OIL AND GAS INDUSTRY AND CHALLENGES FROM CLIMATE CHANGE REGULATIONS
Domagoj Vulin1, Daria Karasalihović Sedlar2, Lucija Jukić3
1Faculty of Mining, Geology and Petroleum Engineering, Pierottijeva 6, Zagreb, tel.: 003851 5535 846,
2 Faculty of Mining, Geology and Petroleum Engineering Pierottijeva 6, Zagreb, tel.: 003851 55 35 829,
3 Faculty of Mining, Geology and Petroleum Engineering, Pierottijeva 6, Zagreb, tel.: 003851 5535 838,
Abstract
Oil companies are facing the problem of allowed carbon dioxide emissions because of high-energy consumption or gas flaring. Green (or greener) technology, in the case of oil and gas companies became one of the key parts of their business strategy, often by comprising (or by equalizing) energy sustainability with sustainability of a business.There are three main categories of air pollutants in upstream and downstream activities: fuel combustion, fugitive emissions and carbon dioxide separated at natural gas processing plants. In refineries, boilers in which fuels are oxidized, in order to generate heat for internal separate use, are major contributors to CO2 emission from fuel combustion. Fugitive emissions are mostly related to emissions of methane during oil production (flaring, leakage at seals in flanges, valves etc. or depressurizing releases during blow down in pressure vessels or oil production wells). Gas processing plants in Croatia are producing significant amount of CO2which after purification could be used for Enhanced Oil Recovery (EOR).In order to review the options for CO2 emission reduction during upstream (and part of mid-stream) operations it should be considered that burning 1 m3 of diesel will result in about 2.5 tonnes of CO2 and that flaring of 1 m3 of gas (at standard conditions) generates around 2 kg of CO2.Possible strategy that oil and gas companies can use to deal with challenges from climate change regulations was analyzed in this work. Additionally, results of case study of CO2 emissions for a different gas composition burned at flaring system in Croatia, and amounts of CO2 at gas processing plants that could be reduced were analyzed. Also, economic analysis with net present value of different technological investments was conducted.
Keywords: CO2 emission, gas flaring, pressure depletion, net present value
1.INTRODUCTION – SOURCES OF CO2
Among the largest CO2 sources in upstream part of oil and gas production process are natural gas processing facilities and flares.In Croatia oil is produced from 34 fields, condensate is primarily produced from eight gas-condensate fields, while natural gas is produced from 23 gas fields. Almost all perspective locations for oil production are in northern part of Croatia, i.e. Sava and Drava Depression. Domestic hydrocarbon production can cover more than 60 % of the domestic demand. The largest CO2point source from upstream activities is in Molve, where gas and condensate are processed for further transportation [1]. At oil production fields, there is prominent aspect of gas flaring as one of factors that are not contributing the image of oil and gas industry as environmentally-friendly.
1.1.CO2emissions and mitigation possibilities
Mitigation of greenhouse gas emissions can be achieved during upstream activities by (1) efficient gas separation from oil, (2) using natural gas for energy demand near hydrocarbon production facility (3) using natural gas for injection back to an oil reservoir to improve oil mobility i.e. for Enhanced Oil Recovery (EOR).
In this work focus was given to gas flaring near hydrocarbon production facilities. Natural gas processing plant Molve and ethane facility near Dugo Selo produce more than 6 500 t/year of CO2 by flaring. This flaring has not been considered for this work, as flaring is not constant through the year, i.e. the flares at these facilities are used for periodic burning of gas when some part of facilities works near blow-out pressure.
Large quantities of CO2 might be stored into regional aquifers in Croatia, which are marked on figure 1 [2].
Figure 1 Regional deep saline aquifers in Croatia [2]
The most recent assessment of aquifer storage capacity is published in Vulin et al. (2012) [3], estimating almost 1000 Mt of CO2 that could be stored in Sava Central aquifer during the whole period of injection. Such estimated amounts indicate that all CO2 produced in Croatia (including all CO2 from oil and gas production activities) can be injected and permanently stored into geological formations. However, such projects demand extensive research and investment into pilot project(s), and CO2 storage to aquifers considers large CO2 point sources. In other words, if CO2 capture at power plants and heating plants in Croatia will not be the option, storage capacity of one regional aquifer would be oversized for CO2 that could be captured in Croatia. On the other side, hydrodynamic properties of aquifer (e.g. permeability distribution, wettability, pore size distribution), thermodynamic and geochemical process of CO2-brine-rock interaction and techno-economical aspects of CO2 storage to aquifers might change interpretation of CO2 storage capacity, which also contributes to the fact that storage in such formations should be comprehensively studied and that the technology will not be available at least for several years at specific site in Croatia.
In this work the study of typical oil reservoir was conducted in terms of:
-Oil production decline through lifetime of a reservoir;
-Constant pressure decrease during oil production and consequently different oil and gas composition during separation at pressures below saturation (bubble point) pressure;
-Gas composition at different separation conditions at the surface;
-CO2 production by flaring the gas separated from different production and separation pressure-temperature (p-T) conditions;
-Economic parameters related to possible reduction of CO2 emission.
2.LABORATORY ANALYSIS OF FLUID FROM OIL FIELD
Assumption that gas separation from oil in an oil reservoir can be simulated in laboratory by differential liberation experiment proved to be good [4], [5]. In reservoir, when pressure decreases below saturation pressure, gas phase appears and gas liberation occurs until the end of production from a reservoir. During gas liberation, different molecules evaporate from oil. Oil and gas composition at each pressure below saturation pressure can be determined only by gas chromatography analysis of liberated gas in DL test (oil composition can be then calculated by material balance) or by cubic equation of state (EOS) which has to be tuned (to be proven as accurate) to simulate experiments conducted in the laboratory.
Gas to oil volumetric ratio, and compositions of oil and gas phase from DL experiment (performed at reservoir temperature) were input for further calculation of gas separation from production well to surface conditions (flash process).
For simulation of PVT (pressure-volume-temperature) experiments cubic equation of state is used together with vapor-liquid equilibria calculation (VLE). The approach of tuning EOS parameters includes a large number of iterations and numerical solutions, so it was convenient to use PVTi simulation software [6]. When accurate EOS for observed oil composition is available, input parameters for further calculation are production decline (changes of oil produced) and pressure decrease. These parameters are needed to calculate CO2 emitted at different (separation) conditions at the surface.
- CALCULATION RESULTS
In order to predict future oil production, atypical oil production of a relatively old and small field was taken and decline curve analysis was applied for this case. The main assumption is that the trend of a curve in the past will be present in the future and this assumption can be made considering well—known production history. Exponential decline was selected based on the production historybehavior, with annual decline rate of 15 %. Equation used for production forecast [7]:
(1)
where:
qo – oil production, m3/y
qoi – initial oil production, m3/y
D – decline rate 1/year
t – time, year
Gas production is calculated on the basis of a constant gas-oil-ratio which had been measured in the history of this field.
Another parameter needed for CO2 emission calculation is reservoir pressure, which can be estimated if reservoir drive mechanism is known. Figure 2shows a typical oil recovery (Np/N)-pressure (p) diagram for the case of an oil reservoir throughout the reservoir lifetime.In the beginning of the production, elastic drive mechanism (above bubble point) is present, and in some later time, solution drive mechanism and/or gas cap mechanism start to dominate. Although pressure curve would differ in case of water flooding and in case of a great gas cap, for purpose of this research, this typical pressure curve shape can be applied and pressure can be correlated for a specific case. First period (top left) on this curve can be approximated with a 3rd order polynomial since gas cap influence in minimal. Rest of the production period can be approximated with a 2nd order polynomial since pressure and production data are available.
Figure 2Change of reservoir pressure with increasing oil recovery
After the reservoir pressure is determined, flare gas composition can be simulated.Since the composition depends on the exit pressure, two different compositions are obtained, one for separation at 7 bar, which represents separator, and one for separation at 1 bar. This way emitted amounts of CO2 with and without separator can be compared.
First step is to determine carbon content of individual hydrocarbon compound on a mass percent basis:
(2)
where:
wCCi - carbon content of (hydrocarbon) component i (mass part of unit)
MC - molecular weight of carbon (MC=12 g/mol)
x - stoichiometric coefficient for carbon (number of carbon atoms in a molecule)
Mj - molecular weight of component
For plus fraction, stoichiometric coefficient (x) is determined by finding an alkane with the similar molecular weight.
Carbon content of the mixture can be calculated using next equation:
(3)
where:
Cc – carbon content of the mixture (mass part of unit)
wi – weight fraction of component i
The amount of CO2 produced by flaring can be calculated with:
(4)
where:
ECO2 - amount of produced CO2, kg
V – (flaring) gas volume, m3
MCO2 – molecular weight of carbon dioxide
zi – molar fraction of component i
Finally, for given case, oil and gas production, reservoir pressure and CO2 emissions were calculated and results are in table 1.
Table 1 Results of CO2 emission calculation
Np, m3 / Gp, m3 / pressure, bar / CO2 emission, twith separator / without separator
2016 / 2152 / 538 000 / 80 / 30 878 / 43 941
2017 / 1852 / 463 000 / 80 / 26 573 / 37 815
2018 / 1594 / 398 500 / 80 / 22 871 / 32 547
2019 / 1372 / 343 000 / 60 / 19 830 / 29 313
2020 / 1181 / 295 250 / 60 / 17 070 / 25 232
2021 / 1016 / 254 000 / 60 / 14 685 / 21 707
2022 / 875 / 218 750 / 60 / 12 647 / 18 694
2023 / 753 / 188 250 / 60 / 10 884 / 16 088
2024 / 648 / 162 000 / 60 / 9 366 / 13 845
2025 / 558 / 139 500 / 60 / 8 065 / 11 922
2026 / 480 / 120 000 / 60 / 6 938 / 10 255
- INVESTMENT CALCULATION
In this paper, two possible investment options were analysed witheconomic feasibility of separator installation. General goal of the analysis was to indicate investment possibilities of the separator introduction into the production system on hydrocarbon field production plant. The purpose of the project was to define decrease of the CO2 emissions and to calculate economic return of separator investment. The project defined the possible scenarios as the first - business as usual (without separator) and the second - do something else (with separator).The both analysed scenarios have the same technological prerequisite. Since both scenarios have the certain impact on the environment due to the CO2 emissions- external impact (ecological output), impact of the project on climate and vice versa have been analysed. For the total expenditures prediction investment costs, project management, documentation and the OPEX have been taken into account.The discount rate of 7.5% has been taken as relevant for the whole petroleum industry operating in production of hydrocarbons in Croatia. In cash flow the current CO2 emissions prices of 4.15 EUR per CO2 units have been taken for production period until the technical limit of production due to the pressure drop[8]. Also amortization have been calculated for the capital investment. Since project does not generate revenues, it was analysed from the negative expenditures point of view. Direct expenditures of production were analysed (material, personnel, maintenance) with presumption of financing from investors capital only (revenues, bank credit).Economic analysis has given the discounted sum of all costs through production period as analysed time horizon.All indicators were discounted. As a result, net present value - NPV was calculated as a sum of all present values of the project in the analysed time.
The economic analysis showed that the NPV was positive for the total investment starting from 15 % of emissions over emissions cap value. The financial internal rate of return – IRR, value that shows the rate according to which NPV is equal to 0 in analysed time frame,was calculated (Figure3).
Figure 3. Internal rate of return – production with separator
The IRR was above discount rate for the investment up to 14,5% of emissions over emissions cap value. Below that, IRR was below discount rate. Therefore, the project was analysed as commercially acceptable for wide range of emissions over the emission cap starting from 14.5%.
- CONCLUSION
The specific goal of the project was to define net benefits resulting from the capital investment into separator for decreasing CO2 emissions. In the primary phase, the initial physic indicators of the project like production quantities of natural gas, pressure, quantities of CO2 emissions through production time have been calculated. In the second phase, economic indicators have been calculated. These indicators could help measure the impact of the project (revenue, costs, NPV, IRR) which could influence to socio-economic variables (e.g. new working places, increase of GDP or total decrease of GHG emissions). The further investigation could include more data and could give total feasibility of the project by analysing costs and benefits not only for the investor, but also other socio-economic costs and benefits including the complete socio-economic context of the project. This would probably give the size of the increase of the benefits for the society. Local area was defined as targeted area, although the analysed area could be of much wider geographic context due to the fact that global emissions decrease is not directly related to specific area. For the detailed cost-benefit analysis, it would be necessary to quantify all the positive and negative direct and indirect impacts of the investment. Due to localized scope of the project, indirect impactswere excluded from this analysis.
The results of techno-economic analysis could be used as possible business strategy option for dealing with climate change challenges in the petroleum industry. The results showed that small changes in technological production flow like separator introduction could be net positive and applicable at the different hydrocarbon production facilities.
References:
[1] Ministry of Economy and Ministry of Construction and Physical Planning, 2013. Second National Energy Efficiency Action Plan for the Period until the End Of 2013
[2] EU Geocapacity, 2009. Assessing European capacity for geological storage of carbon dioxide. Technical reports, FP-518318: EU Geocapacity, 2007. Storage Capacities. WP2.3 D12; 2009.
[3] Vulin, D., Kurevija, T. and Kolenkovic, I., 2012. The effect of mechanical rock properties on CO 2 storage capacity, Energy, 45(1), pp.512-518.
[4] Standing, M.B.: Volumetric and Phase Behavior of Oil Field Hydrocarbon Systems, Millet Print Inc., Dallas (1977) 81.
[5] McCain, W.D. Jr.: The Properties of Petroleum Fluids, second edition, PennWell, Tulsa (1990) 283.
[6] Schlumberger, 2015 Eclipse Software - Acknowledgement to Schlumberger for opportunity to use software for scientific purposes
[7] Arps, J. J.: Analysis of Decline Curves, Trans. AIME 160, pp. 228-247
[8] Belektron Carbon Newsleter (2016): EUA Dec 16 – current CO2 unit prices (
NAFTNA I PLINSKA INDUSTRIJA I IZAZOVI KOJE POSTAVLJAJU PROPISI O KLIMATSKIM PROMJENAMA
Naftne kompanije se suočavaju s problemom dopuštenih emisija CO2 koje se javljaju kao posljedica intenzivne potrošnje energije ili spaljivanja plina na baklji. Zelena (zelenija) tehnika je u slučaju naftnih i plinskih kompanija postala ključnim dijelom poslovne strategije, gdje je često energetska održivost sadržana u održivosti djelatnosti.Tri su glavne skupine izvora zagađivača zraka u “upstream” i “downstream” aktivnostima: sagorijevanje goriva, emisije od odzračivanja ugljikovog dioksida odvojenog u postrojenjima za obradu prirodnog plina. U rafinerijama, bojleri u kojima goriva oksidiraju i stvaraju toplinu za internu potrošnju predstavljaju glavni izvor CO2 od izgaranja goriva. Emisije od odzračivanja se uglavnom odnose na emisije metana tijekom pridobivanja nafte (spaljivanje na baklji, curenje na brtvama, ventilima i slično). Postrojenja za obradu prirodnog plina u Hrvatskoj proizvode značajnu količinu CO2. Budući da se radi o pročišćenom CO2, može se upotrijebiti za utiskivanje u ležišta u sklopu tercijarnih metoda povećanja iscrpka (engl. EOR – Enhanced Oil Recovery).Kako bi se dao pregled mogućnosti za smanjenje emisija CO2 tijekom “upstream” (i dijela “mid-stream) aktivnosti, treba naglasiti kako spaljivanje 1 m3 dizela rezultira s oko 2,5 tone CO2, dok spaljivanje 1 m3prirodnog plina (pri standardnim uvjetima) proizvodi 2 kg CO2.U radu su analizirane strategije koje naftne i plinske kompanije mogu primijenitikako bi se nosile s izazovima koje donose propisi o klimatskim promjenama. Osim toga, prikazani su rezultati studije slučaja u kojoj su proučavane emisije CO2 za različite sastave plina spaljenog na bakljama te mogućnosti smanjenja količine emisija CO2 u postrojenjima za obradu prirodnog plina primjerice prilikom ugradnje separatora.