extracting.
Oil price forecasting has been shown to be challenging if not impossible for the long-term. However, the oil price has a major impact on Exploration and Production projects.
Historical Project Realized Oil Price (PROP) can be calculated for example projects by summing up the total project revenue using the actual oil prices and dividing through the total amount of oil produced. For different starting dates of example projects, the PROP changes. Determining the PROP for different starting times, a Cumulative Distribution Function (CDF) can be derived. Adjusting this CDF for expected "half cycle breakeven costs" for the low limit and demand considerations for the high case leads to a PROP range that can be used for future project evaluation.
Including PROP ranges into project evaluation allows for the selection of the most attractive development option, Value of Information analysis and project Probability of Economic Success (PES) calculation including oil price uncertainty.
Furthermore, using PROP ranges rather than oil price scenarios enables a distinction between short-term budget planning and long-term project development. For budget planning, a scenario approach is suggested while for long-term planning PROP ranges should be used. Applying long-term planning on PROP ranges leads to less fluctuation in staff planning and small annual adjustments in PROP range forecasting. Also, using PROP ranges results in increasing PES project hurdles at low oil prices and lower PES hurdles at high oil prices. Hence, at low oil prices the risk averseness of the company is increased. Another effect of using PROP ranges is that at high oil prices robustness of projects to low oil prices is included in the assessment.
To investigate the effect of PROP ranges on portfolio PES hurdles and project PES hurdles, a simplified linear-fit-model was developed. The results of the model showed that the project PES hurdles in a Value at Risk assessment can be determined applying the linear-fit-model to quantify the oil price dependency. The required individual project PES hurdles can be adjusted using the linear-fit-model to account for oil price uncertainty.
The booming of shale gas production has affected the natural gas price in the United States (U.S). Natural gas price has plummeted due to the excessive capacity. On the other hand, the import of crude oil and its production of diesel, gasoline, and others are increasing. The problem lies in finding a practical, economical and efficient way of making natural gas marketable. A potential solution is Small-scale Gas-to-Liquids plants. Small-scale GTL can fulfill some of the petroleum products demand such as Gasoline, Ultra-low-sulfur diesel, and jet-fuel. Small-scale GTL plants especially can benefit countries where the gas production is higher than gas demand, yet these countries depend on imported oil.
A Monte Carlo simulation approach is used to conduct sensitivity analysis on various parameters such as the feedstock/natural gas price, plant capacity, plant efficiency, capital expenditure (CAPEX), operational expenditure (OPEX), and products selling prices. The range for natural gas prices and gasoline prices are obtained from average historical data in the United States for the past five (10) years where the shale gas production is booming. The CAPEX is attained from previous GTL project plants before using the Power-Sizing model and literature. The annual OPEX is the percentage fraction of the CAPEX. The plant capacity was chosen based on the diseconomy factor estimated from previous GTL projects. Even with the premium quality of GTL products, the selling price for the products is equal to regular crude oil products.
Economic metrics such as Net Present Value (NPV), Internal Rate of Return (IRR), Cost-to-Profit (C/P) ratio and Payback Period were used to assess the success of GTL technology at each given business case. Results showed that NPV, IRR, C/P ratio and payback period are most affected by CAPEX, products selling price, OPEX, and capacity of the plant, in respected order. Based on these case scenarios and parameters, sensitivity analysis is conducted using Monte Carlo's simulation of 10,000 iterations the results for NPV, IRR, C/P ratio and payback period showed that the GTL project is profitable. The NPVs for the GTL plant in this study are positive for all case scenarios.
It is expected that the outcome of this research would guide shale gas producers and private investors when considering GTL investment to monetize their assets in the United States and beyond.
Echendu, Joseph C (Emerald Energy Institute and International Institute for Petroleum, Energy Law, and Policy) | Idowu, Adekunle Joseph (African University of Science and Technology) | Adejumo, Adedapo (Emerald Energy Institute) | Iledare, Omowunmi (Emerald Energy Institute) | Akinlawon, Adeyemi Joseph (Emerald Energy Institute)
In this work we evaluate the effects of the single-tier tax system (STS) at its current rate in comparison to the proposed dual-tier tax system (DTS) in the National Petroleum Fiscal Policy in Nigeria on project economic performance. We also expound on the arguments between two schools of thought (single tax and dual tax proponents) toward understanding the rationale underlying the divergent viewpoints. The methodological approach applies the discounted cash flow modeling framework to evaluate the performances of terrainbased projects using selected metrics, such as internal rate of return, discounted payout, net present value, and government take (GT) under the two tax systems. This approach calibrates the unit technical cost for typical deepwater projects in Nigeria and imposes the current and proposed fiscal terms. Varying cost treatment options and alternative allowables/incentives are investigated in the modeling framework using global best practices.
We conclude that whichever tax system is adopted, it is possible to achieve equivalent economic metrics. However, the DTS presents a better, more flexible option over the STS because one of the split rates—especially the hydrocarbon resource tax—could serve as an instrument to incentivize investment, promote conservation, and expand the resource base through technology innovation more easily without denying the mineral owner an outright revenue through taxation. In a classical case such as Nigeria, in which the national fiscal budget is largely financed using hydrocarbon revenue, the DTS seemingly offers a better option for revenue sharing among the stakeholders—the resource owners and the Federal Government—than the current single upstream tax system. Our discussion in this paper bridges the gap between the divergent viewpoints on the taxation system in Nigeria by proffering a pathway. We suggest that the overall objectives of stakeholders could be achieved using either STS or DTS metrics if the mechanics in designing the fiscal system is better understood. This will lead to progressive application in achieving divergent expectations.
Das, Paloma (Reveal Energy Services, Inc.) | Solaja, Ola (SM Energy) | Cabrera, Julio (SM Energy) | Scofield, Reid (SM Energy) | Coenen, Erica (Reveal Energy Services) | Kashikar, Sudhendu (Reveal Energy Services) | Kahn, Charles (Reveal Energy Services)
The industry continues to face a challenge understanding and optimizing completion strategies to minimize the impact of infill development on existing wells and achieve larger Stimulated Reservoir Volume (SRV) on infill wells. This paper presents a cost-effective technique for evaluating parent-child interaction using poroelastic pressure responses on the parent wells. The method was employed on a four-well pad in the Eagle Ford to understand diversion effectiveness and the extent of offset depletion.
The case study comprised the analysis of pressure data sets, covering wellhead pressure data from the nearby parent wells. The method quantifies and interprets pressure signal magnitude and its transient behavior for each completed stage. The well offsetting the parent well was completed using two different completion designs. One half of the lateral was completed without employing diversion, while the other half employed a specific diversion strategy. The primary goal of the case study was to demarcate the areal extent and degree of depletion around the existing wells and determine the effectiveness of using diversion in inhibiting growth towards parent wells.
The analysis determined fluid and fracture pathways, mainly seen driven by formation stresses, depletion, and completion design in each stage. The case study compared the effects of employing diversion vs. not employing diversion, using the magnitude of pressure responses felt by the parent well. The initiation points of the pressure signals, as felt by the offset wells on each side quantified how quickly and in which direction the newly treated fractures were growing. The pressure responses from multiple parent wells were correlated to understand the areal extent of depletion around each offset producer. This ultimately promotes understanding the difference in pre and post production of the wells and optimizes infill completions for future development.
Cross well analysis using poroelastic pressure responses is easy to implement and very cost-effective. The proposed method provides a workflow to analyze offset pressure data in a consistent and reproducible manner. This method affords the industry a better understanding of parent well damage and mitigation of child well productivity loss.
The interest in developing new technologies to produce energy with low environmental impact by using renewable sources has grown all over the world in recent years. The economics of wave energy converters (WECs) is of particular interest. The key factors affecting the cost of energy of marine renewable devices include performance, capital costs, operating & maintenance costs and risks due to the offshore environment. The energy converted into electricity by a WEC is a function of the wave climate at the installation location. Assessments of efficiency open up a large number of questions. These include the theoretical maximum energy that the converter could be expected to capture, the intermediate efficiencies of its prime mover and individual power take-off system components, and the certainty to which the resource's energy content itself can be described. Furthermore, overall efficiency may be influenced by certain control and operating regimes that relate to other aspects of the design, including survivability. This paper presents a mathematical method to describe the economics of a wave energy converter based on performance, capital costs, operating & maintenance costs and risks. In the economic performance estimation, the wave energy converter investment and associated investment analysis is based on variables that are allocated to drivers for cost and efficiency.
In this paper we present an example of a Coal Seam Gas field evaluation that funnels multiple realisations of the subsurface forecast for different well spacing into a simple visual tool for economic screening of the development opportunities.
The evaluation approach can be described as follows: consolidate the available data in a regional scale geological model; identify the prospective production seams and areas based on a combination of static properties; automatically populate the potential development areas with model wells of different types, completions and lateral spacing; and run the resulting multiple reservoir models in a dynamic simulator. Finally economic metrics, e.g. average gas produced per well, unit cost, or NPV, are applied to the predicted production, and the development options are compared when the metrics are plotted against the total produced gas or well count.
Application of the workflow to an actual project evaluation demonstrated its robustness for the decision making process. The area of interest is about 100 km2 and contains several coal seams, which are proposed to be developed using surface to inseam, horizontal wells. Several well layouts with different spacing between lateral wells were evaluated using multiple subsurface realisations. Proposed wells in each development option were sorted by their median (P50) of predicted produced gas volume and their economic metrics plotted against the total produced gas. If the best wells are drilled first, the economic value of the project starts eroding after a certain number of wells are drilled. This happens because each new well delivers less gas while the cost of the well doesn't reduce at the same rate. The sweet spot is being exhausted. The cloud of well metrics as a function of the number of wells drilled or total gas produced provides an efficient tool for evaluating the optimal size of the project and its economic feasibility.
Due to relatively low permeability of the coal cleat system and large area of interest, the static model had to be split spatially and by seams with the model grid being refined for dynamic simulation. Automation of this workflow made it possible to evaluate multiple development options with multiple subsurface realisations within a tight project timeframe.
The workflow provides a structured framework for selecting economically feasible development options based on the pre-defined criteria while taking into account the subsurface complexity and uncertainty.
Since the first frac in 1954, around 250 of the 3000 exploration and production wells in the Netherlands have been hydraulically fractured. This study focusses on about 50 of the more recent fracs, of which sufficient production data, reservoir information and hydraulic fracture properties could be obtained for economic and data analysis.
For each well, the production history has been analyzed with a commercial rate transient analysis software package. About half of the wells have a pre-frac production history while the other half have been hydraulically fractured immediately after drilling. For wells with pre- and post-frac production data two history matched analytical models were made. Those models were subsequently used to create two production forecasts, to determine the incremental production profile and to calculate the economic value added by each frac. For wells without pre-frac production data the history matched post-frac model was used two create two production forecasts, one with and one without a hydraulic fracture in place.
The calculated economic values have been combined with reservoir properties (permeability, GIIP, stratigraphy, etc.) and frac data (proppant type, amount of fluid used, amount of proppant pumped, etc.), to form a dataset which was analyzed using a commercial data analysis tool to investigate perceived correlations.
The results show that practically all analyzed fracs resulted in a production improvement, and most of the fracs resulted in positive economic value added. However, some resulted in an economic grey area (below EUR 5 million incremental discounted cash flow), and one frac even resulted in a negative value.
Many reasons can be given for the distinction between economic and uneconomic projects. This paper shows that although multiple attributes influence the calculated economic value, some generic observations can be made. There is apparently no correlation between PI improvement, skin or kh and economic value. Remaining GIP is definitely important for economic value, but no generic correlation for reservoir pressure can be made. It was shown that wells often see more connected GIIP after fraccing. The results show that fracs in reservoirs with 80% depletion can still result in very economically beneficial projects, especially if the fracs increase the connected GIIP. Frac properties might very well be important for the determination of the economic value of fractures. However, no clear correlation between economic value and frac half length or proppant size could be found. On the other hand, the results show that larger amounts of (any) proppant pumped seem to lead to higher economic value. Last but not least, a relation between PI improvement and pre-frac skin was found.
The study presented is the first portfolio analysis of fracced conventional gas wells in The Netherlands. Input and methods have been checked and results have been shared with several experts outside our organization.