A Review on Geothermal Energy and HPHT Packers for Geothermal Applications

Abstract

Energy is an essential component for prosperity, economic growth, and development and has become a basic necessity for humans, but at the same time, it has an impact on the environment. Therefore, it is believed that, in the coming future, renewable energy will play an important part in fulfilling the energy demand. In that respect, geothermal energy will be vital as it is a continuous source of energy that is not affected by metrological conditions and can be used in power generation or domestic heating. Many countries around the globe are actively producing energy from geothermal resources. However, the extraction of the heat from the subsurface comes with challenges such as subsurface environment, wellbore instability, corrosion, loss of circulation, and cementing operation. However, one of the most challenging and critical tasks is the zonal isolation of the geothermal well. A packer is a tool that is used for the zonal isolation of a well, and at high pressure and high temperature (HPHT) conditions, which is common for geothermal wells. Most of the components of packers fail, causing well integrity issues. This paper gives a review of the forces acting on packers, testing standards, problems encountered by a packer in the HPHT subsurface environment, and designs to overcome those problems.

1. Introduction

With each passing day, the population of the world is increasing, hence, the availability of energy has to be sufficient to meet the demand of people. It is estimated that by 2035, the population of earth will be 8.8 billion and energy needs will be increased by 30% [1]. Some other reports like the Energy Information Administration (EIA) (2016) [2] suggest that the population can go as high as 48% by 2040 [2]. This high energy demand can be met by contributions from both renewable and non-renewable energy resources. However, the contribution would not be shared equally as it is expected that by 2040 the energy production from renewables will increase fourfold, thus accounting for a majority share of the net energy production [1].

At present, amongst the renewable sources, hydropower is the highest contributor with 71%, while geothermal resources produced less than 1% of the energy demand [3]. Although the contribution of geothermal energy is on the lower side as compared to other carbon-free sources, the advantage that geothermal has over other renewable energies makes it attractive for future development. Some of these advantages are: a huge amount of untapped resources, consistency, applicability for a wide range of applications, and availability in many parts of the world at certain depths [4]. Moreover, it is considered a continuous source of energy that is rarely affected by weather conditions, and 98% of the time is in operation mode [5,6]. Geothermal energy has shown great potential as a renewable source of energy because of its low impact on the environment, less emission of greenhouse gases, and technology availability [7,8].

The word geothermal comes from the Greek word gê, which means Earth while Thêrm refers to energy. Geothermal energy is not a new source of energy, it dates back to 10,000 years when the Paleo-Indian settled at the hot springs and used natural geysers for cleansing and as a source of warmth, while its minerals were utilized as a medication [9]. Whereas, the first commercial geothermal power plant was established in Tuscany, Italy in 1904 [10].

Geothermal Energy is interpreted as the heat that is acquired from the earth, which can be utilized in a wide range of applications from a small scale, such as for heating a building, to a large commercial scale for the production of power (electricity). Due to the high temperature of the earth’s core, that is, 5500 °C the heat is transferred to the mantel and crust by the conduction through rocks, movement of the fluid, or the displacement of deep hot rock toward the surface because of the tectonic activities [11]. The extraction of the heat from the subsurface is done by the circulation of fluid from the bottom to the surface. In most cases, the fluid, which mainly consists of brine, is produced from the geothermal reservoir. At some locations either the fluid does not exist (dry rock), or the permeability of the formation is very low. For such situations stimulation job is performed to increase the transfer properties of the formation. This process involves injecting water from an injection well and recovering the heated water from the production well [12]. Figure 1 shows a basic schematic representation of a geothermal well.

Hydraulic fracturing is the most common method used for the stimulation of the oil and gas well and has been used since the 1950s [13]. For geothermal wells, hydraulic fracturing has been used since the 1980s [14]. Hydraulic fracturing involves injecting a high-pressure fluid (above the minimum horizontal stress of the formation) into the formation. This creates cracks/fractures in the vicinity of the wellbore and improves the transfer properties of the reservoir (Figure 2). To keep fractures open, permeable proppants are injected along with the fluid. The co-coefficient of performance (COP) of hydraulic fracturing is dependent upon the permeability of the reservoir and the skin. For low permeable formation, the COP can be doubled whereas for a tight reservoir the COP can increase by five times or more [13].

Figure 1. Geothermal well for the production of energy [15].

Figure 1. Geothermal well for the production of energy [15].

2. Geothermal Source Energy

The heat in the geothermal wells located in the continental margin of non-volcanic areas is produced from the decay of radioactive elements such as 232Th, 40K, and 238U [16,17] and is not from a magmatic source like for geothermal wells in volcanic regions. Another source of heat generated in geothermal wells is by viscous shearing and friction between the boundaries of lithosphere sectors [18]. The use of geothermal energy for different applications is dependent on the source temperature and is shown in

Table 1. Geothermal source temperature and its application [19,20,21].

Range	Temperature	Dominated Fluid	Application
High temperature	Above 150 °C	Vapor and liquid	Fuel and power generation
Medium temperature	Around 95 °C	Mostly liquid	Electricity production by utilizing binary plant
	From 90 °C to 150 °C		Drying of timber, refrigeration, cooling, or heating of buildings
Low Temperature	From 90 °C to 30 °C	Liquid	Aquaculture, processing of food, and heating of the greenhouse
	Below 30 °C		Warming of soil

. To make the geothermal project reliable and economical, efforts should be made to utilize the geothermal energy extracted from a single source to be used for multiple applications.

3. Geothermal Systems

There are different types of geothermal systems present from which energy production can be made possible. (1) Hydrothermal system is considered to be the most ideal source of geothermal energy in which the subsurface layers have good permeability and fractures, from which fluid can be produced at a high volume. In most of these systems, liquid water is present, however, in places where high temperature and low pressure exist, water and steam or steam alone can be present in a continuous phase [22,23]. (2) A geopressured system is one in which the water is present in a medium temperature range, but the hydrostatic pressure of a such system is higher than the depth in which they are present [24]. (3) In the Magmatic system, the temperature exists in the range from 1112 to 2552 °F (600 to 1400 °C) [25] (4). For the Hot Dry Rock (HDR) system, the temperature ranges from 392 to 572 °F (200 to 300 °C) [26]. This geothermal system contains less fluid, and the permeability of the reservoir is low [11].

At present, the geothermal reservoirs known as the “Enhanced Geothermal System” (EGS) have taken the central stage and have a huge potential for power generation of 70 GW_e by the end of 2050 [27]. The temperature of the EGS ranges up to 572 °F (300 °C) [12]. The characteristic of this system lies in between the hydrothermal and HDR system, which means that either the reservoir is deprived of brine water, or the permeability of the formation is very low. The US Department of Energy defines EGS as “engineered reservoirs created to extract economical amounts of heat from unproductive geothermal resources” [28]. In this context, engineering is defined by the use of the latest technologies that will make this resource commercially viable through fracturing and circulation of the fluid from the injection well and receiving it from the production well as shown in Figure 3. Though the USD/MWh of EGS is higher than the hydrothermal systems, it is abundant in most parts of the world. Many studies focusing on extracting energy in a cost-efficient way from EGS show the importance of successful drilling and completion operations in developing an EGS geothermal well [27,29].

4. Uses of Geothermal Energy

4.1. For Power Generation

For power generation, the temperature of the steam or water recovered from a geothermal well is required to be between 212 to 700 °F (100 to 371 °C). Most the geothermal plants are located in areas where a geothermal reservoir exists within a depth of up to two miles [30]. There are three main categories of electricity-producing geothermal plants. The first category of plants involves the generation of electricity from a high-temperature geothermal reservoir that has a temperature of more than 455 °F (235 °C). These plants are most economical because the steam from the geothermal source is directly fed into the turbine for electricity generation (see Figure 4). Whereas a condensed stream is fed into the subsurface layers. However, these plants are very few in number and are rarely established as the depth to achieve such a high temperature can go up to 2.5 miles [31].

The second category is the flash steam cycle plants, which are deployed when the temperature of the given resource is in the range of 300–700 °F (149 to 371 °C) [30]. In this process, the pressure of the hot liquid is reduced to convert it into flash steam. The flash steam is then removed from the liquid and is fed to an electric generator through the turbines, while the separated liquid is injected back into the subsurface layers as shown in Figure 5.

For low-temperature reservoirs, with temperatures higher than 185 °F (85 °C), binary cycle systems look promising [27]. In these plants, the transfer of heat takes place from hot subsurface fluid to a working fluid (usually consisting of low boiling hydrocarbon), which vaporizes and drives the generator turbines. The advantage of this method is that the geothermal fluid is not exposed to the ambient condition and is injected back into the subsurface layers. These plants are capable of producing power at a large scale [28]. Figure 6 shows the working of a binary flash/cycle power plant.

Currently, the United States is leading the way in the power generation from geothermal resources and in 2020 produced about 17 billion kWh, which is almost 0.4% of the total electricity utilized by the country.

Table 2. Share of the electricity generated from geothermal energy by different states of the USA in 2020 [35].

USA States	Share Contributed by the State with Respect to the U.S. Geothermal Electricity Generation	Share of the Electricity Generated for the Given State
California	70.5%	6.1%
Nevada	24.5%	10.2%
Utah	2.1%	1.0%
Hawaii	1.2%	2.2%
Oregon	0.9%	0.2%
Idaho	0.5%	0.5%
New Mexico	0.3%	0.2%

shows the share of geothermal electricity produced by different US states in 2020 [35] while Figure 7 shows the geothermal resource distribution in the US. It is expected that between 2030 and 2050, the energy generated by geothermal resources will exceed 60 GW [36].

As evident from the table above, most of the geothermal energy production in the US comes from the western states including Hawaii. The first geothermal plant in the USA was installed in North California, which hosts one of the biggest dry steam fields in the world and has been producing electricity since 1960 [28].

At present, there are more than 25 countries that have started working on geothermal projects for the commercial production of electricity. Among these countries, Indonesia is ranked second in terms of total geothermal energy production. The country produced 14 billion kWh of electricity, which accounts for 5% of the total produced electricity. While Kenya produces 48% of the required electricity from geothermal energy and is ranked eighth in the world with 5 billion kWh production [35].

4.2. Direct Use

From native American, Chinese, and ancient Roman times, the use of geothermal energy was common, they used hot water from the geysers located near the earth’s surface for cooking, bathing, and heating. Many hot springs are used by people for baths as it is believed that mineral-rich hot water has certain health benefits. Currently, direct energy from geothermal is used as a district heating system in which a building or multiple buildings are heated. This costs almost 80% less than the heating done through fossil fuels [30]. The direct heating system is very common in Reykjavik, Iceland. It has helped to cut down the fossil fuel usage for space heating in Iceland, resulting in a boosted economy through an average annual savings of about 2.6% of the GDP between 1956 and 2016 [37].

Table 3. Population-based (per 1000) ranking of the country utilizing direct geothermal energy-2015 [38].

Country (MWt/Population)	TJ/Year/Population
Iceland (6.26)	82.04
Sweden (0.57)	5.30
Finland (0.28)	3.29
Norway (0.25)	1.61
Switzerland (0.22)	-

and

Table 4. Ranking of the countries utilizing direct geothermal energy (including and excluding heat pumps-2015 [38].

Including Heat Pumps
Country (MWt)	TJ/year
China (17,870)	174,352
USA (17,416)	75,862
Sweden (5600)	51,920
Turkey (2937)	45,892
Germany (2849)	-
Iceland (-)	26,717
Excluding Heat Pumps
China (6089)	74,041
Turkey (2894)	44,932
Japan (2086)	25,630
Iceland (2035)	26,700
India (986)	-
Hungry (-)	9573

show the countries that are using direct geothermal energy.

5. Drilling and Completion Challenges for Geothermal Well

Drilling and completion operations are an important and critical part of developing a geothermal or hydrocarbon field. It accounts for approximately 50% of the total cost of setting up a geothermal field [39]. The drilling and completion operations for a geothermal hydrocarbon well do share many similarities, but geothermal wells are much more challenging, complicated, and expensive. This section highlights some of the drilling and completion challenges associated with developing a geothermal well.

5.1. Subsurface Environment

Geothermal reservoirs are typically found in formations with highly fractured igneous or metamorphic rocks, which are present at a much greater depth as compared to hydrocarbon reservoirs located in sedimentary rock formations. This differentiates a geothermal reservoir from a hydrocarbon reservoir as it is present in a region of much harder rocks under high temperature and pressure conditions. The temperature of most of the developed geothermal wells ranges between 150–300 °C although a few wells with supercritical conditions, that is, temperatures and pressures above 374 °C and 221 bar, respectively for pure water, and temperatures above 406 °C with pressures exceeding 298 bar for seawater have been found [40]. The ductility of the rocks has been reported to increase under high temperature (200–300 °C) conditions [41], which can reduce the efficiency of the drilling process. High-temperature conditions can also cause the failure of elastomer components, control electronics, and logging tools present in the bottom hole assembly [42].

5.2. Corrosion and Scaling

Corrosion and scaling issues are commonly observed in geothermal wells. Geothermal reservoir fluid contains corrosive chemical elements and compounds like oxygen, hydrogen ion, chloride ion, sulfate ion, carbon dioxide, hydrogen sulfide, hydrogen chloride, and ammonia, which can have a detrimental effect on the metallic components placed in the well [43,44]. In cases where superheated steam is produced from geothermal wells, erosion and severe scaling of liner and casing elements were observed [45]. Corrosion and scaling can compromise the structural and well integrity, which can lead to the abandonment of wells in some cases. Therefore, Corrosion Resistant Alloy (CRA) is recommended for casing and liner selection. Geothermal fluid has the potential to contaminate cement during the setting stage leading to poor zonal isolation and reduced performance.

5.3. Wellbore Instability

Wellbore instability is a common, time-consuming issue faced during the drilling of the geothermal well. Wellbore instability can be described as the inability of an open hole to maintain its required size, shape, and structural stability [46]. A highly fractured rock formation in a geothermal well can make the wellbore geomechanically unstable. The instability can also be caused by the degradation of the wellbore wall from the liquid present in the drilling fluid. Whereas, a reduction in hole diameter due to swelling or squeezing clays can lead to the pipe sticking or can prevent the running of the casing. Unconsolidated formations can make hole cleaning more challenging, collapse around a drill pipe results in sticking, and can also cause a washout [11]. All these issues further increase the complexity of geothermal well drilling.

5.4. Circulation Loss

Circulation loss is the partial or complete loss of the drilling fluid in formations with high permeability [47] and is a frequently encountered problem in geothermal drilling because of the presence of highly fractured rock formations. It accounts for 10–20% of the total cost of geothermal drilling operations [11]. In a case study done on geothermal wells in Indonesia, 30% (194 h) of the total operation time was put to resolve the issue of loss circulation in one of the sample wells [48]. Figure 8 shows the distribution of the operation time for this well.

Circulation loss can lead to the following problems:

• Loss of fluid in the well can decrease the static head of the drilling fluid, which can result in a well control issue.
• If the drilling fluid fails to bring the cuttings to the surface, the cuttings can fall back to the bottom hole and stick to the BHA.
• Drilling fluid is expensive, it accounts for 25–40% of the drilling operations cost [49]. Excessive loss of drilling fluid can have a negative effect on the economics of the drilling operation.

Loss of circulation is a constant topic of discussion in the geothermal world and can be tackled by optimizing drilling and cementing operations. While drilling, it is advised to always keep the Effective Circulating Density (ECD) within the drilling window of pore pressure and fracture pressure of rock. In unstable formations, Under Balanced Drilling (UBD) and Managed Pressure Drilling (MPD) drilling techniques should be used [50]. During cementing, utilizing a sealant spacer fluid or implementing foam cementing are some proven ways of achieving effective zonal isolation in geothermal applications [51].

5.5. Wellbore Cementing Challenges

The cementing and casing operation takes up about 30–35% of the total well cost [52] and must be designed and planned to bear the extreme conditions of a geothermal well including high temperature, pressure, and corrosive fluids. The cementing operation holds the casing in place and prevents unwanted formation fluid to enter the wellbore by creating an annular barrier between the formation and casing. It also provides structural support and acts as a barrier that prevents the corrosion of the casing from the corrosive fluids. Traditional oil well cement is not used in geothermal wells due to difficult downhole conditions.

Field applications have shown a reduction in cement compressive strength and increased permeability, also called strength retrogression for Ordinary Portland Cement (OPC) exposed to temperatures exceeding 110 °C [50]. This can often lead to well integrity challenges like fluid leakage, cement sheath debonding from the casing/formation, development of cracks, or cement deformation leading to structural instability. One solution is to add additives to the cement that will resist the degradation of the cement matrix in harsh conditions. For example, Silica is often used in cement composition for dealing with strength retrogression problems in geothermal wells [53]. Another viable solution is to accurately predict downhole cement sheath stresses for a more informed cement selection.

Although extensive literature is available for well cementing operations, most of it caters to hydrocarbon well cementing. Temperature is a key factor impacting the cement properties, but a limited amount of literature is available on cement performance at high temperatures (above 350 °C).

In conclusion, drilling and completion challenges related to geothermal wells are due to extreme pressure and temperature conditions, unstable rock formations, and the presence of a corrosive environment. In most cases, well integrity can be potentially compromised if not corrected in time.

6. Downhole Tools for Geothermal Wells

Saito (1995) [54] discusses the efficiency of the MWD and downhole motor when used in the geothermal field of Honshu Island, Japan. The temperature of the formation was in the range of 300 to 350 °C at the depth of 1500 to 2000 m. The limitation of the equipment was about 150 °C but MWD was able to work under high temperatures due to the use of an efficient mud cooling system that assisted in reducing the bottom hole temperature. Though the temperature of the formation was 350 °C, the bottom hole circulating temperature (BHCT) was 80 °C because of the cooling system of the drilling fluid installed at the surface. In comparison, it was found that MWD remained in workable condition even in the 350 °C formation temperature while the stator of the downhole motor failed at 150 °C. The main reason was that the MWD can be run immediately after the well is cooled while for the lowering of the downhole motor, it must be attached to the drilling string, which takes time and limits its operation widow.

To avoid the borehole necking problem in the geothermal well, a reamer should be used. In that respect, Schlumberger developed a RHINO reaming tool that has a temperature limit of 215 °C [55] and can enlarge the hole by 20%. The most important component of the BHA is the drill bit and in the drilling of geothermal wells very hard formations are encountered. Most of the geothermal resources are present in igneous or metamorphic rocks, which are hard compared to sedimentary rocks. Hence, for the drilling of the deep geothermal well, NOV came up with a thermal resistant and ultra-hard ’ReedHycalog PDC bit‘, which can drill rocks with compressive strength of 280 MPa. Moreover, with the proper mud cooling system, this bit can operate at 350 °C [56]. JRG Energy (2022) [57] has introduced a retrievable bridge plug for the zonal isolation of a geothermal system that is resistant to high temperatures. It is set by either wireline or coil tubing and has an operation window of 250 °C and 4931 to 10,000 psi of differential pressure.

A downhole tool for fracking geothermal wells is shown in Figure 9. The most important component here is the packer as it is responsible for holding the differential pressure and the axial loads. Moreover, the corrosive fluid along with the HPHT condition makes the operating conditions for packers much worse. If the packer fails to provide zonal isolation or loses its integrity during the stimulation operation, serious well integrity issues can arise, which might lead to losing the well completely. Hence conventional packers used in the oil and gas wells are not suitable for geothermal applications. Special packers compatible with HPHT, high differential pressure, and corrosive fluid environments are required for geothermal applications. This paper gives a review of the challenges and design solutions of the packers exposed to HPHT/geothermal subsurface conditions.

7. Relation of HPHT and Geothermal Well

As discussed in the previous section, drilling a geothermal well is similar to drilling an oil and gas well, however, drilling a geothermal well presents unique complexities and challenges because of the subsurface environment in which the geothermal resource is present. Hence, it is important to understand the limitations of the equipment and tools used in the oil and gas industry before they are deployed for geothermal well drilling [7]. At present, about 50% of the money in the geothermal project is spent on drilling research and completion. It is one of the most important aspects of the geothermal well because if the integrity of the well is compromised then the whole project can fail [39].

As the drilling operations are going deeper, the demand for the completion technologies that are suitable for such conditions is on the rise. In the past few years research efforts have been focused to develop completion tools that are workable in the HPHT condition [58]. The definition of HPHT has changed over the years. Initially, it was considered to be the pressure greater than 10,000 psi and temperature ranging around 300 °F (149 °C) and later was changed to 20,000 psi and 450 °F (232 °C) [59]. While the ultra-HPHT condition is considered to have temperature and pressure above 20,000 psi and 450 °F (232 °C) [59] respectively, as shown in Figure 10. Hence, the completion of the geothermal well can be considered similar to an HPHT well as the annular barrier is exposed to similar downhole conditions. Therefore, the packers that are used for the zonal isolation in HPHT wells can also be utilized in geothermal wells.

8. Testing Standard for Packers

For the classification and standardization of the packers, American Petroleum Institute (API) along with the International Organization for Standardization (ISO) came up with certain guidelines for laboratory testing to assist the industry with packer design and selection. These standards are the minimum threshold that a manufacturer should imply in order to claim conformity. The guidelines have been delineated under API Specification 11D1 and ISO14310:2001(E) [61,62]. With respect to testing of the packers, six standard grades V1 to V6 have been established that outline the design criteria for packers. V1 represents the highest level of testing and V6 is the lowest one. Whereas, a special grade V0 has been included, which is for special requirement purposes. The different grades are described below.

Grade V6

In this grade, the manufacturer defines the performance level of the packer that does not come under V1 to V5 testing criteria. Therefore, it is considered to be the lowest grade.

Grade V5

Testing in this grade is conducted with liquid. The packer is set under the maximum temperature and internal diameter for which it is rated, and the lowest pack-off force as directed by the manufacturer is applied. For the pressure testing, maximum differential pressure is deployed across the packer (to which it is rated) with the help of hydraulic oil or water. To ensure the packer withstands the pressure from both sides, two pressure reversal is applied. The holding time for each test should be at least 15 min. For the retrievable packer, it is important that the packer is retrieved from the testing setup after the test.

Grade V4

In this test, all the guidelines of V5 are followed along with the addition of tension and compression loads that are applied during the pressure differential test. A performance envelope of the tested packer is then defined.

Grade V3

Tests corresponding to grade V3 include all the parameters of grades V4 and V5 with the addition of temperature cycling in which the packer is exposed to its minimum and maximum rated temperature. The test is initiated with the highest temperature, with the relevant pressure and load (axial and tensile) that a given packer is designed for. After clearing this test, the temperature is reduced to the minimum rated temperature of the packer and the load and pressure are applied again. After going through the low-temperature test successfully, the packer should also clear the differential pressure test after the temperature of the testing setup is raised back to maximum.

Grade V2

The test parameters of this grade are the same as that of grade V4 with the difference being in the fluid used in testing. In the grade V4 test, liquid is used but for grade V2, the testing medium is gas, which comprises nitrogen or air. A leakage rate of under 20 cm³ during the hold pressure test is considered acceptable for this grade.

Grade V1

It has the same parameters as V3, but gas is used as a medium for testing. Similar to V2, the acceptable leakage rate is under 20 cm³.

Grade V0

This is the special grade introduced for the specific requirement where no gas leakage is allowed, that is, a tight gas seal is required. The parameters of this test are similar to V1.

It must be noted that if the packer is qualified for the lower grade it can also be used for the upper grade. For example, if the packer satisfies the V0 test, it is also validated for V0, V1, and V2. The summary of the grade testing is shown in

Table 5. Summary of packer grades tests according to API Specification 11D1 and ISO 14310:2001(E) [61,62].

Grade	Liquid	Gas	Pressure	Loading (Axial and Tensile)	Temperature Cycle	Gas Tight
V6 *
V5	✓		✓
V4	✓		✓	✓
V3	✓		✓	✓	✓
V2		✓	✓	✓
V1		✓	✓	✓	✓
V0		✓	✓	✓	✓	✓

* Manufacture and supplier defined. Lowest grade amongst all.

.

9. Forces Acting on the Packer in HPHT Condition

In an HPHT reservoir, the produced fluid is under the influence of high temperature and pressure. Due to these conditions, the loads acting on the packers change drastically and can cause failure and serious well integrity issues [63]. Packers also play a vital role in conducting the well-completion test [64] as they ensure the ease of production fluid flowing out of the tubing and protect the casing by isolating the annulus between the casing and the tubing [65]. Zhao et al. (2016) [66] report that in the Tahe Oilfield in Tarim Basin there were 1152 well times that the completion tests were performed out of which 30 well times the packers failed and resulted in huge financial losses. According to Li, et al. (2021) [67], the forces acting on the packer in well completion testing for deep water HPHT well can be divided into two parts. First is the axial force acting on the tubing due to a change in its original length, which will ultimately be transferred to the packer. The second is the pressure difference created across the packers (lower and upper annulus pressure) as shown in Figure 11. The axial force on the packers acts due to the dynamic downhole condition, in which a change in forces can lead to the ballooning and buckling effect, leading to elongation or shortening of the tubing that creates axial loads on the packers [68]. The different packer designs for HPHT/geothermal well applications have been further discussed in this paper.

10. Challenges for Packers and Their Remedial Design

Packers are crucial elements for the completion of geothermal wells. Technically, all casing packers almost share similar elements, which are elastomeric seal assembly, mandrel, and slip-cone (wedge). Packers are generally classified as production and service packers. Production packers are mostly permanently deployed to withhold the production casings along the lifetime of a well. Whereas service packers are temporarily deployed and are retrieved upon the completion of an operation. Following their deployment, both types of packers need to be set (energized) either mechanically, hydraulicly, hydrostatically, or electrically.

Applications of packers in geothermal wells are primarily influenced by the temperature limitations of the elastomeric materials, which are considered key components of packers. For geothermal wells, selecting an elastomeric material to service in this hostile environment is a big challenge. It was not until 1979, that the researchers were able to invent modified ethylene propylene diene monomer (EPDM) to successfully serve in a variety of geothermal applications at downhole temperatures of up to 500 °F (260 °C) [69]. The author claimed that the Y267 EPDM packer proved to serve in steam injection, geothermal hydraulic stimulation, and geothermal hydraulic fracture operations. Y267 EPDM can be considered a technological breakthrough for the applications of high-temperature elastomers. However, the integrity of this packer is most likely to be compromised in a downhole condition where there is a possibility of easy access to air and oxygen at high temperatures.

By the 1980s, extensive research work was conducted at Los Alamos National Laboratory (LANL) and Sandia National Laboratories (SNL), USA, to explore potential drilling technologies that could advance an improvement in geothermal energy extraction. LANL managed DOE’s hot dry rock (HDR) program at Fenton Hill, New Mexico from 1974 to 1995. In this program, two parallel wells were drilled into the hot impermeable rock and artificial fractures were created between the two holes to create a flow loop in order to produce hot fluid to drive a power plant. To complete the wells successfully, LANL developed special packers in 1982, however, the packers failed to perform effectively under the harsh geothermal environmental conditions. As a result, two novel packer designs were introduced. The first design was introduced by Dreesen, et al. (1988) [70] in which an elastomer and steel expansion elements were integrated as a single packer. The packer was used to isolate zones, conduct injection tests, and stimulate an HDR (granite wellbore) with temperatures up to 470 °F (240 °C), in the hole size of 9.2″ with differential pressures and cooling downs exceeding 5500 psi and 300 °F (170 °C), respectively. This design was deployed for 10 packer runs in 1985 and exhibited good performance in four runs. In one of the runs, the packer had shown a tight seal as planned but could not be retrieved. Although this design at that time was considered to be commercially viable, it was too complex. The second design was introduced by Dreesen (1991) [71] in which metal (tandem) expanded metal packers were proposed as an alternative to open hole packers and cemented liners for zonal isolation in aggressive geothermal wells. The major concern with the expanded metal packer was their limited expansion. Additionally, the packer was susceptible to failure (rupture) in oversize/enlarged holes or intervals with high breakouts (i.e., irregular cavities in the wellbore wall caused by localized stresses). However, the latter issue could be avoided by conducting an accurate caliper log.

It is a common industry practice to use packers for accomplishing different operations in geothermal wells. Based on their applications, packers can be classified into hydraulic stimulation packers or hydraulic fracture packers. Polsky, et al. (2008) [72] claimed that permanent packers are superior to retrievable packers for single-zone fracturing because of their higher-pressure rating. Like in oil wells, the completion of geothermal wells could be with open or closed holes. In an open hole well, packers can be designed in various configurations; inflatable, swellable, and mechanical. Polsky, et al. (2008) [72] stated that conventional inflatable packers are not appropriate for EGS geothermal wells because they are usually designed for rated temperature and pressure of 356 °F (180 °C) and 5000 psi, respectively. Currently, the use of modified packers (cement inflated) has become an available option. Swellable packers are the best fit for EGS geothermal applications. These packers have the capacity to operate at a differential pressure range of 7000 to 10,000 psi and a temperature of 392 °F (200 °C). It is worth mentioning that lab tests performed on this packer proved its workability at a temperature of up to 392 °F (572 °C). The setting time for these packers is relatively long, up to 20 days [72]. Mechanical packers are not a favorable option for the completion of a geothermal fracturing application because during the setting process fractures may be induced around and above the packer. Fractures tend to occur since the hole is not cased and cemented, in addition, the packer elements are short.

Robb and Valentine (2010) [73] discuss the problem encountered in one of the wells that were operated in the North Sea. The casing had worn out in the HPHT well and therefore leakage was encountered in the production annulus due to the failure of the isolation system. Therefore, a permanent packer was designed for the worn-out 9.625-inch casing and a three-step test was conducted. In the first step, the packers were exposed to the flow rate of 3 barrels per minute at the temperature of 180 °F (82 °C) to make sure that the AFLAS element (a copolymer of propylene (P) and tetrafluoroethylene (TFE)) was not damaged. This was to create a scenario in which the packer is run down the hole and the circulation that takes place before its setting. While in the second stage, the application test was performed with the help of the synthesis oil to duplicate the real field condition until the failure happened. Moreover, this test also accommodated the production, setting of the packers, and hot and cold shut-in. The test was conducted for more than 200 h at a temperature of 343 °F (173 °C). While for the last set of examinations, a modified ISO14310 V0 test was conducted at a differential pressure of 15,000 psi at 450 °F (232 °C) with a compression and tension load of 400,000 lbs. After all these tests, it was observed that the element AFLAS did not go through any extrusion, while the backup shoe remained undamaged. This was the first packer test that was carried out in a worn casing under HPHT conditions.

Doane et al. (2012) [60] report that the conventional packers that were used in the condition of 15,000 psi and 350 °F (177 °C) had some challenges. Most of these packers are compression sets with three elements and metal backup rings. To activate the backup ring the push is given by the element to the backup ring after which it comes in contact with the casing ID. The setting of the packer element becomes difficult in a high-temperature environment because, in these conditions, the rubber element becomes soft and starts to extrude over the backup ring, which hinders its contact with the casing ID. Moreover, in a high-temperature environment, the backup rings become thicker, which creates more difficulty for its expansion. Therefore, a new design was formulated that used the best design criteria of the ZXP and Premier seal system in such a way that the backup ring profile was taken from the Premier and combined with the ZXP seal system. In this type of seal, the extrusion of the backup ring is not dependent on the rubber element and can hold higher pressures. The element used was made up of Perfluoroelastomer (FFKM) as it has a temperature rating of more than 450 °F (232 °C) and is one of the best know elastomers against chemical attack [74]. The seal carrier was composed of Nickle Alloy C-276 because of its ductility and its resistance to corrosion and cracks. The packer was designed to be used in casing ID of 7.625 with a nominal weight of 51.2 to 52.8 lb/ft. The qualification test was conducted on the newly designed sealing system under 25,000 psi and 500 °F (260 °C) conditions with a minimum threshold temperature of 250 °F (121 °C). The tension and compression load of 240,000 and 490,000 lbs was applied respectively. The sealing system was able to withhold the pressure at the given temperature ranges without any cracking or extrusion of the element or seal insert.

For a rolled casing in an HPHT environment, Doane, et al. (2013) [59] designed a permanent set production packer that could withstand the pressure of 20,000 psi and temperatures up to 470 °F (243 °C). It was used for a 6.625-inch casing with a nominal weight ranging from 58.8 to 60.8 lb/ft. The test was conducted with water and covered all the points in the rating envelope including an initial temperature of 470 °F (243 °C), subsequent cooling to 300 °F (149 °C), and heating back to 470 °F (243 °C). It consisted of a three-piece element system that was coupled with the radially expandable seal setting. This assembly design is beneficial as it allows the packer to set efficiently in HPHT and irregular as rolled casing condition. Tangential slips were used to minimize the stress in the packer and casing body. The element used was made up of Perfluoroelastomer (FFKM) while the seal carrier was composed of Nickle Alloy C-276. The packer was also tested against a minimum temperature of 300 °F (149 °C) while the compression and tension load were about 300,000 lb. After the validation test, no extrusion was found on the element nor in the seal insert.

It was the first permanent packer that was successfully exposed to a pressure range of 17,000 psi and 20,000 psi from the top and bottom, respectively The extension of the work from Doane, et al. (2013) [59] was continued by Taylor, et al. (2014) [75] in which the packer proposed by Doane, et al. (2013) [59] was validated against ISO14310/API11D1 grade V0 to make sure that the packer is workable in the worst-case scenario. In addition to the V0 test, a temperature cycle test having a temperature swing of 310 °F (400 °F-90 °F-400 °F) was conducted for stimulation purposes as it was required from the operator where the packer had to be installed. The performance envelope of these two studies is shown in Figure 12.

Wang, et al. (2013) [18] report packer failures that were installed in the wells located in Kuqa Foreland Basin in Western China. The reservoir was located at the depth of 5000 to 8235 m with the pressure and temperature ranging from 80 to 146 MPa and 120 to 186 MPa respectively. As the permeability of the reservoir was reduced stimulation job was conducted and pump pressure was maintained at 136 MPa. In order to avoid casing collapse, the packer was run in a high-density fluid having a specific gravity of 1.75 to 2.3. This extreme environment caused packer failure in 10 wells in the last 10 years, which piled up to greater than 160 workover days. It was analyzed that the packer failure was due to three reasons. (1). At high temperatures, the precipitation of the drilling mud takes place, which causes blockage in the piston chamber of the packer. (2) Reduced clearance gap between the packer and casing due to axial expansion of the rubber causing pump suffocation (3). The axial force acting on the packer was not correctly calculated. To manage the first problem, it was suggested that the scarping of the well should be done at least three times, 50 m above and below the casing setting depth. To avoid pump suffocation and expansion of the rubber, the displacement fluid flow rate should be controlled at 3 m/s. Furthermore, a restructure of the packer was conducted in which the OD of the packer was reduced to 108.22 mm from 110.74 mm to increase the clearance gap, which in turn will reduce the friction on the packer’s element. For the reduction of axial load on the packers, expansion joints were installed. The optimized packer was then subjected to the validation test of V0 under temperature and pressure of 232 °C and 13,053 psi, respectively. While compression of 111.13 tons and tension of 136.05 was applied. The packer passed the test and was then installed successfully in 43 wells.

Permanent set packers are considered to be more favorable for application in HPHT conditions. However, they have their drawbacks, including non-productive time for packer removal, reduced cost-effectiveness for the end user, and potential damage to the casing string during the milling operation. To overcome these problems, Suarez et al. (2017) [76] developed a retrievable packer for deep water application that can operate in pressure and temperature range of 20,000 psi and 450 °F (232 °C), respectively, with an axial load of up to 900,000 lbs. Slip saver technology was deployed to release the trapped pressure in the packer element before the slip can be retrieved. It is comprised of two independent components that work in tandem for the safe release of trapped pressure. The first component is the pressure release rubber mechanism in which the component sits radially in the recessed area provided on the mandrel, which allows the axial release of pressure trapped between the slips and packers in a controlled manner. While for the release of high radial and tangential slip load, a wedge segment was incorporated on the shoulder of the packer. To minimize the stresses on the casing because of the slips, the contact area was increased by 300% as compared to conventional packers. Whereas, to decrease collapse load on the body/mandrel, the slip load distribution was made tangential instead of radial. Before the V0 validation test at HPHT conditions, a pilot test was conducted under ambient conditions to ensure that slips would be able to bear extreme load (900,000 lbs). The result of the V0 and pilot test are shown in

Table 6. Test results of the ultra-HPHT retrievable packers [76].

Test	Description	Casing ID	Temp. Max/Min (°F)	Max Pressure Above/Below (psi)	ISO V0/V3	Notes
A	Test the slip system to a maximum axial force of 900,000 lbs and retrieve	8.875″	Ambient	N/A	N/A	Pass. Slip system withstood 900 k lbs. of applied axial force. The slips successfully retrieved post-test
B	Validate to V0 at maximum casing ID and 17,500 psi	8.875″	400/200	17,500/17,500	V0	Pass. The packer successfully met the design validation requirements of ISO14310 ANSI/API11D1 Grade V0 for 17.5 k psi differential performance from 200–400 °F
C	Validate to V0 acceptance criteria in minimum casing ID and 17,500 psi	8.500″	400/200	17,500/17,500	N/A (min ID)	Pass. The packer was successfully set at 200 °F, tested to 17.5 k psi differential per the rating envelope, gas-tight, no bubbles, and retrieved in minimum ID casing
D	Validate to V0 at maximum casing ID and 20,000 psi	8.875″	450/200	20,000/20,000	V0	Pass. The packer successfully met the design validation requirements of ISO14310 ANSI/API11D1 Grade V0 for 20 k psi differential performance from 200–450 °F

.

As seen in Table 6, tests were conducted on both minimum and maximum IDs of the casing to have a better understanding of the packer capability. The validation test was conducted with nitrogen gas as a medium. After an array of tests were performed, the packer was retrieved successfully, and it remained operational without any leakage in the given ultra-HPHT condition.

According to Patel, et al. (2019) [77] rubber seal is considered to be degradable in an HPHT environment as it loses its elasticity. On the other hand, the use of a metal-to-metal seal is not favorable due to its low elasticity. Yu et al. (2017) [78] came up with a novel Lattice seal technology that consists of a porous metallic structure, which helped to increase the elasticity by 30% and a thermoplastic matrix was developed. It was designed to work at temperatures of up to 500 °F (260 °C). For a comprehensive investigation of setting force, filler ring, and pressure differential, finite element analysis was conducted. It was found that the lattice seal was able to show chemical stability, high elasticity, incompressibility, large expansion, and resistance against the extrusion. A prototype packer was assembled for a casing ID of 6.25 inches in which the lattice packer seal assembly was installed. This prototype was successfully operational at temperatures up to 450 °F (232 °C) and 6000 psi of differential pressure.

Open hole completion is considered to be more desirable than close hole completion because of the high production rate. The challenges associated with open hole completion are off-bottom cementing, ineffective sealing in the fractured formation, and exposure to the HPHT environment [79]. However, one of the major problems in open holes is irregularities in the wellbore diameter, which are formed by large washouts during circulation and drilling operations due to which the diameter of the wellbore becomes difficult to predict [80]. On the other hand, to withstand HPHT conditions, high-rated annular barriers are used, which when set applies high radial pressure to the wellbore that often fractures the formation around the packer. Moreover, in short zonal packers, backup rings are made of strong materials and are placed on both sides of the elastomers element to prevent the extrusion of the elastomers when it is exposed to differential pressure. By taking such design into account, the reach of the elastomer to fully cover the open hole is compromised as a strong backup ring with low strain property limits its extension. Mills, et al. (2016) [81] developed a short radius hydraulically set packer for HPHT open hole condition in which a nested backup ring was used that was able to extend approx. 288% more than the conventional short radius packer while the stress level on the backup ring remained the same as of the packers of the prior generation. For the packing element, a polymeric material was used, and to access swabs off risk during tripping or high circulation, Computational Fluid Dynamics (CFD) was used. It was found that 67% of the radial pressure was reduced, which averts the swab off risk. The axial load on the packers decreased by 50% as compared to conventional ones. The packer was able to withstand pressures of 13,000 psi for gauge and 5000 psi for washout geometries of the borehole while the temperature was kept at 350 °F (177 °C) for both conditions (see Figure 13).

To increase the production flow in permeable reservoirs, fractures are induced to increase the transfer properties of the given formation and subsequently improve the recovery ratio. Fracturing operation is also common in geothermal reservoirs where the permeability is very low. In that aspect, packers play a key role as they isolate the well from the fractured region and maintain well integrity. For packers to work in deep and geothermal well fracturing operations, they should be able to withstand the HPHT environment. In that respect, Lan, et al. (2019) [82] worked on the optimization of conventional packers by using finite element analysis through Abacus and identified weak spots in its structure. In that respect, two different approaches were evaluated. For the first one, the conventional three rubber barrel structure was optimized by the addition of a protective metal cover (made of copper) over the rubber barrel to avoid shoulder protrusion, which limited the use of the conventional packer in HPHT conditions. The second approach consisted of an expandable backup ring with single barrel rubber. The rubber elements used in both structures consisted of AFLAS and HNBR. The experiment was conducted for a 6″ casing at a pressure of 70 MPa and 170 °C. It was reported that though the shoulder protrusion was avoided for three-barrel rubber, it failed under a pressure of 50 to 53 MPa. Whereas, a single barrel element with AFLAS was able to seal the pressure of 70 MPa at 170 °C at different time intervals (Figure 14), while HNBR did not work and was ruptured after being set. Therefore, it was concluded that the single rubber barrel with AFLAS material performs better in multi-stage fracturing.

For effective annular isolation of the well, a good annular barrier is required, which is commonly done by placing cement in the annulus or with swellable packers. The petroleum industry tends to lean toward cement for annular isolation, however, cementing is expensive, complex, and time-consuming. Moreover, with time, cement bonds with casing or formation can be compromised, which can create micro annuli due to dynamic changes in the formation around the wellbore such as subsidence or change in geomechanical stresses. Whereas, polymers used in swellable packers cannot resist the harsh environment and are sensitive to the activation fluid (oil or water), which can lead to premature swelling at an undesired depth. It is worth mentioning that even in favorable subsurface conditions, the swellable packers take at least 20 to 30 days to get properly placed before the production from the well can be started. Therefore, Welltec™ [83,84,85,86] introduced the Well Annular Barrier (WAB), which is a full well bore metallic swellable packer with elastomer as a sealing element that helps to mitigate the plague of sustained casing pressure (SCP) in the well. To activate the WAB, pressure is applied to the casing/liner bore on which it is installed. The packers remain unaffected by the subsurface fluid (water, gas, or oil), and the running outer diameter will not be changed until it is activated. WAB sets in less than half an hour from the surface and can be used for assurance of cement and open hole completion or can be deployed as a stand-alone barrier replacing cement. WAB has been qualified as a standalone barrier as it has passed the V3 grade test of ISO14310 [84]. Later Budisulistyo and Krumdieck (2015) [6] performed tests with axial loading of 320,000 lbf, which further strengthened the use of WAB as a stand-alone barrier in the well. With the passage of time and the success of the WAB deployed in different fields around the world, Welltec has entered into the geothermal industry and has introduced Welltec Magma Packers (WMP^®) [87] for zonal isolation of Enhanced Geothermal System (EGS). WMP comes in a single piece, which is machine sleeved and installed at the base pipe through welding. WMP is compatible with all standard casing, nominal weight, and threads. The length of the seal is up to 2 m and is made up of metal or FFKM. There is an option available for a non-elastomer seal, which is composed of Ceramic or PTFE. The operation detail of WMP is shown in

Table 7. WMP operational details for EGS [87].

	Geotermal—All Metal	Geothermal—PTFE (Spring Energizad)
Welltec® WAB®	812 Magma HT	614 Magma	812 Magma	1214 Magma
Expansion Range (mm)	8.50″ > 9.50″ (215.9 > 241.3 mm)	6.25″ > 7.20″ (158.8 > 182.9 mm)	8.50″ > 9.50″ (215.9 > 241.3 mm)	12.25″ > 13.50″ (311.1 > 342.9 mm)
Minimum Running OD (mm)	8.180″ (207.8 mm)	5.900″ (150.0 mm)	8.180″ (207.8 mm)	11.380″ (289.1 mm)
Maximum Working Pressure psi (bar)	6000 (414 bar)	5000 psi (345 bar)	10,000 psi (690 bar)	6000 psi (414 bar)
Constant element ΔP across expansion range psi (bar)	6000 (414 bar)	5000 psi (345 bar)	10,000 psi (690 bar)	6000 psi (414 bar)
Standard element lengths ft (m)	Up to 6.4 ft (2 m) packer length can be customized
Temperature range °C (°F)	300 °C (572 °F)	260 °C (500 °F)	260 °C (500 °F)	260 °C (500 °F)
Base-pipe range (up to)	7″	4 1/2″	7″	9 7/8″
ID in (mm)	Full Bore (as per base-pipe)

[87]. Expansion of the magmatic packer takes place from the surface hydraulically.

Geothermal resources are often present in formations with multiple faults that inhibit the sealing property of cement. Hence packers are required to give zonal isolation and maintain well integrity in different scenarios. Some of those scenarios are to provide zonal isolation from the cold feed or thief zone and relining of the well. Usually, in these scenarios, expandable metal seal packers are utilized, which are considered to be stronger as compared to packers having an elastomer sealing. Moreover, the thermal stability of the metal is much higher than the best-known polymer, as it does not lose its mechanical properties when exposed to a high-temperature environment. However, the limitation of metal packers is that it does not provide good sealing when installed in rolled or corroded casing, and due to the high differential pressure the corrosive fluid can leak through the element and further degrade the already compromised casing. Roy, et al. (2022) [88] presented a concept in which the elastomer was encapsulated in an insulated flexible gel that has a low thermal conductivity, which acts as a protective layer to protect the elastomer from a high-temperature geothermal environment. It is predicted that the temperature of the core in which the elastomer will be present will not have a temperature greater than 400 °F (204 °C) while the temperature in the surrounding can be >750 °F (399 °C). This whole system is placed in the flexible nano metallic Grain Body Engineer (GBE) that prevents it from the hostile fluid. This new system is set to be tested at the subcomponent level to prove its viability and then the full packer system with three stacks of elements and anti-extrusion rings will be integrated together to show its working at 15,000 psi and 750 °F (399 °C).

JRG Energy (2022) [57] has launched a retrievable packer for the geothermal well that can be set on drill pipe, tubing, or coil tubing. The failsafe deflation and latch fish neck mechanisms ensure the ease of retrieving the packer with the help of slickline from the damaged or obstructed casing. The packer can be used for the temperature and differential pressure range of 150 °C and 4,931 psi, respectively, and can be installed in the casing ID of 3.0″ to 12.75″. The length of the packer is about 2.3 m in which sealing element is 1.6 m. The premature setting of the packer is avoided by the protection system installed on the shear valve. A double-check valve is also available for reliable operation. Packerplus (2022) [89] introduced Titanium XV packers, which are capable of enduring the temperature of 315 °C and the differential pressure of 15,000 psi. It has been successfully deployed for the stimulation of the geothermal well compromised of the granitic bedrock in Helsinki, Finland.

For the estimation of pressure difference and axial loading across the packers, a dimensionless formulation was proposed by Li, et al. (2021) [67] in which 10 controllable factors were evaluated. It was found that the most influencing factors include mechanical forces, production rate, thermophysical properties of the fluid, and tubing thermal expansion coefficient. Whereas, Poisson’s ratio and elastic modulus of the tubing, the cross section of the annulus between the tubing and the casing has a minute impact on the pressure difference and axial forces. To overcome these forces, two mitigation methods were proposed, which include the installation of a slip joint that reduces or removes the length adjustment tendency of the tubing. Thus, axial force applied due to the changing length of the tubing can be controlled. Whereas injection of nitrogen gas in the annulus between the tubing and the casing decreases the annular pressure and will reduce the differential pressure across the packer. This approach increases the safety window of the axial force.

Table 8. Summary of the designed HPHT packers and sealing system.

Author	Packer/Sealing System	Element	Minimum Temperature (°F)	Maximum Temperature (°F)	Pressure (psi)	Tension/Compression (lbs)	Casing ID (Inches)	Challenges	Novelty/Solution
Dreeesen, et al. (1988) [70]	Open hole retrievable packers	Elastomer	300	500	5450	N/A	9.2 (open hole)	Two parallel wells were to be connected through the fracturing in the impermeable layers. The conventional packers failed to perform the stimulation job	Elastomer and steel expansion element were integrated as a single packer and was able to connect the two wells through stimulation job
Robb and Valentine (2010) [73]	Permanent	AFLAS	343	450	15,000	400,000/400,000	9.625	Due to the worn-out casing in HPHT well the packer failed, and leakage happened	Developed a permanent packer design that was tested successfully in the worn-out casing
Doane, et al.(2012) [60]	Sealing system mounted on packer chassis	Perfluoro elastomer	250	450	25,000	240,000/490,000	7.625	The rubber element in the conventional packer becomes soft and extrudes over the backup ring in HPHT condition, which hinders the contact of the backup ring with the casing ID	The sealing system combined the design of ZXP and Premier packers
Doane, et al. (2013) [59]	Permanent	Perfluoro elastomer	300	470	20,000	300,000/300,000	6.625	Conventional packers have not shown good performance in the as-rolled casing	The packer consisted of three-piece element system that was coupled with the radially expandable seal setting. It was successfully tested in the as-rolled casing
Bårdsen, et al. (2014) [84]	Permanent	Elastomer	20	90	5000	300,000/300,000	Full bore	Effective annular isolation of the well	Full well bore metallic swellable packer with elastomer as a sealing element
Mills, et al. (2016) [81]	Hydraulically set short radius packer for open hole	Polymeric material	200	350	13,000	N/A	N/A	The backup ring in the short radius packer limits the extension of the elastomers	A nested backup ring was designed, which allowed the extension of 288% more than the conventional short radius packer
Suarez, et al. (2017) [76]	Retrievable	N/A	200	450	20,000	900,000/900,000	8.875	Use of retrieval packers in ultra-HPHT condition	Slip saver technology was deployed in the packer to release the trapped pressure in the packer element before the slips can be retrieved
Yu, et al. (2017) [78]	Model-D packer element systems	Porous Metallic structure	N/A	450	6000	50,000 (setting force)	6.25	The rubber seal is degradable in an HPHT environment while the metal-to-metal seal is not favorable due to its low elasticity	Developed thermoplastic-Lattice metal composite seal
Lan, et al. (2019) [82]	Sealing system	AFLAS and HNBR	N/A	170	70	N/A	6	Multistage fracturing in horizontal well	Single barrel rubber with expandable ring for multistage fracturing in horizontal well
Roy, et al. (2022) [88]	Sealing system and packer (Still in pilot phase)	Elastomer	N/A	>750	15,000	N/A	N/A	The limitation of metal packers is that it does not provide good sealing when installed in rolled or corroded casing	Elastomer encapsulated in an insulated flexible gel that has a low thermal conductivity that acts as a protective layer. Then placed in flexible nano metallic Grain Body Engineered (GBE)

summarizes the packer review performed in this paper.

11. Conclusions

Geothermal energy is making its impression on the world with America being at the forefront of power generation from geothermal resources while Iceland leading with TJ/year/population. It is expected that by 2030 to 2050, renewable energy generated by the USA alone from geothermal resources will exceed 60 GW. However, there are many challenges along the way. The biggest one is the complexity of drilling and completion of a geothermal well, which is much more challenging than that of oil and gas wells. It is reported that around 50% of the total cost of geothermal wells is spent on drilling and completion as these are the factors on which the integrity of the well depends. Therefore, for effective zonal isolation, different tests have been recommended on packers by ISO and API, in which V6 grade is the lowest rated and V0, which consists of a gas-tight test, is the highest rated. Packers have their limitations when exposed to an HPHT environment hence different designs to mitigate those problems have been discussed. Though most of the illustrated packers are from the HPHT oil and gas well, the packers designed by Welltec™ (Welltec Magma Packers (WMP^®)) are made exclusively for geothermal well applications and have the capacity to operate at the subsurface condition of 10,000 psi and 300 °C. Additionally, a case study on Packerplus Titanium XV has reported a successful stimulation job in a geothermal well at a differential pressure of 15,000 psi and 315 °C. With the wide adoption of geothermal energy, many companies are now focusing on developing packers suitable for the HPHT environment. In the coming future, geothermal will be contributing more toward renewable energy, as this is the only source of energy that is not affected by metrological changes.

A new testing protocol with a focus on geothermal applications is not only desired but necessary in order to offer qualified packers for geothermal applications and furthermore to improve the reliability of these tools.