# Hydraulic Stimulation of Enhanced Geothermal System: A Case Study at Patuha Geothermal Field, Indonesia

Authors: Sangdon Lee; Wisup Bae; Asep K. Permadi; Changhyup Park
Journal: International Journal of Energy Research
 (2023)

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## Abstract

This paper discusses a case study on the enhanced geothermal system (EGS), which entails a hydraulic stimulation at Patuha geothermal field, West Java, Indonesia. Patuha field is a volcano-hosted vapor-dominated geothermal system. A hydraulic stimulation was designed with 6,360 m3 (=40,000 barrels) of water injection to evaluate the enhancement in steam production. The water injection was conducted in three phases: a step-up period, a plateau period with a constant rate, and a step-down period, which raised the bottom hole pressure effectively and positively influenced formation. In addition, in EGS, rapid restorations of pressure and temperature to their pretest values near the bottom hole were observed, unlike in a typical nonvolcanic system. Hall plots, i.e., the Hall integral and Hall derivative, confirmed that the geothermal reservoir was stimulated, and thus, the hydraulic stimulation increased the steam production up to 11.4% at other production wells that were located near the cold-water injector.


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## Body

## 1. Introduction

Regions with abundant geothermal energy are associated with high volcanic and tectonic activity, e.g., the Ring of Fire. A vapor-dominated system produces only steam with less pore pressure. In a typical vapor-dominated field, an impermeable cap rock seals the heated underground water and prevents it from escaping to the surface. The heated water then becomes vapor and is contained in the permeable reservoir beneath the cap rock. Due to the combined effect of insufficient seal integrity and heated underground water, most geothermal resources are underpressured [1–3]. Additionally, most geothermal reservoirs contain natural fractures that result in highly permeable reservoirs [4]. These conditions incur a higher risk of lost circulation during drilling processes. Considering that most geothermal wells are drilled directionally, losing a well creates additional economic risk. Generally, a vapor-dominated geothermal field experiences a rapid depletion of steam production [2, 3].Patuha geothermal field, located in West Java, Indonesia, has a distinct vapor-dominated reservoir. It is in the quaternary volcanic arc, along with other currently developed fields in Indonesia, e.g., Dieng, Darajat, Kamojang, Wayang-Windu, Gunung Salak, and Karaha-Bodas [5–9]. Geological, geochemical, and geophysical field surveys have been conducted in Patuha field by Pertamina, the Indonesian national oil company, since 1983. Geo Dipa Energi, an Indonesian state-run geothermal power generation company and the current operator of Patuha field, has explored geothermal resources and drilled the wells [10–15]. The formation of the vapor-dominated layer in Patuha is approximately 0.5 km thick at 1 km depth above sea level (asl), and its temperature is between 200°C and 240°C [8, 9, 11, 12]. The magmatic steam plume, including corrosive gas, moves upward through the center, and the steam spreads laterally in the permeable vapor-dominated reservoir. There is a liquid-dominated zone underlying the vapor zone, which is a very dilute steam condensate [3, 5, 14, 15]. Patuha started producing electricity in September 2014, with a dry steam cycle of approximately 60 MWe power generation capacity. Sixty-eight percent of the steam produced in a steam cycle was vented into the atmosphere, while the remainder was injected back into the reservoir through injection wells to maintain the reservoir pressure. The steam production rate of Patuha geothermal field continues to decline by approximately 6% annually [10–15]. The water level rises as the steam production continues. There is substantial literature on how to improve the reinjection scheme to achieve maximum sustainability of geothermal power production by maximizing the condensation process and avoiding an early thermal breakthrough within the reservoir. However, despite efforts to achieve sustainability, some make-up wells must be drilled according to a predesigned drilling schedule to harness the entire potential of steam production. Additionally, reaming operations can effectively remove scale deposition that reduces a well’s productivity [14–19].An enhanced geothermal system (EGS), based on hydraulic or acid fracturing at the depleted wells, has the potential to improve steam production [20–26]. Water is injected, after which the well is shut in for a specific interval of time. Upon reopening, the mass productivity of the well is increased for a while. This method has been publicly demonstrated but is not recommended because it deteriorates the casing integrity over time [20, 23]. Practically, water injection has been implemented to improve well injectivity in Gunung Salak, a liquid-dominated volcano-hosted geothermal field [24–26]. An optimal design of injecting water can secure the sustainability of steam production. However, because vapor-dominated reservoirs are rare, the effects of hydraulic stimulation are limited [27, 28].This study considered the low steam production of the well to be attributed to the lack of permeability or supply of steam. Based on increasing steam productivity through hydraulic stimulation, i.e., hydraulic fracturing to enhance the permeability near the wellbore, a short-term hydraulic stimulation test was designed to examine whether injecting water would enhance the permeability of the rock in a vapor-dominated geothermal reservoir. This paper presents insights from hydraulic stimulation, which included improving well productivity and reservoir management at the vapor-dominated reservoir.


## 2. Materials and Methods

The Patuha field power plant is located at an elevation of 1,995 m asl. Various surface manifestations, e.g., hot springs, fumaroles, and craters, exist within the Patuha field. Its main volcanic heat source is Mt. Patuha, which has andesitic stratovolcanic rock formations. Regional geology is dominated by quaternary volcanic rocks, which cover most of the field, and tertiary sedimentary rock. The relatively young volcanic rocks chronologically blanket major faults in the area. The outflows of geothermal fluids incur hydrothermal alternation where they contact the upper rock formation. The most common classifications of hydrothermal alternation are argillic and phyllic mica facies [3–5, 10–15].Figure1 describes the well locations, well trajectories, and faults for hydraulic stimulation. The temperature core hole (TCH) enables the measurement of temperature with depth. Water is injected during the nonproductive period of the well; injecting water into highly productive wells might reduce steam production. Therefore, the injection must be implemented on inactive, reinjection, or production wells with relatively low steam production [15]. PPL-6, a subcommercial well, was selected for water injection into the reservoir to achieve high enthalpy (Table 1). PPL-6 had the highest maximum temperature, 221°C, at the bottom hole among all the candidate wells. The PPL-6 well, a directional well, was also close to the condensate tank, which was situated within the power plant area. Two slotted liners were installed: the first (upper) liner was 27.31 cm (=10.75 in) and was installed from 692 m (top of liner) to 1,854 m (liner shoe), and the other liner was 17.78 cm (=7 in) from 1,802 m to 2,536 m. PPL-6 has been continuously producing approximately 10 tons/h contributing only 1.4 MWe to the overall power generation, but its current production is inadequate for commercial application [14, 15].Figure 1
Locations of some wells in the Patuha field. PPL-6 is a well for hydraulic stimulation, i.e., water injection.Table 1
Well information of PPL-6.
Maximum bottom hole temperatureSteam pressureElevation (m asl)Top of liner (m)Measured depth (m)Completion typeMaximum wellhead pressure221°C23.3 bars2001.6770.02536.85Slotted liner137.9 bars


### 2.1. Pressure and Temperature Survey prior to Hydraulic Stimulation

According to a pressure and temperature survey conducted in 2015, at a water level of approximately 1,710 m, the maximum temperature was 220°C, and the pressure was 23.58 bars (=342 psi (lb/in2)). Figure 2 demonstrates the results of the pressure and temperature survey conducted before hydraulic stimulation. As steam is produced, temperature and pressure decrease, and the water level inside the well increases. The water level was at approximately 1,670 m asl, where the pressure was 18.96 bars (=275 psi) and the temperature was 208°C. Temperature fluctuations could be observed a few meters above the water level. The fluctuation temperature reached a maximum of 215°C at approximately 1,500 m. Because the temperature in this particular interval was above the saturation temperature, this zone was identified as a superheated zone. The temperature profile showed a maximum temperature of 217°C, which steadily decreased with depth.Figure 2
Pressure and temperature profiles with depth of PPL-6 conducted prior to hydraulic stimulation: (a) pressure distribution; (b) temperature distribution.
(a)(b)


### 2.2. Design of Hydraulic Stimulation: Water Injection Schedule

First, the wellhead was shut off to recover the natural temperature and pressure of the well and measure these parameters under static conditions. The well took approximately 24 h to recover its stabilized static condition. Next, quenching was performed by injecting cold water to cease steam production in the well during the opening of the wellhead. Pressure, temperature, and spinner (PTS) surveys were performed to observe the permeable zone. Finally, a step rate injection test was performed while lowering the PTS tool in the bottom hole to observe the response of the well in real time. The water utilized for quenching was obtained from the power plant condensate. The tank had a capacity of 2,385 m3 (=15,000 barrels) with an average daily condensate production of 117 tons/h. Pressure gauges were installed at the casing shoe, wellhead, and pumps.A total of 40,000 barrels (bbl) of cold water was injected for 22 h. The process was divided into three phases or periods: 3.3 h (=3 h and 20 min) of step-up period, 15 h of constant injection rate period (the plateau zone), and 3.7 h (=3 h and 40 min) of step-down period. The flow rates were 3.18 m3/min (=20 bbl/min) for the first 55 min, 3.66 m3/min (=23 bbl/min) for the next 90 min, and 4.93 m3/min (=31 bbl/min) for the last 55 min of the step-up period. Subsequently, the injection continued at 4.13 m3/min (=26 bbl/min) for 15 h during the constant injection rate period. Finally, the step-down injection rates were 23, 20, 15, 10, and 5 bbl/min (in the field unit) until the pumping stopped (Table 2). The other wells and their steam production continued to be observed during the injection period to evaluate the effects of hydraulic stimulation.Table 2
Schedule of water injection for the short-term hydraulic stimulation.
PeriodTime (min)Water injection ratem3/minbbl1/minStep-up0–553.182055–1453.6623145–2004.9331Plateau200–10854.1326Step-down1085–11303.66231130–11903.18201190–12352.39151235–12951.59101295–13250.8051325–1422001“bbl” stands for barrel (1barrel=0.159m3).


### 2.3. Evaluation of Hydraulic Stimulation

The Hall integral and its derivative are commonly used to monitor waterflooding activities in oil and gas fields [24, 29–34]. The Hall integral (HI) is the integral over time of the difference between the well-flowing pressure (bottom hole pressure; pwf) and the reservoir pressure (p¯) defined by Equation (1), and the Hall derivative (DHI) is defined by Equation (2):
(1)HI=∫0tpwf−p¯dt=Bwμln0.472re/rw+s2πkh∫0tWidt,(2)DHI=dHIdlnWi.In Equation (1), Wi is the water volume injected. Bw, μ, k, h, re, rw, and s are the formation volume factor of water, viscosity, permeability, payzone thickness, effective radius, well radius, and skin factor, respectively. In Equations (1) and (2), “ln” represents the natural logarithm. Equation (1) was derived assuming a steady-state radial Darcy flow. In the Cartesian plane, the Hall plot represents both HI and DHI versus the cumulative water volumes to evaluate the flow restriction or stimulation. The trajectory of DHI tracking below HI represents the occurrence of fracture and the generation of negative skin. By contrast, DHI tracking above HI is due to the plugging or positive skin [24, 32, 33].


## 2.1. Pressure and Temperature Survey prior to Hydraulic Stimulation

According to a pressure and temperature survey conducted in 2015, at a water level of approximately 1,710 m, the maximum temperature was 220°C, and the pressure was 23.58 bars (=342 psi (lb/in2)). Figure 2 demonstrates the results of the pressure and temperature survey conducted before hydraulic stimulation. As steam is produced, temperature and pressure decrease, and the water level inside the well increases. The water level was at approximately 1,670 m asl, where the pressure was 18.96 bars (=275 psi) and the temperature was 208°C. Temperature fluctuations could be observed a few meters above the water level. The fluctuation temperature reached a maximum of 215°C at approximately 1,500 m. Because the temperature in this particular interval was above the saturation temperature, this zone was identified as a superheated zone. The temperature profile showed a maximum temperature of 217°C, which steadily decreased with depth.Figure 2
Pressure and temperature profiles with depth of PPL-6 conducted prior to hydraulic stimulation: (a) pressure distribution; (b) temperature distribution.
(a)(b)


## 2.2. Design of Hydraulic Stimulation: Water Injection Schedule

First, the wellhead was shut off to recover the natural temperature and pressure of the well and measure these parameters under static conditions. The well took approximately 24 h to recover its stabilized static condition. Next, quenching was performed by injecting cold water to cease steam production in the well during the opening of the wellhead. Pressure, temperature, and spinner (PTS) surveys were performed to observe the permeable zone. Finally, a step rate injection test was performed while lowering the PTS tool in the bottom hole to observe the response of the well in real time. The water utilized for quenching was obtained from the power plant condensate. The tank had a capacity of 2,385 m3 (=15,000 barrels) with an average daily condensate production of 117 tons/h. Pressure gauges were installed at the casing shoe, wellhead, and pumps.A total of 40,000 barrels (bbl) of cold water was injected for 22 h. The process was divided into three phases or periods: 3.3 h (=3 h and 20 min) of step-up period, 15 h of constant injection rate period (the plateau zone), and 3.7 h (=3 h and 40 min) of step-down period. The flow rates were 3.18 m3/min (=20 bbl/min) for the first 55 min, 3.66 m3/min (=23 bbl/min) for the next 90 min, and 4.93 m3/min (=31 bbl/min) for the last 55 min of the step-up period. Subsequently, the injection continued at 4.13 m3/min (=26 bbl/min) for 15 h during the constant injection rate period. Finally, the step-down injection rates were 23, 20, 15, 10, and 5 bbl/min (in the field unit) until the pumping stopped (Table 2). The other wells and their steam production continued to be observed during the injection period to evaluate the effects of hydraulic stimulation.Table 2
Schedule of water injection for the short-term hydraulic stimulation.
PeriodTime (min)Water injection ratem3/minbbl1/minStep-up0–553.182055–1453.6623145–2004.9331Plateau200–10854.1326Step-down1085–11303.66231130–11903.18201190–12352.39151235–12951.59101295–13250.8051325–1422001“bbl” stands for barrel (1barrel=0.159m3).


## 2.3. Evaluation of Hydraulic Stimulation

The Hall integral and its derivative are commonly used to monitor waterflooding activities in oil and gas fields [24, 29–34]. The Hall integral (HI) is the integral over time of the difference between the well-flowing pressure (bottom hole pressure; pwf) and the reservoir pressure (p¯) defined by Equation (1), and the Hall derivative (DHI) is defined by Equation (2):
(1)HI=∫0tpwf−p¯dt=Bwμln0.472re/rw+s2πkh∫0tWidt,(2)DHI=dHIdlnWi.In Equation (1), Wi is the water volume injected. Bw, μ, k, h, re, rw, and s are the formation volume factor of water, viscosity, permeability, payzone thickness, effective radius, well radius, and skin factor, respectively. In Equations (1) and (2), “ln” represents the natural logarithm. Equation (1) was derived assuming a steady-state radial Darcy flow. In the Cartesian plane, the Hall plot represents both HI and DHI versus the cumulative water volumes to evaluate the flow restriction or stimulation. The trajectory of DHI tracking below HI represents the occurrence of fracture and the generation of negative skin. By contrast, DHI tracking above HI is due to the plugging or positive skin [24, 32, 33].


## 3. Results and Discussion

### 3.1. Hydraulic Stimulation at a Vapor-Dominated Reservoir

The bottom hole pressure was measured as a response to the predesigned injection rates (Table2). The recorded pressures showed a specific trend: due to the nature of flow in the reservoir, the pressure increased with time for a few moments until a stabilized flow was reached. A constant rate was applied to the reservoir, and stabilized pressure responses were recorded. The pressure response was plotted in a Cartesian graph for the slope measurement to represent the injectivity. A single liquid phase fluid that passes through a permeable medium normally shows an increasing linear trend, which follows Darcy’s law.Figure3 shows the changes in bottom hole pressure and temperature with changes in the water injection flow rate. The overall bottom hole pressure was approximately 6 bars, but some peaks and fluctuations were observed: the bottom hole pressure increased sharply after 2 h and 24 min from water injection, which is approximately the point of fracture opening, while at the later time, the fluctuation of the bottom hole pressure represented phase changes due to the mixture of vapor and water. When opening fractures, both pressure and temperature increased dramatically. This can be attributed to the high-temperature steam in the geothermal reservoir contacting the injected water. This sudden increase in pressure and temperature is very characteristic of hydraulic stimulation in a conversion zone. By contrast, hydraulic stimulation in nonvolcanic zones typically showed a gradual rise in bottom hole pressure [16, 30, 34].Figure 3
Results of hydraulic stimulation: (a) water injection rates; (b) bottom hole pressures; (c) bottom hole temperatures.
(a)(b)(c)


#### 3.1.1. First Phase: Step-Up Water Injection Rates

Pressure response toward the step-up injection rate revealed a large jump initially followed by a slow decrease in value. This indicates that the permeability in the well was high enough to absorb the injected water, thus leaving a small amount of water to build up the water column inside the well (Figure4). Although a loss of control was reported during the drilling of PPL-6, no issues were encountered in water injection during this time.Figure 4
Responses of step-up water injection rates: (a) water injection rates; (b) bottom hole pressures; (c) bottom hole temperature with time.
(a)(b)(c)The injection process was smooth in step-up injection, and stabilized flow could be achieved even without determining the minimum injection rate. An increase in pressure was observed when the flow rate was increased, with the peak at approximately 9.31 bars (=135 psi). These pressures were still below the reservoir pressure, which ensured that the injection process was smooth. A step-up rate test was used to determine the fracture closure pressure in the formation, and the results indicated that a wider fracture width resulted in overall higher formation permeability. The temperature response decreased with only a few fluctuations (Figure4(c)). These fluctuations occurred in conjunction with the pressure response and were possibly from convective heat transfer; all the reservoir temperature lines were placed below the saturation temperature, which implies that the fluid phase of the reservoir is liquid.


#### 3.1.2. Middle Phase: Plateau Constant Rate

During the constant injection rate period, a constant pressure of approximately 5.52 bars (=80 psi, Figure3(b)) was observed. Additionally, no remarkable pressure build-up was observed; the pressure responses oscillated between 5.45 bars (=79 psi) and 5.65 bars (=82 psi), which is a very slight change. This indicates that the reservoir could take water without disrupting the reservoir properties. The temperature decreased slightly, which was the desired outcome because the injected water was colder than the reservoir fluid. The temperature at the plateau zone was below the saturation temperature.


#### 3.1.3. Late Phase: Step-Down Water Injection Rates

The step-down injection rates indicated that steam inflow at a minimum rate of 2.39 m3/min (=15 bbl/min; 1,190 minutes) must be maintained during the quenching process to prevent any premature well reactivation (Figures 5(a) and 5(b)). During the initial injection of cold water, the liquefied steam boiled again due to the small amount of injection, which is referred to as “reactivation” here. A quenching process was required to prevent steam from flowing out of the wellbore in the initial stages of water injection. When the injection rate was <2.39 m3/min, steam could still be observed, and therefore, the quenching process did not work. As shown in Figure 5(c), vapor and liquid phases coexisted at 2.39 m3/min and 1.59 m3/min (=10 bbl/min) injection rates, and after 0.80 m3/min (=5 bbl/min), only the vapor phase was observed.Figure 5
Responses of step-down water injection rates: (a) water injection rates; (b) bottom hole pressures; (c) bottom hole temperature with time.
(a)(b)(c)The unstable fluctuation in pressure and the rapid increase in temperature indicated the changes in flow status, i.e., phase changes (Figure5(c)), and implied that part of the steam influx entered the wellbore as early as 1190 min; the two fluids, i.e., the injected cold water and the steam in the reservoir, were mixed rapidly.


### 3.2. Conclusions from Hydraulic Stimulation

Figure6 demonstrates a Hall plot, i.e., the Hall integral and its derivative in the Cartesian plane, to evaluate the effect of hydraulic stimulation. As observed in the graph, the Hall derivative was below the Hall integral, which confirms that the formation was stimulated, and hence, water injection could enhance reservoir productivity, i.e., increase the reservoir permeability. It is estimated that fractures occurred and flow paths were secured when 636 m3 (=4,000 bbl) of cumulative water was injected. After 954 m3 (=6,000 bbl) of water was injected, the Hall derivative increased monotonically, which confirms that the hydraulic stimulation was effective in enhancing the geothermal reservoir through waterflooding.Figure 6
Hall plot confirming the stimulation of the reservoir.An increase in steam production was also observed in the surrounding wells. PPL-2 was closest to PPL-6 (Figure1), and thus, the subsurface open section of PPL-2 could be influenced expeditiously. The averaged mass flow rate at PPL-2 increased from 46.99 tons/h to 51.5 tons/h, a 9.6% increase owing to hydraulic stimulation (Figure 7(a)). This was a result of comparing the steam production before (averaged for 9 d) and after hydraulic stimulation at PPL-6. Despite PPL-4 being located relatively far from the water injector, PPL-4 was connected to the water injector by some faults within the productive zone. Its steam production also increased by 11.4% (Figure 7(b)).Figure 7
Improvement of mass flow rates at other wells due to the hydraulic stimulation at PPL-6: (a) mass flow rate observed at PPL-2; (b) mass flow rate observed at PPL-4. The dotted horizontal line represents the average mass flow rate before hydraulic stimulation. The red dotted box indicates the period of hydraulic stimulation at PPL-6.
(a)(b)After hydraulic stimulation at PPL-6, an overall increase in power generation from 50.0 MWe to 56.3 MWe was observed. Additionally, it was confirmed that the amount of excessive generation was proportional to the volume of water injected. These results imply that hydraulic stimulation at volcano-hosted vapor-dominated reservoirs is efficient in improving steam productivity.


### 3.3. Discussion

A typical hydraulic stimulation in a nonvolcanic zone leads to a considerable pressure increase from the starting point of water injection until the fractures are opened, and when hydraulic stimulation achieves critical pressure and the fractures are opened, the pressure drops significantly. However, in the volcano-hosted vapor-dominated reservoir, hydraulic stimulation led to a slight rise in pressure until the fractures opened. This could be due to already-formed natural fractures or fractures with reduced permeability. Even after the fractures were opened, the bottom hole pressure returned to its original level. Another important conclusion that can be drawn from this hydraulic stimulation is that injector location, well stability conditions, and water supply potential are also critical factors to consider when designing an EGS.Long-term water injection is required to confirm whether the hydraulic stimulation at Patuha field is commercial. An increase in steam production was observed by injecting 6,360 m3 (=40,000 bbl) water for 22 h, but this effect may not be sustainable. The optimal designs of hydraulic stimulation in this study are imprecise because the stimulated reservoir volume, i.e., the rock volume influenced by water injection, was not fully analyzed with tracer tests or microseismic surveillance [35]. This study indirectly estimated the fracture opening using the trajectories of pressure and temperature; however, more experimental analyses, e.g., the fracturing mechanism, stimulated reservoir volume, and core analyses, are required in the future. A reliable estimation of geomechanical features and reservoir heterogeneity must be conducted to obtain the optimal design of hydraulic fracturing techniques.


## 3.1. Hydraulic Stimulation at a Vapor-Dominated Reservoir

The bottom hole pressure was measured as a response to the predesigned injection rates (Table2). The recorded pressures showed a specific trend: due to the nature of flow in the reservoir, the pressure increased with time for a few moments until a stabilized flow was reached. A constant rate was applied to the reservoir, and stabilized pressure responses were recorded. The pressure response was plotted in a Cartesian graph for the slope measurement to represent the injectivity. A single liquid phase fluid that passes through a permeable medium normally shows an increasing linear trend, which follows Darcy’s law.Figure3 shows the changes in bottom hole pressure and temperature with changes in the water injection flow rate. The overall bottom hole pressure was approximately 6 bars, but some peaks and fluctuations were observed: the bottom hole pressure increased sharply after 2 h and 24 min from water injection, which is approximately the point of fracture opening, while at the later time, the fluctuation of the bottom hole pressure represented phase changes due to the mixture of vapor and water. When opening fractures, both pressure and temperature increased dramatically. This can be attributed to the high-temperature steam in the geothermal reservoir contacting the injected water. This sudden increase in pressure and temperature is very characteristic of hydraulic stimulation in a conversion zone. By contrast, hydraulic stimulation in nonvolcanic zones typically showed a gradual rise in bottom hole pressure [16, 30, 34].Figure 3
Results of hydraulic stimulation: (a) water injection rates; (b) bottom hole pressures; (c) bottom hole temperatures.
(a)(b)(c)


### 3.1.1. First Phase: Step-Up Water Injection Rates

Pressure response toward the step-up injection rate revealed a large jump initially followed by a slow decrease in value. This indicates that the permeability in the well was high enough to absorb the injected water, thus leaving a small amount of water to build up the water column inside the well (Figure4). Although a loss of control was reported during the drilling of PPL-6, no issues were encountered in water injection during this time.Figure 4
Responses of step-up water injection rates: (a) water injection rates; (b) bottom hole pressures; (c) bottom hole temperature with time.
(a)(b)(c)The injection process was smooth in step-up injection, and stabilized flow could be achieved even without determining the minimum injection rate. An increase in pressure was observed when the flow rate was increased, with the peak at approximately 9.31 bars (=135 psi). These pressures were still below the reservoir pressure, which ensured that the injection process was smooth. A step-up rate test was used to determine the fracture closure pressure in the formation, and the results indicated that a wider fracture width resulted in overall higher formation permeability. The temperature response decreased with only a few fluctuations (Figure4(c)). These fluctuations occurred in conjunction with the pressure response and were possibly from convective heat transfer; all the reservoir temperature lines were placed below the saturation temperature, which implies that the fluid phase of the reservoir is liquid.


### 3.1.2. Middle Phase: Plateau Constant Rate

During the constant injection rate period, a constant pressure of approximately 5.52 bars (=80 psi, Figure3(b)) was observed. Additionally, no remarkable pressure build-up was observed; the pressure responses oscillated between 5.45 bars (=79 psi) and 5.65 bars (=82 psi), which is a very slight change. This indicates that the reservoir could take water without disrupting the reservoir properties. The temperature decreased slightly, which was the desired outcome because the injected water was colder than the reservoir fluid. The temperature at the plateau zone was below the saturation temperature.


### 3.1.3. Late Phase: Step-Down Water Injection Rates

The step-down injection rates indicated that steam inflow at a minimum rate of 2.39 m3/min (=15 bbl/min; 1,190 minutes) must be maintained during the quenching process to prevent any premature well reactivation (Figures 5(a) and 5(b)). During the initial injection of cold water, the liquefied steam boiled again due to the small amount of injection, which is referred to as “reactivation” here. A quenching process was required to prevent steam from flowing out of the wellbore in the initial stages of water injection. When the injection rate was <2.39 m3/min, steam could still be observed, and therefore, the quenching process did not work. As shown in Figure 5(c), vapor and liquid phases coexisted at 2.39 m3/min and 1.59 m3/min (=10 bbl/min) injection rates, and after 0.80 m3/min (=5 bbl/min), only the vapor phase was observed.Figure 5
Responses of step-down water injection rates: (a) water injection rates; (b) bottom hole pressures; (c) bottom hole temperature with time.
(a)(b)(c)The unstable fluctuation in pressure and the rapid increase in temperature indicated the changes in flow status, i.e., phase changes (Figure5(c)), and implied that part of the steam influx entered the wellbore as early as 1190 min; the two fluids, i.e., the injected cold water and the steam in the reservoir, were mixed rapidly.


## 3.1.1. First Phase: Step-Up Water Injection Rates

Pressure response toward the step-up injection rate revealed a large jump initially followed by a slow decrease in value. This indicates that the permeability in the well was high enough to absorb the injected water, thus leaving a small amount of water to build up the water column inside the well (Figure4). Although a loss of control was reported during the drilling of PPL-6, no issues were encountered in water injection during this time.Figure 4
Responses of step-up water injection rates: (a) water injection rates; (b) bottom hole pressures; (c) bottom hole temperature with time.
(a)(b)(c)The injection process was smooth in step-up injection, and stabilized flow could be achieved even without determining the minimum injection rate. An increase in pressure was observed when the flow rate was increased, with the peak at approximately 9.31 bars (=135 psi). These pressures were still below the reservoir pressure, which ensured that the injection process was smooth. A step-up rate test was used to determine the fracture closure pressure in the formation, and the results indicated that a wider fracture width resulted in overall higher formation permeability. The temperature response decreased with only a few fluctuations (Figure4(c)). These fluctuations occurred in conjunction with the pressure response and were possibly from convective heat transfer; all the reservoir temperature lines were placed below the saturation temperature, which implies that the fluid phase of the reservoir is liquid.


## 3.1.2. Middle Phase: Plateau Constant Rate

During the constant injection rate period, a constant pressure of approximately 5.52 bars (=80 psi, Figure3(b)) was observed. Additionally, no remarkable pressure build-up was observed; the pressure responses oscillated between 5.45 bars (=79 psi) and 5.65 bars (=82 psi), which is a very slight change. This indicates that the reservoir could take water without disrupting the reservoir properties. The temperature decreased slightly, which was the desired outcome because the injected water was colder than the reservoir fluid. The temperature at the plateau zone was below the saturation temperature.


## 3.1.3. Late Phase: Step-Down Water Injection Rates

The step-down injection rates indicated that steam inflow at a minimum rate of 2.39 m3/min (=15 bbl/min; 1,190 minutes) must be maintained during the quenching process to prevent any premature well reactivation (Figures 5(a) and 5(b)). During the initial injection of cold water, the liquefied steam boiled again due to the small amount of injection, which is referred to as “reactivation” here. A quenching process was required to prevent steam from flowing out of the wellbore in the initial stages of water injection. When the injection rate was <2.39 m3/min, steam could still be observed, and therefore, the quenching process did not work. As shown in Figure 5(c), vapor and liquid phases coexisted at 2.39 m3/min and 1.59 m3/min (=10 bbl/min) injection rates, and after 0.80 m3/min (=5 bbl/min), only the vapor phase was observed.Figure 5
Responses of step-down water injection rates: (a) water injection rates; (b) bottom hole pressures; (c) bottom hole temperature with time.
(a)(b)(c)The unstable fluctuation in pressure and the rapid increase in temperature indicated the changes in flow status, i.e., phase changes (Figure5(c)), and implied that part of the steam influx entered the wellbore as early as 1190 min; the two fluids, i.e., the injected cold water and the steam in the reservoir, were mixed rapidly.


## 3.2. Conclusions from Hydraulic Stimulation

Figure6 demonstrates a Hall plot, i.e., the Hall integral and its derivative in the Cartesian plane, to evaluate the effect of hydraulic stimulation. As observed in the graph, the Hall derivative was below the Hall integral, which confirms that the formation was stimulated, and hence, water injection could enhance reservoir productivity, i.e., increase the reservoir permeability. It is estimated that fractures occurred and flow paths were secured when 636 m3 (=4,000 bbl) of cumulative water was injected. After 954 m3 (=6,000 bbl) of water was injected, the Hall derivative increased monotonically, which confirms that the hydraulic stimulation was effective in enhancing the geothermal reservoir through waterflooding.Figure 6
Hall plot confirming the stimulation of the reservoir.An increase in steam production was also observed in the surrounding wells. PPL-2 was closest to PPL-6 (Figure1), and thus, the subsurface open section of PPL-2 could be influenced expeditiously. The averaged mass flow rate at PPL-2 increased from 46.99 tons/h to 51.5 tons/h, a 9.6% increase owing to hydraulic stimulation (Figure 7(a)). This was a result of comparing the steam production before (averaged for 9 d) and after hydraulic stimulation at PPL-6. Despite PPL-4 being located relatively far from the water injector, PPL-4 was connected to the water injector by some faults within the productive zone. Its steam production also increased by 11.4% (Figure 7(b)).Figure 7
Improvement of mass flow rates at other wells due to the hydraulic stimulation at PPL-6: (a) mass flow rate observed at PPL-2; (b) mass flow rate observed at PPL-4. The dotted horizontal line represents the average mass flow rate before hydraulic stimulation. The red dotted box indicates the period of hydraulic stimulation at PPL-6.
(a)(b)After hydraulic stimulation at PPL-6, an overall increase in power generation from 50.0 MWe to 56.3 MWe was observed. Additionally, it was confirmed that the amount of excessive generation was proportional to the volume of water injected. These results imply that hydraulic stimulation at volcano-hosted vapor-dominated reservoirs is efficient in improving steam productivity.


## 3.3. Discussion

A typical hydraulic stimulation in a nonvolcanic zone leads to a considerable pressure increase from the starting point of water injection until the fractures are opened, and when hydraulic stimulation achieves critical pressure and the fractures are opened, the pressure drops significantly. However, in the volcano-hosted vapor-dominated reservoir, hydraulic stimulation led to a slight rise in pressure until the fractures opened. This could be due to already-formed natural fractures or fractures with reduced permeability. Even after the fractures were opened, the bottom hole pressure returned to its original level. Another important conclusion that can be drawn from this hydraulic stimulation is that injector location, well stability conditions, and water supply potential are also critical factors to consider when designing an EGS.Long-term water injection is required to confirm whether the hydraulic stimulation at Patuha field is commercial. An increase in steam production was observed by injecting 6,360 m3 (=40,000 bbl) water for 22 h, but this effect may not be sustainable. The optimal designs of hydraulic stimulation in this study are imprecise because the stimulated reservoir volume, i.e., the rock volume influenced by water injection, was not fully analyzed with tracer tests or microseismic surveillance [35]. This study indirectly estimated the fracture opening using the trajectories of pressure and temperature; however, more experimental analyses, e.g., the fracturing mechanism, stimulated reservoir volume, and core analyses, are required in the future. A reliable estimation of geomechanical features and reservoir heterogeneity must be conducted to obtain the optimal design of hydraulic fracturing techniques.


## 4. Conclusions

This paper discusses the effects of hydraulic stimulation with cold water at the volcano-hosted vapor-dominated reservoir of the Patuha geothermal field. The result of the Hall plot analysis and the increase in steam production confirmed that the hydraulic stimulation was effective on the EGS. The reservoir showed a small increase in pressure until the fractures opened; i.e., it required less increase in pressure to reach the fracture pressure, following which the bottom hole pressure recovered to its original level. The massive injection of water at high injection rates into the reservoir in Patuha showed an improvement in formation permeability as well as steam production. The high permeability and low pore pressure required less pressure increase during water injection. For the step-down rate injection, phase changes and pressure fluctuations were observed. This paper only discussed the short-term hydraulic stimulation, and thus, the results are not indicative of long-term sustainability. Although short-term stimulation was performed, a significant improvement in steam production was observed, and thus, the results confirm the applicability of hydraulic stimulation in a vapor-dominated geothermal field.



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*Source: 9220337-2023-02-13.xml*