First-Principles Performance Verification of Gas-Solar Thermal Projects for Enhanced Oil Recovery

2. Introduction

2.1. Importance of Sustainability for Oman

Recent studies show that the Sultanate of Oman is witnessing a verified trend of climate change, expressed as a steady increase in temperature at a rate of approximately 0.03 °C/year [10,11,12]. Hotter air can carry more moisture content, in accordance with the thermodynamic Clausius-Clapeyron relationship when applied to two-phase systems [13,14,15]. Therefore, this thermal anomaly can lead to interruptions in the natural hydrological cycle, reflected in heavy rainfalls and more frequent floods in Oman [16,17,18]. An example of the precipitation anomaly can be the exceptional April 2024 rainstorm accompanied by hail showers, heavy precipitation, and flash flooding that occurred in Oman and its neighboring country United Arab Emirates (UAE) [19,20].

Limiting the climate anomalies stems from curbing greenhouse gas (GHG) emissions [21], particularly carbon dioxide (CO₂) [22,23,24] through shifting from traditional practices in engineering and businesses to sustainable ones. Examples of such sustainability shifts [25] include phasing out systems and processes that rely heavily on burning fossil fuels [26,27], using electric propulsion (e-mobility) [28] in transportation [29,30,31], deploying green buildings that consume a small amount of energy [32,33], investing in green (zero-emissions) hydrogen and its derivatives [34,35,36], investing in blue (low-emissions) hydrogen and its derivatives [37,38,39], exploring new high-performance power generation technologies [40,41,42], and encouraging the adoption of carbon capture technologies [43,44].

According to the International Energy Agency (IEA), the domestic energy production in Oman in 2022 was distributed as 59.3% crude oil (2,230,003 TJ), 40.6% natural gas (1,525,393 TJ), and 0.1% wind and solar energy (3,863 TJ) [45,46,47,48]. The term “domestic energy production” or (DEP) refers to all energy production (such as extracted fossil fuels), which can be used as fuels or burned to generate electricity [49], as well as energy produced by local nuclear reactors (not applicable in Oman) and renewable energy sources such as wind [50] and solar photovoltaic systems [51]. In terms of the Omani total energy supply (TES) profile in 2022; natural gas contributed the dominant share of 88.1% (1,023,964 TJ), while crude oil contributed a small share of 11.5% (134,165 TJ), and wind/solar energy contributed a marginal share of only 0.3% (3,863 TJ). The term “total energy supply” or (TES) refers to the result of subtracting all the energy that is exported outside a country or stored without immediate usage in that country from all the energy produced in that country or imported to it. In other words, the total energy supply (TES) represents the sum of all forms of energy that are needed to supply end users in the country [52,53]. Some of the energy sources involved in computing TES are used directly, whereas most of them are transformed into fuels or electricity for final consumption [54]. For the same year of 2022, electricity production in Oman depended on natural gas with a percentage of 94.7% (40,508 GWh), on crude oil with a percentage of 2.8% (1,190 GWh), and on the wind and solar photovoltaic systems with a percentage of 2.5% (1,073 GWh). In terms of the total final energy consumption (TFC) in Oman for 2022, natural gas represented 56.6% (600,340 TJ), oil products represented 31.1% (330,230 TJ), and electricity represented 12.3% (130,243 TJ). These energy mix figures are summarized in Table 1. They show the heavy penetration of fossil fuels in the Omani economy despite the abundance of clean energy resources [55,56,57]. This is a practice that the country aims to bring to a halt by 2050 [58]. This progress in sustainability and energy transition in Oman is aligned with progress in other domains [59,60,61], such as education [62,63,64] and urbanization [65], according to the Oman Vision 2040 [66,67,68].

2.2. Enclosed Solar Enhanced Oil Recovery (ESEOR)

One of the practices that is in need of sustainable transitioning in Oman is thermal enhanced oil recovery (TEOR), which is based on using steam. It is of special importance in Oman and similar oil-producing countries. In the current study, we present a case study of sustainable transitioning of the EOR in an oil field in Oman called “Amal” or “Amal West” [69,70]. In the original EOR process, natural gas was burned as the single source of heat energy to boil liquid water and convert it into hot steam suitable for underground injection to heat the crude oil and its surrounding rock layers, rendering this crude oil less viscous and thus possible to extract. The modified EOR process utilizes collected solar radiation for clean steam generation, while still using natural gas for night operation. The current study provides an informative description of this hybrid EOR process, which is established by the company GlassPoint (or GlassPoint Solar) [71,72] for the company Petroleum Development Oman (PDO), which owns and operates that oil field [73,74,75].

GlassPoint is a private start-up business that started in 2009. It was funded by venture capital. The company specializes in designing and manufacturing solar steam generation units. The company went bankrupt and was liquidated in May 2020 in light of a challenging business environment related to low and unpredictable prices of oil and gas. However, the company restarted in June 2022 with a contract to build a gigawatt-scale solar steam project in Saudi Arabia for green aluminum production, where the solar steam is to be used this time for refining bauxite ore into alumina rather than thermal enhanced oil recovery [76].

Thermal steam-injection enhanced oil recovery (TEOR) requires supplying a large amount of heat to generate the hot steam. For example, recent computer modeling considered injecting superheated steam at 800 °F (426.67 °C) into the reservoir of heavy crude oil [77]. That modeling work reported that heating the reservoir from 100 °F (37.78 °C) [78,79] to 823.5 °F (439.72 °C) results in a big drop in the heavy oil viscosity from 9.940 Pa.s to 2.697 Pa.s, which improves the fluidity of the oil. To help realize the huge heat consumed in, we consider as an example a cubic foundation zone with a side length ($L$) of 100 m, which is to be heated by a reasonable temperature rise ($\mathsf{\Delta }T$) of 250 °C [80]. If the reservoir bulk (apparent) density (${\rho }_r$) [81] is taken as 2,400 kg/m³ [82], and its specific heat capacity ($C_r$) is taken as 800 J/kg.K [83], and the volume is estimated as the cube of a reference characteristic length ($L$); then the thermal energy ($Q$) needed to raise the temperature of this reservoir zone is

$$Q={\rho }_r{L}^3{C}_r\Delta T$$

(1)

The above equation gives 480 × 10¹² J or 480 TJ. This is equivalent to 133.3 GWh, which is enormous. It is equivalent to the electricity consumed if a large load of 15.22 MW; roughly as if 6,000 big residential air conditioning units are working simultaneously [84,85,86,87,88]; is kept running continuously over one full year (365 days or 8,760 hours).

In the solar enhanced oil recovery (SEOR) technique for the three Omani projects, parabolic trough mirror concentrators are used to collect and focus the incoming solar radiation for industrial heating, rather than for electricity generation [89,90,91]. Liquid water is heated and partly boiled to produce a two-phase liquid-vapor mixture “wet steam” with a quality of 80% [92] (a mixture of 80% water vapor and 20% liquid droplets) [93,94], at an absolute pressure [95] of about 100 bar (1,450 psi or 10 MPa) [96,97] and a saturation temperature of about 310 °C (583.15 K) [98]. This solar-generated steam is used to operate SEOR. The thermodynamic properties of steam at 100 bar absolute pressure are shown in Table 2 [99,100,101].

For the three Omani projects covered here, the solar troughs are rotatable with one degree of freedom (DOF) to track the solar radiation [105,106], and they are placed in a greenhouse-like structure for protection from environmental disturbances and aerodynamic wakes [107,108,109], as well as to ease automated daily cleaning. This design leads to an enclosed solar enhanced oil recovery (ESEOR).

In enhanced oil recovery (EOR), unexploited crude oil (petroleum) in underground wells is pumped up with the aid of special oil production methods to reduce the flowing resistance of this oil and improve its extraction from the underground formation [110]. These special production methods for enhanced oil recovery (EOR) include injecting hot steam into the reservoir [111,112,113,114], thereby lowering the viscosity of the heavy viscous oil [115] (thermal thinning process), thus improving its ability to flow through the reservoir, or injecting a compressible miscible gas (such as carbon dioxide, CO₂) [116] through an injection well [117], and this external gas dissolves in the underground oil, thereby reducing its viscosity (miscible displacement process) [118] and improving its mobility [119,120].

The oil recovery stage that precedes EOR is called (secondary recovery) [121,122], which is, in turn, preceded by the initial stage of production that is called (primary recovery) [123,124]. In the first stage of crude oil recovery (namely, the primary recovery stage), the crude oil is naturally extracted under the initially high well pressure. During the primary recovery stage, it is possible to utilize mechanical pumping (mechanical lift process) using beam pumps (pump jacks) [125] or electric submersible pumps (ESP) [126], or inject an immiscible gas into the production tubing (gas lift process) [127] to artificially increase the well pressure [128]. This technique and system to boost the well pressure (head) for oil production during the primary recovery stage, if necessary, is referred to as (artificial lift) [129,130] or (AL) [131,132]. In the second stage of oil recovery (namely, the secondary recovery stage, taking place after the primary recovery stage, when the well pressure declines despite the artificial lift), the well is either flooded with incompressible liquid water (waterflooding process), such as by pumping seawater or brackish water, or a gas is injected (gas injection process) [133] into the gas cap [134], which is the accumulated gaseous zone at the upper part of the reservoir [135]. Either of these processes has the primary goal of maintaining the reservoir pressure [136,137], such that the oil production level remains high enough to render it economical.

A newly introduced term (assisted oil recovery) or (AOR) [138]can be used to refer to a condition where artificial lift is used during the primary oil recovery.

The amount of oil that can be recovered during each of the three production stages depends on the properties of the crude oil itself. For heavy oils, EOR is responsible for a large portion of the oil that can be produced from an oil field, as high as 90% of the original oil-in-place (OOIP) or oil-initially-in-place (OIIP), while only about 5% can be produced in either the first stage or the second stage [139]. On the other hand, for light oils, about 25% of the produced oil can be accomplished during either the first or second stage, with the remaining 50% accomplished during the third stage, which is the EOR stage [140].

Heavy oils can be defined as those having an American Petroleum Institute gravity degree (°API) below 22.3° [141,142], which corresponds to a specific gravity (SG) above 0.92 or a density ($\rho$) above 920 kg/m³. Heavy crude oils not only have relatively high densities, but also have high sulfur contents (an undesirable property) and high viscosities, causing resistance to flow (another undesirable property). Light oils can be defined as those having an °API > 31.1° [143,144] (SG < 0.87 or $\rho$ < 870 kg/m³), and they are commercially desirable, due to the low sulfur content (making them easier to refine) and the low viscosities (making them easy to extract from the underground well) [145,146].

The API gravity degree is related to the specific gravity (SG) and the density ($\rho$) by the following nonlinear relationship [147]:

$$\rho ={\displaystyle \frac{\mathrm{141,500}}{°API+131.5}}=\mathrm{1,000}SG$$

(2)

Figure 1 illustrates graphically the relationship between either density ($\mathsf{\rho }$) or the specific gravity (SG) and the American Petroleum Institute gravity degree (°API) over a range of °API between 10 and 50. This is wide enough to cover a large number of possible crude oils [148,149]. A quadratic regression model is also shown in the figure, which approximates the exact expression in the above equation well.

The enclosed solar enhanced oil recovery (ESEOR) concept was implemented at either a pilot scale or a commercial scale for the first time in Oman at the Amal oil field. It is worth mentioning that a smaller test-scale or proof-of-concept (POC) unit was installed earlier in February 2011 in McKittrick, California, USA [150] (with a peak thermal capacity of 0.3 MWth or 300 kWth). Technically speaking, the McKittrick project of the GlassPoint company in California was the world’s first enclosed solar enhanced oil recovery (ESEOR) project. However, the Miraah project in Oman is the world’s first commercial-scale ESEOR project. Also, small scale, experimental scope, and limited monitoring records of the McKittrick project in California make it of secondary importance compared to the three subsequent ESEOR projects in Oman. Therefore, the current study can be of interest to readers and researchers working in the areas of enhanced oil recovery (EOR) and seeking information about this novel technology. The current study can attract the general interest of those working in solar thermal systems, solar heat for industrial processes (SHIP), and sustainability in the oil industry.

3. Research Methodology

3.1. Objectives and Contributions

The contributions of the current study to the literature of enhanced oil recovery, steam applications, solar heat for industrial processes (SHIP), and sustainable engineering practices include:

• Providing an example (a case study) of sustainable business operation in the oil industry. The current study is considered unique in terms of the provided independent technical and performance analysis of successful and flagship projects of enclosed solar enhanced oil recovery (ESEOR).
• Contrasting the three enclosed solar enhanced oil recovery (ESEOR) project designs in Oman, to derive best practices.
• Validating public data against first-principles models in a simple and reproducible way. Such validated data include avoided emissions of carbon dioxide (CO₂).
• Discussing general aspects and challenges of solar enhanced oil recovery (SEOR).

3.2. Approach and Data Sources

The research framework adopted in the current study is a case study analysis method, guided by qualitative and quantitative processing of secondary data. Supporting information was selected, cross-validated, organized, and presented such that it facilitates achieving the stated objectives of the current study.

Most of the data accessed about the three presented enclosed solar enhanced oil recovery (ESEOR) projects in Oman were made publicly available. The sources of these data can be categorized into three types as follows [151,152]:

(1)

The GlassPoint website.

(2)

Research publications by GlassPoint staff.

(3)

Personal communications with GlassPoint staff, through which further proprietary information was obtained.

4. Results and Discussions

The current section is dedicated to presenting our summary of the geometric and operational configurations for the three GlassPoint enclosed solar enhanced oil recovery (ESEOR) projects in Oman. All of them are geographically located in the same zone of the Amal oil field, which is an offshore petroleum reservoir in the southern part of Oman. These three projects are: Amal I (pilot scale), Amal II (pilot scale), and Miraah (commercial scale). The current section is divided into three subsections. In the first subsection, we provide a tabular comparison between the three ESEOR projects. In the second subsection, we provide graphical illustrations related to the ESEOR concept of GlassPoint. In the third subsection, we present photographs that help in depicting the real view of the three ESEOR projects in the field. In the fourth subsection, we discuss some aspects of operating the ESEOR projects. The attribution is properly made in the caption of each figure.

4.1. The Choice of Parabolic Trough Collectors

We start the results section by justifying the choice of parabolic trough collectors (PTC) as the solar heat collection design for all three GlassPoint enclosed solar enhanced oil recovery (ESEOR) projects in Oman. There are other options for solar heat collection, such as the linear Fresnel reflectors (LFR), the parabolic dish collector (PDC), and the solar tower. However, the parabolic trough collector (PTC) design has multiple attractive features, which are:

• Adequate temperature rise: Parabolic trough collectors can provide a broad range of high temperature rises (150–400 °C) [153,154,155,156,157], making them very suitable for solar steam generation.
• Maturity: Parabolic trough collectors are a very reliable technology that has been proven to be successful for many years, including large commercial-scale plants operating with stable conditions and low technological risks. A good example is the Mojave Solar project is a 250-megawatt solar electric generating facility (280 MW gross) in California, USA [158,159]. This commercial-scale PTC power plant has been operational for more than a decade (commissioned at the beginning of December 2014) [160].
• Modularity: Parabolic trough collectors are very scalable. They can be installed under a wide range of thermal capacities, ranging from a few kilowatts to hundreds of megawatts [161]. This makes them attractive for a diverse spectrum of industrial applications, including solar enhanced oil recovery.
• Simple construction: Parabolic trough collectors can be viewed as composed primarily of repetitive components (mirrors and receiver tube) and common materials (steel and glass) [162]. No large construction is needed (as in the case of the solar towers or the linear Fresnel reflectors). Also, the one-dimensional solar tracking in the case of parabolic trough collectors [163] tends to be easier to maintain and install than the two-dimensional (two-angles) solar tracking in the case of parabolic dish collectors or the heliostats of a solar tower.
• Low cost: The structural simplicity and the maturity of parabolic trough collectors make them one of the lowest-cost solar options [164].
• Structural strength: The lack of high-rise structures and the layout in the form of parallel rows of reflective mirrors in parabolic trough collectors provides intrinsic structural strength [165,166,167] and suppresses airflow-induced vibrations [168,169].
• Effective land use: Compared to linear Fresnel reflectors (LFR) and solar towers, parabolic trough collectors (PTC) can permit better utilization of the available land area for the same power capacity.

It is useful to add here that in 2024, the largest investment for solar heat for industrial processes (SHIP) systems globally was for parabolic trough collectors (PTC), with a share of 66% in terms of the collector area or the equivalent thermal capacity [170].

Also, the superiority and dependability of the parabolic trough collectors (PTC) design is evidenced in selecting that design for building the world’s largest solar steam generation project (1,500 MWth peak capacity and a solar field area of 6 km²) [171]. It is under construction in Saudi Arabia. The application sector is mining (aluminum production) [172,173] rather than the oil sector.

4.2. Contrasting the Three Enclosed Solar EOR Projects

In Table 3, we compare 15 characteristics for the three Omani ESEOR projects by GlassPoint Solar, and we also provide external references for additional information.

In addition, the receiver tube of the parabolic troughs is made of carbon steel, with all-welded construction and long-radius (less pressure loss) bends. It has an internal diameter of 48 mm and an external diameter of 60 mm. Also, solar steam is produced using a once-through steam generator (OTSG) system.

Computer ray trace modeling was used to inspect the optical behavior of the closely-packed parabolic trough collector mirrors in response to the changing sun position [174,175,176].

It can be noticed that the large scale Miraah project was built closer to the earlier Amal I project rather than the subsequent Amal II project (for example; by having gable roofs in both cases, adopting the same aperture size, and using unevacuated receiver tubes). The adopted flat roof glass in Amal I and Miraah is favored due to simplicity and lower cost compared to the curved glass roof in Amal II [177,178]. Similarly, the attempted evacuated tube (vacuum tube) design in Amal II is not repeated in the Miraah project (and was not implemented in Amal I). Such tube evacuation improves the performance through vacuum insulation that suppresses heat loss [179,180], but it implies a cost and installation penalty due to the incurred complexity.

The above results of the reduced natural gas consumption are aligned with a reduction of about 25% of the original system. Thus, the capacity factor (CF), or the ratio of actual output heat compared to the theoretical output heat assuming continuous operation at the peak rated power [187,188], of the enclosed solar enhanced oil recovery (ESEOR) design is about 25%. This can be justified by the absence of solar radiation at night, and the weakened absorbed radiation outside the solar noon time, partly due to self-shading [189,190] and partly due to gradually weakened direct normal irradiance (DNI) [191,192]. It is useful to add here that such a low capacity factor is usual for solar systems [193,194,195].

Summing the amount of annually avoided natural gas consumption gives the following figures in Table 4.

Similarly, the summed annual avoided carbon dioxide emissions from the three ESEOR projects are 105,593 tonnes/year.

4.3. Thermal and Emissions Validation Model

To validate the heat and CO₂ emissions values reported in the previous subsection (as reported by third-party sources), we provide here a simple thermal and emissions validation model [196]to verify these values in terms of their magnitude. We found that these values are acceptable as explained below.

The latent heat of vaporization or enthalpy of vaporization (the energy needed to convert 1 kg of saturated liquid water to saturated water vapor) at this pressure is 1,317.1 kJ/kg(water) or 0.36586 kWh/kg(water). Sensibly heating water from ambient temperatures to 310 °C requires an additional specific heat of about 1,425.4 kJ/kg(water) or 0.39594 kWh/kg(water). Summing both types of heats gives 2,742.5 kJ/kg, 0.76180 kWh/kg(water), or 2.5993 MMBtu/tonne(water).

Therefore, producing 1 tonne of steam daily during one year (365 days) requires a heat of about 948.7445 MMBtu or 1,000.98 GJ. Producing 50 tonnes of steam daily during one year (365 days) requires a heat of about 47,437 MMBtu or 50,049 GJ. This estimated quantity is identical to the GlassPoint-reported value of 47,437 MMBtu/year for either the Amal I pilot project or the Amal II pilot project, as shown in Table 3. Producing 2,000 tonnes of steam daily during one year (365 days) requires a heat of about 1,897,489 MMBtu or 2,001,960 GJ. This estimated quantity is very close to the GlassPoint-reported value of 1,897,461 MMBtu/year for the Miraah full-scale project, as shown in Table 3.

Because natural gas has a lower heating value (LHV) of approximately 0.035 MMBtu/Nm³ (0.03693 GJ/Nm³ or 10⁶ MMBtu/Bcf), producing 1 tonne of steam daily during one year (365 days) requires burning about 27,106 Nm³ (0.027106 MNm³ or 0.0009487445 Bcf) of natural gas. Producing 50 tonnes of steam daily during one year (365 days) requires a heat of about 1.3553 million Nm³ (1,355,300 Nm³ or 0.047437 Bcf) of natural gas. Producing 2,000 tonnes of steam daily during one year (365 days) requires a heat of about 54.212 million Nm³ (54,212,000 Nm³ or 1.897 Bcf) of natural gas.

The reasonable and equivalent carbon dioxide emission factors for natural gas [197] of 52.9996 kg(CO₂)/MMBtu, 185,253 kg(CO₂)/GWh, 185.253 kg(CO₂)/MWh, 0.185253 kg(CO₂)/kWh, 51.4591 kg(CO₂)/GJ, 0.0514591 kg(CO₂)/MJ, 52,999,621 kg(CO₂)/Bcf(NG), 1,854,989 kg(CO₂)/MNm³(NG), and 1.854989 kg(CO₂)/Nm³(NG); it can be computed that producing 1 tonne of steam daily during one year (365 days) by burning natural gas results in CO₂ emissions of 50,283.1 kg. Producing 50 tonnes of steam daily during one year (365 days) by burning natural gas results in CO₂ emissions of 2,514,155 kg. This estimated quantity is identical (when the same number of significant digits is compared) to the GlassPoint-reported value of 2,514 tonnes(CO₂)/year for either the Amal I pilot project or the Amal II pilot project, as shown in Table 3. Producing 2,000 tonnes of steam daily during one year (365 days) by burning natural gas results in CO₂ emissions of 100,566,200 kg. This estimated quantity is close to the GlassPoint-reported value of 100,565 tonnes(CO₂)/year for the Miraah full-scale project, as shown in Table 3.

With regard to the above-quoted carbon intensity, the following theatrical justification can be made. Natural gas consists mainly of methane (CH₄) [198], with a molar fraction of around 95% [199]. The ideal stoichiometric reaction of methane [200] with oxygen is

$$C{H}_4+2O_2\to C{O}_2+2H_{2}O$$

(3)

Thus, in terms of moles, the perfect combustion of one mole of methane leads to the emission of one mole of carbon dioxide (CO₂). The molecular weight of methane is approximately 16 kg/kmol [201], and the molecular weight of carbon dioxide is approximately 44 kg/kmol [202]. Therefore, the perfect combustion of 1 kg of methane leads to the emission of 2.75 kg(CO₂), or 44/16 kg(CO₂). The volumetric lower heating value (LHV) of natural gas is approximately 35,000 Btu/Nm³ or 36,930 kJ/Nm³ [203]. Treated as an ideal gas [204], one mole (kmol) of methane or natural gas at 15 °C and 1 atm or 101,325 Pa [205] occupies about 23.645 normal liters (NL) and has a mass of approximately 16 g. This can be derived using the following ideal gas law:

$$V=n\overline{R}T/p$$

(4)

In the above equation, setting the number of moles ($n$) to 1, the universal (molar) gas constant ($\overline{\mathrm{R}}$) to 8.3145 J/mol.K [206], the absolute temperature (288.15 K) that corresponds to 15 °C, and the absolute pressure ($p$) to 101,325 Pa, gives the standard volume of 0.023645 normal cubic meters (Nm³) or 23.645 normal liters (NL).

Therefore, one kilomole (kmol) of methane or natural gas occupies about 23.645 Nm³ and has a mass of approximately 16 kg at normal conditions. Thus, one normal cubic meter of methane (or natural gas) has an LHV energy content of 35,000 Btu/Nm³ (or 36,930 kJ/Nm³) × 23.645 Nm³/kmol, which results in 827,575 Btu/kmol(CH₄) or 873,209.85 kJ/kmol(CH₄). Given the 1:1 molar ratio between methane and carbon dioxide, these energy intensities can be converted into reciprocal carbon intensities as 0.827575 MMBtu/kmol(CO₂) or 0.87320985 GJ/kmol(CO₂). Converting these molar reciprocal carbon intensities into mass-based (gravimetric) reciprocal carbon intensities via dividing by the molecular weight of carbon dioxide (44 kg/kmol) gives 0.0188085 MMBtu/kg(CO₂) or 0.0198457 GJ/kg(CO₂). Taking the reciprocal of these values gives estimated ideal carbon intensities for natural gas combustion as 53.1674 kg(CO₂)/MMBtu or 50.3888 kg(CO₂)/GJ. Given that 1 MWh = 3.6 GJ = 3,600 kWh, our estimated carbon intensity is also equivalent to 181.400 kg(CO₂)/MWh and 0.181400 kg(CO₂)/kWh. These estimates are very close to the reported third-party value.

4.4. Illustrative Sketches

To explain the geographical location of the Amal field (and thus the three ESEOR projects covered here), Figure 2 has a useful map that demonstrates this [207]. The oil field is located in the southern part of Oman. The Amal oil field is in the north of the Dhofar governorate (the southern governorate of Oman), near its north border with the neighboring “Al Wusta” governorate (the central governorate of Oman). The field is located about 50 km north of the Arabian Sea coast.

The Amal oil field is located at the geographic coordinates of 18.3333989° North, 55.6684729° East [208].

The Miraah enclosed solar enhanced oil recovery (ESEOR) project is located at a latitude of 18.349281° North and a longitude of 55.684590° East [209,210].

Figure 3 illustrates the layout of the parabolic trough rows within an enclosing glasshouse [211]; the curved roof in the sketch corresponds to the Amal II pilot project. The looping of the heated water is noticeable in the sketch, where the heat addition process is cascaded through multiple passes along a sequence of trough rows.

Figure 4 further emphasizes the structural advantage behind the enclosure concept [212], where the fluid-structure interaction [213,214], as well as other environmental harsh influences such as dust and soiling effects, are prevented from affecting the parabolic reflector mirrors.

Figure 5 visualizes the compactness advantage of the ESEOR concept as a source of energy [215] compared to the solar updraft tower (SUT) solar thermal technology [216,217], and the photovoltaic (PV) modules technology (the produced PV electricity should then be converted into heat using electric heaters) [218]. The close proximity of the trough rows in the ESEOR and the decreased soiling loss as a result of better automated daily cleaning make the design very efficient in terms of area utilization. In particular, the footprint demands of an SUT (solar tower) system are about 3 times those of the ESEOR system, while the footprint demands of a PV system are about 6 times those of the ESEOR system.

4.5. Selected Photos

It can be a valuable addition to the current study to show selected real photos that effectively describe the appearance of the three constructed ESEOR projects. This aim is fulfilled in the current subsection.

Figure 6 and Figure 7 are two photos taken for the Amal I pilot project [219,220]. The gable roof design is visible. The trough rows within the greenhouse-like enclosure show small spacing between rows as well as small tolerances at the two side tips of each row. Therefore, the ground coverage ratio (GCR) is close to one (around 0.93), which indicates a very compact design [221,222]. The ground coverage ratio (GCR) is the total mirror aperture surface area divided by the occupied ground area. This high GCR contributes to the effective utilization of the land area. However, self-shading losses become high in the morning and the evening. It can also be noticed that the Amal I project has a single enclosure structure.

Figure 8 is a photo taken for the Amal II pilot project [223]. The high ground coverage ratio (GCR) is apparent from this photo, as a result of small inter-row spacing and small tolerances between the rows and the adjacent enclosure walls. Like Amal I, the Amal II project consists of a single enclosure structure. The curved roof of Amal II is one of its main differences from Amal I.

Figure 9 is another photo of the Amal II pilot project during night installation, and it shows effectively one of the reflector mirrors and its supporting frame [224].

We visually illustrate the structure of the commercial-scale Miraah project. Given its larger scale compared to the pilot-scale Amal I and Amal II projects (the solar field area of Miraah is 36 times the solar field area of either Amal I or Amal II), the Miraah project is not constructed as a single enclosure. Instead, it is split over six enclosures and three modules. This is shown in Figure 10 [225].

Figure 11 is an on-site drone photo for one of the six enclosures of the Miraah project. A small portion of the adjacent enclosure can also be noticed [226]. The water/steam pipelines can be recognized well in this view.

Figure 12 is a front photo of one of the six enclosures of the Miraah project, showing the gable roof and outside pipelines [227]. The photo was taken near the solar noon (the sun is at its highest elevation), and therefore, the trough apertures are nearly pointing straight up. This particular view emphasizes the small clearance between the parabolic reflector mirrors. This maximizes the land utilization but at the expense of reduced capacity factor (CF) due to accentuated self-shading losses before and after the solar noon.

4.6. Challenges

In this subsection, we discuss six challenges faced by the pioneering enclosed solar enhanced oil recovery (ESEOR) projects in Oman.

We compiled these challenges and the attempted mitigation actions and solutions from a variety of published works by GlassPoint staff as well as supplementary relevant external sources, as demonstrated by the cited reference(s) for each discussed challenge.

First, before even the installation phase, the large land area needed for an ESEOR project can be a challenge by itself. As in solar systems in general, the incoming solar radiation has relatively low density (around 1 kW/m² at its peak), and thus requires a large area to collect sufficiently useful heating rates [229,230,231]. A single receiver loop in the 54-loop Miraah project produces about 1.54 tonnes of steam per hour (about 13,500 tonnes of steam per annum), which requires heating freshwater at an intense rate of about 3.38 GJ/hour or 0.940 MWth. This is the bare minimum theoretical heating rate, without any losses. At peak operation, the realistic single-loop load jumps to 6.11 MWth or 22.0 GJ/hour. While this particular challenge was not problematic in the case of the Omani Amal oil field (due to the availability of unoccupied land), it might be a concern in another site.

Second, soiling in the open desert area of the Amal oil field can cause rapid loss of performance. While the transparent enclosure of the ESEOR protects the solar collector mirrors from dust and other soiling factors, the glass enclosure itself is subject to such soiling effects. This problem was addressed by daily night cleaning using a fast automatic roof washing (cleaning) system. The average soiling losses are kept at a maximum of 2% only between two consecutive daily washing processes. Due to dust infiltration, some internal soiling (inside the glasshouses) also occurs, but at a slow rate of about 0.2% per week. Due to the absence of condensation at the reflector mirrors, which is a condition attained by an air handling unit (AHU), dry, infrequent cloth-based cleaning is enough to restore the performance of the parabolic troughs and receiver tubes. A reverse osmosis (RO) plant is used to produce clean water for washing (cleaning) purposes that counteract soiling [185].

Third, due to having two sources of steam (the solar steam and the gas-firing steam) in the hybrid ESEOR projects in Oman, such hybrid steam generation systems require attention in terms of combining these two streams of steam. This was addressed by installing a production steam header, into which solar steam or gas-firing steam is injected directly. This header is charged at 88 bar to 100 bar [232].

Fourth, the weather at the Amal desert field can be very harsh, especially in the summer, when the ambient temperature approaches 50 °C at noon. This harmfully affects labor productivity as well as health and safety. This issue was mitigated by shifting the work from daytime to nighttime, where a drop of about 10 °C occurs [185].

Fifth, maintaining the receiver tube clear for the fluid flow requires special treatments. The water used at the Amal field is produced water (saline water separated from the extracted oil) [233], with about 8,000 ppm total dissolved solids (TDS) [234]. Such produced water is contaminated with dissolved minerals and probably with small solid particles. Therefore, it is important to prevent corrosion, erosion, and the deposition of solid matter on the internal walls of the receiver tube. These targets were achieved through multiple actions. Instead of the expensive demineralization treatment, water softening (as a limited but less expensive form of water treatment) was adopted, and water hardness was removed to less than 1 mg(CaCO₃)/L, which is very small [235,236]. Also, dissolved oxygen content is kept below 10 ppb using oxygen scavengers [237,238]. Accumulation of solid deposits is reduced by limiting the steam quality (steam dryness fraction) [239] at the boiler exit to 80%, which means that 20% (by mass) of this two-phase liquid-vapor water mixture is sufficient to dissolve soluble impurities. It should be noted that due to the variation of the solar irradiance during the day and the nonlinear heat transfer phenomena for solar heat generation [240,241], a control system [242] is installed to adjust the feedwater flow rate accordingly to maintain the target output steam quality [243,244,245]. Despite these preventive procedures, a small quantity of solids still inevitably accumulates in the receiver tubes. This is periodically removed through cleaning by hydraulically activated pipeline pigging (HAPP) [246]. The selection of carbon steel for the receiver tube was carefully made because of the high salt concentration of the feedwater. Alternative austenitic stainless alloys are not suitable here because they are susceptible to stress corrosion cracking (SCC) [247] upon exposure to chloride concentrations above 100 ppm [248,249].

Sixth, the limited capacity factor of an ESEOR project affects its economic feasibility. However, this low capacity factor can be increased if the rate of steam injection into the oil reservoir does not have to be at a constant rate during the 24-hour day. Instead, if more steam injection during the sunshine hours and less steam injection during the night are adopted, then the consumption of natural gas can be reduced further, to about 80%. This idea is possible because the heating and pressurization of the subsurface reservoir are not sensitive to the daily profile of steam injection. However, this idea implies elevated capital costs, increased operational maintenance costs, and added system complexity due to the oversized solar steam generation system. It also means that the oversized solar steam generation is more underutilized when the overall daily cycle is considered.

4.7. Steam-Oil Ratio (SOR)

In this subsection, we broadly discuss one of the key aspects of thermal enhanced oil recovery, which is the steam-oil ratio (SOR) [250], also called steam-to-oil ratio [251,252] and steam/oil ratio. This non-dimensional number is defined as the volume of water (converted into injected steam) to produce one volume of oil. The value of SOR can vary between two and eight [253]. In the case of the Omani solar enhanced oil recovery projects, a value of about three was reported. This is a favorable low value, reflecting an efficient use of steam. It is the same as the average steam-oil ratio (SOR) reported for the thermal enhanced oil recovery projects in Alberta, Canada [254]. The implication of the SOR is the water consumption for the thermal enhanced oil recovery. This consumption is aimed at being minimized for environmental and economic reasons. The profitability of steam-based EOR depends largely on the steam-oil ratio (SOR), due to affecting the operational cost [255]. It is worth mentioning that the steam-oil ratio might be reported in terms of the mass (kg steam/kg oil) [256] rather than the volume (m³ steam/m³ oil).

5. Conclusions

We provided an overview of three novel sustainable enhanced oil recovery projects in Oman, in which clean steam produced by concentrated solar radiation partially replaces conventional steam produced by natural gas combustion, for the purpose of thermal enhanced oil recovery at the Amal oil field. Various design parameters, visualized structures, and challenges were discussed. This work is a case study that primarily aims to demonstrate and promote these successful examples for broader adoption in other geographic locations, which have large environmental gains.

We applied a thermal and emissions model to validate public data about the annual energy needs, annual natural gas consumption, and annual avoided carbon dioxide emissions. We found that the independently reported values are reasonably acceptable.

The current work did not cover the economic aspects of solar steam generation [257]. Also, some technological details were not mentioned here (such as the control system for steam injection, water storage, and automatic cleaning devices). Although these can be viewed as limitations, they help make the study focused and concise. These additional elements are valuable additions for coverage in a separate work.

The current work can be extended by examining thermal energy storage [258,259] as an added aspect in the Miraah solar enhanced oil recovery system. The technical gains from this idea can be assessed in terms of its ability to further reduce, or even eliminate, the demand for natural gas as a heating source at the Miraah project. This extension may require proper sizing of the storage capacity and exploring possible profiles of supplying steam to the reservoir (fixed rate versus variable rate).

For policymakers, the current study recommends expanded deployment of hybrid solar-steam generation systems for thermal enhanced oil recovery. The successful and endured operation of the Omani projects, as presented here, encourages governments and businesses to adopt this concept. The use of hybrid solar steam generation is not recommended only in enhanced oil recovery, but also in other processes that involve large heating demands. These include district heating [260,261], power generation [262,263,264], industrial drying [265], and food processing [266,267]. Governments can provide financial incentives [268,269,270] as well as technical awareness programs to motivate the transition toward this more sustainable heating alternative.