Estimate of Production Profiles from the Reservoir - Coursework Example

Title: ESTIMATE OF PRODUCTION PROFILES FROM THE RESERVOIR Name: Tutor: Institution: Date of Submission: TABLE OF CONTENTS TABLE OF CONTENTS 2 INTRODUCTION 3 ESTIMATION OF THE RESOURCES TECHNICALLY RECOVERABLE BY CO2-EOR 6 MISCIBLE CO2 DISPLACEMENT OPPORTUNITIES 7 IMMISCIBLE CO2 DISPLACEMENT OPPORTUNITIES 8 ESTIMATION OF THE MAXIMUM CO2 STORAGE POTENTIAL 10 MISCIBLE CO2 DISPLACEMENT PROJECTS 10 IMMISCIBLE CO2 DISPLACEMENT 12 INTRODUCTION Enhanced oil recovery using carbon dioxide (CO2-EOR) is a method that can increase oil production beyond what are typically achievable using conventional recovery methods, while facilitating the storage of carbon dioxide (CO2) in the oil reservoir. Although, traditional oil production can recover up to 35-45% of the original oil in place (OOIP), the application of an EOR technique, typically performed towards what is normally perceived to be the end of the life of an oilfield, may produce an additional 5-15% [1]. CO2-EOR involves the injection of CO2 at high pressure into an oil reservoir which mobilizes oil that has not been extracted using traditional methods [1]. Furthermore, a fraction of the injected CO2 remains stored underground, which is helpful in combating global climate change, since CO2 is a greenhouse gas [1]. In principle, when CO2 is injected in an oil reservoir, it mobilizes oil not extracted by conventional methods either by interacting physically and chemically with the oil and the reservoir rock, or by regulating the reservoir pressure [1]. This results in an increased oil production. Therefore, CO2-EOR helps in the reduction of CO2 emissions and simultaneously improves the security of energy supply. There are no major technical barriers for the implementation of this project in onshore. The urgent need to control the carbon dioxide emissions in compliance with the Kyoto commitments and beyond, makes its capture and storage technologies one of the carbon mitigation options worth considering [2]. Furthermore, the emissions trading scheme is expected to provide some financial incentives for this decarbonisation option. At the same time, higher oil prices may now justify investment in oil recovery projects, which were previously deemed uneconomic [2]. The profile of the enhanced oil recovery (EOR) projects must be based on data that are normally accessible through public records or other open sources [2]. The additional oil recovered or incremental profitability that results from an EOR project is a function of several physical properties that describe the reservoir prospect. Screening criteria that are applied simply to the basic reservoir properties will not be enough in identifying promising EOR prediction [1, 2]. Instead, it is necessary to combine the reservoir properties and the tertiary oil recovery mechanics in a predictive model to estimate a production profile for each project [2]. The main barrier to the further implementation of the technique is the economics of CO2 supply [1]. The technique is currently implemented only in regions where CO2 is available in large quantities and at a very low cost. In almost all of these cases, CO2 originates from underground natural reservoirs [1, 2]. The overall goal of CO2-EOR is to optimize fluid displacement in a porous space by injecting two gases, the first for miscibility and the second for immiscibility (CO2). Parameters and equations taken into considerations to simulate this mechanism involve: Darcy's law: A proportional relationship between the instantaneous discharge rate through a porous medium, the viscosity of the fluid and the pressure drop over a given distance. Derived from Darcy’s equation, the relative permeability is a dimensionless measure of the effective permeability of each phase in porous media [2]. This could be written as follow: The Buckley– Leverett equation: In our case, if we consider a 1-D control volume (for simplicity) with S(x,t) be the water saturation, the Buckley–Leverett equation can be written as follow: Where; f is the fractional flow rate, Q is the total flow, φ is porosity and A is area of the cross-section in the sample volume. The study would be performed using reservoir simulation software equipped with a phase behavior package (CMG).The model would be developed in a rectangular coordinate, and would involve a injection well and a production well. Parameters such as flow rate, pressure, porosity, permeability would be taken from existing data of either nitrogen injection or CO2 Injection. The concentration of the initial fluid (CO2) taken from experimental of either carbon injection would progressively decrease (100% to 0%) while the concentration of the second fluid would increase (0% to 100%). The model should predict for each ratio injected a specific production rate and the highest production rate would simply justify the targeted mixing ration [3]. ESTIMATION OF THE RESOURCES TECHNICALLY RECOVERABLE BY CO2-EOR CO2 projects are usually designed to either minimize CO2 utilization or to maximise CO2 storage [4]. In the absence of any economic benefits from geological storage of CO2, the buying cost of CO2 dominates, hence the objective is to buy as little CO2 as possible at the field and maximize the potential for CO2 recovery and recycling. This is the most likely approach to be adopted without benefits from emissions trading [2]. Based on this principle the CO2 quantities required can be calculated. The fields can be classified as miscible or immiscible projects and the estimation of the potential oil recovery is based on information on the present status of the fields [4]. The estimate of incremental oil production is based on previous experience, which indicates yields of 7% to 15% of the OOIP using CO2-EOR. However, there are lower estimates given for the North Sea placing incremental oil production between 3% and 7% of the OOIP due to the different conditions and the increased secondary recovery yield of the offshore fields in this area [2, 4]. The time frame for the implementation of the CO2-EOR projects is more medium than short term due to the fact that much of the technology is still unproven on large scale and offshore and a CO2 delivery infrastructure needs to be constructed before investments in this area can begin [2]. MISCIBLE CO2 DISPLACEMENT OPPORTUNITIES In a high oil recovery scenario on average, 9% of the Original Oil in Place (OOIP) is assumed to be recoverable during EOR, provided that the Minimum Miscibility Pressure (MMP) is exceeded. This is in accordance to the US experience [4]. In contrast, for a low oil recovery rate case, only 4% of the OOIP is recoverable, in line with the reservoir modeling exercises performed in North Sea reservoirs [4]. Furthermore, efficient CO2 displacement projects designed to maximise incremental oil recovery typically requires 0.33 tonnes CO2 to provide an incremental barrel of oil, which is also the value adopted for the calculations regardless of the incremental oil recovery rate assumed [3]. The CO2 required for a miscible CO2-EOR project can be calculated as follows: The Original Oil in Place (OOIP) is multiplied by the estimated recovery factor during CO2-EOR (herein assumed 9% and 4% for the two respective cases). The resulting estimation of incremental oil production in barrels is multiplied by the CO2 requirement estimate per barrel (herein assumed 0.33 tonnes CO2 per barrel of incremental oil produced). Conversion from tonnes of oil to oil barrels, where necessary, is done by assuming 7.5 barrels to the tonnes [3-4]. CO2Required= OOIP [M bbl] x 0.09 (or 0.04) x 0.33 [t CO2/ bbl] A project is considered urgent when the oilfield is over 80% depleted with regards to the estimated recoverable oil reserves at the projected end of secondary recovery (based on 2003 production data) [4]. The increasing number of miscible displacement projects has generated significant experience and has provided valuable insights into the underlying physical and chemical mechanisms for oil recovery [3]. However, detailed data about the operating conditions and the performance of individual projects are not publicly available. For instance, in UK the total miscible displacement potential is assessed, on the basis of a 9% incremental recovery rate, to be approximately 2300 million barrels of incremental oil, which is 35% of the remaining proven and probable oil reserves (December 2003 estimate). A high proportion of these fields are currently in the late stages of secondary recovery [5]. If a low recovery rate of 4% is assumed then the estimate drops to approximately 1000 million barrels or the equivalent of 15% of the proven and probable remaining oil reserves [5]. IMMISCIBLE CO2 DISPLACEMENT OPPORTUNITIES Suitable fields have typically not been subject to extensive secondary water flooding and contain a gas cap or significant quantities of associated gas. For pressure maintenance using immiscible displacement, it is assumed that the volume occupied by oil and gas in the reservoir, extracted during water flooding is replaced by CO2 until the original reservoir pressure is restored. This is likely to exceed the MMP in some fields, and there may be scope for reducing the pressure and associated CO2 requirement to improve the economics of a project. The volume to be replaced refers to oil extracted before EOR and therefore the CO2 requirement is independent of the incremental recovery rate assumed. The CO2-EOR potential and the required CO2 can be calculated as follows: The Original Oil in Place (OOIP) is multiplied by the estimated recovery factor during CO2-EOR (herein assumed to be 18% and 10% for the two cases). Then the CO2 required is calculated from the oil and gas quantities produced after taking into account the reservoir conditions, assuming that a unit volume of CO2 physically replaces a unit volume of oil or gas [4-5]. EOR potential [M bbl] = OOIP [M bbl] x 0.18 (or 0.1) CO2 required to replace oil [Mt] = Voil [M m3] x CO2 density [t/m3] x FVF CO2 required to replace gas [Mt] = Vgas [M m3] x CO2 density [t/m3] / GEF CO2 total = CO2 required to replace oil + CO2 required to replace gas Where: Voil is the volume of oil produced after secondary recovery Vgas is volume of gas produced after secondary recovery CO2 density is at initial reservoir conditions FVF is the oil Formation Volume Factor i.e. the volume of oil at reservoir temperatures and pressures, divided by the volume of oil at surface conditions. This is used to correct volumes at the surface to volumes at reservoir conditions GEF is the Gas Expansion Factor i.e. the volume of natural gas at surface conditions, divided by the volume of natural gas at reservoir temperatures and pressures. This is used to correct gas volumes at the surface to volumes at reservoir conditions [5]. Immiscible displacement projects would generally require a higher amount of injected CO2 per incremental barrel of oil produced, typically two to three times more [5]. However, values may vary significantly between different fields. Heavy oilfields with atmospheric pressure injection (API) of less than 22 degrees are not ideally suited to EOR with CO2 injection. Smaller fields with oil reserves estimated at less than 10 million tonnes (75 million Barrels) each is less suited to investment in CO2-EOR due to the limited potential for recovery of incremental oil [5]. This would make the field operation not profitable as a stand-alone project taking into account that the investment required is substantial [5]. However, a lot of the smaller fields could be profitable as satellite projects if they are in the vicinity of a large CO2-EOR operation due to economy of scale [5]. ESTIMATION OF THE MAXIMUM CO2 STORAGE POTENTIAL MISCIBLE CO2 DISPLACEMENT PROJECTS The most significant cost of CO2-EOR is that of CO2 supply at the oilfield. In the absence of financial incentives for CO2 storage, e.g. via emissions trading, the commercial incentive is to minimize the imports and hence the cost of CO2 by recovering as much as possible from the injected CO2 and recycling it in the reservoir [4]. In this case the storage capacity for miscible displacement projects would be much greater than assessed in the previous sections. Ways to increase CO2 storage in oil recovery include [4]. redesigning the wells to create favorable injection profiles optimizing water injection towards maximizing gas storage considering injection to aquifers underlying the oil fields (for the recycled gas or to increase storage capacity) re-pressurizing the reservoir after the end of oil production by continuing injection Recent research claims that a well controlled process, where wells are shut in according to a gas-to-oil production ratio limit to avoid excess gas circulation, as the best way to obtain both maximum oil recovery and CO2 storage at the same time [1]. However, another recent paper referring to fields of the UKCS (UK Continental Shelf) reports that shutting off wells on gas breakthrough had limited effect in maximizing CO2 storage. Continuous gas injection or optimized WAG schemes were found to be more effective. In all cases there was significant trade-off in the oil production and consequently in the economic value of the projects when the aim of maximum CO2 storage was pursued, unless a low oil price and high CO2 storage credit scenario is assumed [2-4]. For WAG injection, designed for efficient CO2 utilization, typical amounts of CO2 that can be stored at the end of EOR are around 2.5 times the reservoir volume of the incremental oil produced. Given an EOR recovery of 9% of the OOIP for miscible CO2 injection, this equates to a CO2 storage volume of around 23% of the OOIP. This is lower than the average oil recovery factor of around 45-50% that is typically achieved after secondary recovery [5]. Greater CO2 volumes could be potentially stored if the floods were designed to maximise CO2 storage. The objective would be to replace all the oil that had been produced by CO2. Hence, if the project was designed to maximise CO2 storage, a far higher reservoir volume of the initial oil and gas reserves can be utilized. This could be achieved by using a far higher proportion of CO2 to water, or pure CO2 in the injection process [3]. The high level of storage is achieved through all the incremental oil being replaced by CO2, together with the net water saturation of the reservoir being significantly reduced as it is replaced by CO2 [4]. The methodology adopted here is to assume that the volume available for CO2 storage equates to the volume occupied by the initial oil and gas reserves that had been produced after secondary recovery by water injection. The gas is assumed to have been initially present as a gas cap. In comparison to the CO2 requirement for efficient WAG assessed previously, this will usually give a higher limit to the CO2 storage potential of the field. Exceptions are fields with poor recovery factors and no gas cap present [5]. The storage volume is calculated by adding the components relating to the storage volume occupied by the initial oil reserves and the gas cap. V CO2 oil component [Mm3] = Volume of Produced Oil [Mm3] x FVF V CO2 gas component [Mm3] = Volume of Produced Gas [Mm3] /GEF CO2 [Mt] = (VCO2 oil component + VCO2 gas component) [Mm3] x CO2 density [t/m3] Where, the volume of produced oil and gas is at standard temperature and pressure conditions of 0°C and 1atm. IMMISCIBLE CO2 DISPLACEMENT For oil fields that are under-pressurized following secondary recovery, the assumption is that the reservoir is restored to the initial reservoir pressure following CO2 storage, the volume once occupied by oil and gas being replaced by CO2 [5]. ESTIMATION OF THE CO2 AVOIDED The process of capturing, transporting and injecting CO2 for EOR requires energy input and results in CO2 emissions. Since these are all caused by the CO2 storage process, they have to be taken into account in order to calculate the amount actually avoided from emission to the atmosphere [4-5]. An estimate of the CO2 avoided is represented as a percentage of the amount captured for the process of electricity generation by each type of plant when coupled with carbon capture [5]. Due to reduced power plant efficiency, compared to the option without CO2 capture, the CO2 avoided is 72% and 86% of the volume available for storage (at the pipeline entrance) for coal and natural gas power plants respectively [6]. The CO2 emittance of the plant is used to calculate the CO2 emission attributed to the electricity consumption necessary for the pipeline transport [6]. CO2 emissions for the injection and recycling of the gas during the EOR operation can be estimated by adopting an emission factor. The value of 0.048 tonnes of CO2 per incremental barrel of oil produced is derived from literature [6] to account for fugitive emissions, flaring and auxiliary processes. This is an emission factor specific to extra processes related to EOR and does not refer to generic oil production. While there are emissions from the general operation of the oil field these are not taken into account in this balance. The reasoning behind this is that the incremental oil produced because of the EOR operation will be replacing oil extracted by some other method [6]. Therefore these are emissions that would have occurred anyway through oil production. For the sake of simplicity it is assumed that the incremental oil production replaces oil produced in the North Sea, with comparable CO2 emissions during the extraction process. It is calculated that in the case of miscible projects about 58% of the CO2 delivered at the sink (minimum CO2 requirement) can be considered as CO2 avoided from emission to the atmosphere. For immiscible projects the figure varies from 57% to 61%. The costs and cash flows produced by the economic evaluation are normalised to the calculated amount of CO2 avoided [5-6]. This is a very simple balancing of the CO2 flows involved in the systems. It does not include all the associated processes or particular aspects of each project and assumes no further interactions beyond the system boundaries [6]. To gain a better insight of the CO2 balance, more detailed studies of the individual project systems should be performed in terms of life cycle assessment of the energy use and emissions throughout their operation, taking into consideration the specific characteristics of each project [6]. Petroleum flooding by non-hydrocarbon gases is a relatively cheap process with appreciable potential to apply in the reservoirs. Injection of non-hydrocarbon gases, especially carbon dioxide, has found noticeable attractions during the last years. High minimum miscibility pressure of this gas has limited its applicability in the reservoirs with medium depths. Reservoirs containing high and medium gravity oils are good candidates to apply miscible carbon dioxide flooding. Carbon dioxide alternate water injection has been recommended to reduce unfavorable effects of relative permeability of carbon dioxide and oil. Reservoir heterogeneity is also another parameter, which determines the suitability of a reservoir for CO2 flooding [7]. Water-flood history, geology, logs, and well transient tests are indications of reservoir heterogeneity, which should be considered. Economic factors determine the minimum oil saturation, which accepted for CO2 flooding. As a rough guideline, oil saturation should not be less than about 20% PV in those portions of the reservoir that will be swept miscibly [6-7]. Work (s) Cited 1. Cakici, A R and M D Kovscek. "Geologic storage of carbon dioxide and enhanced oil recovery. II. Cooptimization of storage and recovery." Energy Conversion and Management (2005): 56(11-12): 1941-1956. 2. MacDonald, R.C., INTERA Technologies Inc. and J.E., INTERA Technologies Inc. Campbell. "Valuation of Supplemental and Enhanced Oil Recovery Projects With Risk Analysis." Journal of Petroleum Technology: 38; 1 (1986): 57-69. 3. Craus, S R. "Exploration, Drilling and Production of Oil and Natural Gas." Encyclopedia of Occupational Health and Safety, 4th Edition, International Labour Office, Geneva 1998. 4. Jessen, K. and A. R and Orr, F.M. Kovscek. "Increasing CO2 storage in oil recovery." Energy Conversion and Management (2005): 46(2): 293-311 5. E. Balbinski, M. Goodfield, T. Jayasekera and Claire Woods. "Potential for Geological Storage and EOR from CO Injection into UKCS Oilfields,." IEA EOR symposium. London: http://www.og-mrp.com/dissemination/d-rep-IEA03.html, 2003. 10-15. —. "Potential for Geological Storage and EOR from CO Injection into UKCS Oilfields,." IEA EOR symposium. 2003. 6. A.-C. Aycaguer, M. Lev-On, and A. M. Winer. "Reducing Carbon Dioxide Emissions with enhanced Oil Recovery Projects: A Life Cycle Assessment Approach." Energy & Fuels (2001): 15: 303-308. 7. International, Energy Agency, R & D Programme. Transmission of CO2 and Energy. Report PH4/6. Cheltenham: International Energy Agency, 2002: 58-72. 8. Moritis, G. " “EOR Continues to Unlock the Oil Resources”,." Oil & Gas Journal (2004): 45-52. Read More