NO CURRENT GEOTHERMAL PRODUCTION METHOD IS SCALABLE AGAINST CARBON.
Attributes of the Primary HDR Extraction Methods Are Described:
The traditional MULTI-WELL ENHANCED GEOTHERMAL SYSTEM (EGS) is a well-pair or well-triplet of injectors and producers drilled directionally or horizontally to create and then perpendicularly intersect a series of closely spaced hydraulic fractures. Acting essentially as single small points that more pass working fluid through the fracture’s broad surfaces instead of across them, the expected result is 1.5 MWe to 1.7 MWe output per well pair, even when producing intermittently. MWh output is substantially less if operated continuously. Although constructing the largest amount of potential heat exchange surface area of all standard HDR methods, multi-well EGS energy recovery is on the order of 6%.
Under development and fundamentally unchanged since 1973, and not materially commercial, multi-well EGS suffers at least five basic and/or contradictory design and economic issues:
1. The obvious and the unforeseen costs of multi-well drilling for each production site.
2. Horizontal-directional drilling:
3. Minimal hydraulic communication, small well-reservoir intersection causing hydraulic and thermal short-circuiting between the wells, extracting only 6% of the available heat.
4. Fracture congestion precluding timely heat replenishment and baseload potential.
5. Parasitic injection and cooling loads draining up to 90% of gross production.
Details of Multi-Well EGS Issues, Other Issues, and Some of the Industry’s Proposed Solutions
Multi-Well EGS Drilling Cost Ballooning
One proposed improvement to double low multi-well EGS output is to increase lateral lengths, fracture counts, and injection rate capability. The proposal doubles lateral lengths to 7,000’ or more and fracture quantities to 200, while increasing injection rates by 60%+, from 600 GPM – 800 GPM to 1300 GPM (80 l/s) towards doubling power output.
Pumping beyond an 800 GPM rate becomes impractical through the 7” (6” ID) diameter well casing commonly used in O&G and geothermal. Increasing injection to the higher proposed rate, and adding production tubing and isolation and other tooling, requires nearly doubling casing diameter to 13-3/8” and more than doubling the standard 8.5” hole size used for 7” casing hole size to 18.5”.
Doubling hole size, length, and corresponding well construction materials requires 300%+ increased time and expense. Further, the changes also mean that all drilling and casing costs above also increase. Even further, a substantially heavier 13-3/8” casing requires higher drilling rig ratings than typically offered of by the standard shale rig fleet. And the increase is also again doubled for the second-well EGS. Total per location wells’ installation cost is then in the tens of millions. Finally, doubling the fracture count can add several additional millions.
This particular proposal to double output totals 4X increased cost, or tens of millions, optimistically to increase optimistically 2MW intermittent to 5 MW. Even if actual output is higher, the case remains financially unviable, not even servicing debt.
Dependence on Highly Unrealistic Drilling Cost Reductions
Recent reports of sudden and dramatic 70% geothermal drilling time and cost reductions normal are not sustainable and representing as a new is simply irresponsible and misleading. The 70% reduction came about from a planned change in drilling locations and conditions, but was presented as the result of learning and planning. In the majority of drill site settings, it is the non-productive time that mostly determines drilling cost: lost circulation is most common, hydrocarbon influx is another problem, among many. The baseline wells used for comparison suffered from the presence of natural gas and formation instability (not known to have been published). Of course, the subsequent location did not suffer these delays, and the chosen geology happened also to drill faster than the baseline.
In the deeper drilling industry, there have been four step-change technologies occurring over the last 115 years: roller bits, jet nozzles, MWD et al, and the very recent advancements in PDC design and practice. Worth noting as the industry’s normal pace, PDC inserts have been commercially available for some 50 years and their true value only realized very recently.
Minimal Wellbore-Reservoir Hydraulic Connection Scheme
Is where the two or more perpendicular-well-fracture intersections result in thermo-hydraulic short circuiting, or injected flow following the path of least resistance towards the production well. The result is minimal reservoir contact, ‘sweep’, heat transfer, and energy recovery. Given the discrete path’s receiving excessive flow volumes, the minimized flow path also prematurely cools, challenging the system’s already constrained heat replenishment ability. Harvested reservoir area and energy recovery are on the order of 6%
The minimized hydraulic connection and resultant low-producing flows is considered a fundamental flaw, perhaps the primary flaw of multi-well EGS. Any underlying principle has to agree with its purpose, but it does not here, as the traditional well-fracture design is the opposite of what is needed. Heat recovery design in multi-well EGS is best described as an attempt to ‘heat-sweep’ reservoir surfaces, the size of several football fields, with two straws instead of a with full sized ‘broom’; tortuosity notwithstanding.
Yes, incremental improvements to improve recovery can be wrung, as has been ongoing since the method’s 1973 origin, but anything less than orders-of-magnitude improvements, into double-digit outputs, will simply not matter, respecting scalability and impact. Moreover, coordinating any advances across 100 or 200 fractures creates a new set of challenges.
The solution to multi-well EGS’s fundamental recovery problem is aligning the injection inlet and production outlet with the fracture’s plane, a co-planar well-reservoir construction, where the entire reservoir height is supplied with and recovers the heated working fluid. This is the DGS design.
Low Fracture Separation Blocking Timely Heat Replenishment and Baseload Abilities
Horizontal EGS has conflicting limits concerning the productive potential of any given interval. Given the recovery challenges facing multi-well EGS developers already described a developer’s solution towards increasing heat recovery is to place the maximum number of fractures, with fracture spacing in some cases as little as 30’. This congestion of HDR reservoirs precludes their timely reheating. Because geothermal production is only as good as its heat replenishment, a further design contradiction in the method is clearly present. Currently, a multi-million dollar EGS installation would need to be shut off after only a few hours operation in order to replenish. Conversely, attempts at running the system as baseload can only be done at output levels a fraction of the intermittent output, and generally <1 MW.
The contradiction also carries an interval length vs. fracture separation distance vs. fracture quantity vs. cost dilemma. The authors’ research has shown that, fully swept, HDR fractures require separation of approximately 1500’ in order to recharge undiminished, a 25X to 50X contrast with current multi-well EGS separation. At this distance, only five fractures would remain along, e.g., a 7,000’ lateral, not the 200 fractures currently contemplated by developers. However, because multi-well EGS sweep efficacy is estimated at only 6%, in simple terms, a more appropriate separation of 90’ may be in order, leaving 80 fractures, 1/5 lower than the quantity in use currently for shorter laterals. Inferred, is that approximately 1.5 MW might be producible as baseload after investing in two 18,000’ long wells drilled horizontally in granite. Even if tripled, such low output is not within reach of any market impact, much less climate.
Parasitic Loads
Most geothermal extraction requires reinjection and other operations that commonly consume upwards of 40% of gross energy production. However, adding the cooling required for ORC operations brings loss to some 90% resulting, optimistically, in 10% operational efficiency. This overwhelming loss is important, first, to noter the obvious lost revenue and resource spent to the atmosphere. Secondly, when injecting at high rates, subsurface water losses are exacerbated, amounting to potentially millions of gallons annually, amounts able to render a project or operation unviable. Third, reporting gross production levels can easily mislead reviewers and investors.
In stark contrast, some operations to not require injection expense, as they self-circulate via downhole fluid density differences and/or by vacuum. These include some hydrothermal fields, DGS to 400oF operating temperatures, and some AGS production.
Under development and fundamentally unchanged since 1973, and not materially commercial, multi-well EGS suffers at least five basic and/or contradictory design and economic issues:
1. The obvious and the unforeseen costs of multi-well drilling for each production site.
2. Horizontal-directional drilling:
- Accessing only 2/3 of potential heat, as compared with the same vertical total well length, raises the question of how, besides lacking higher temperature operational knowledge, the use of horizontal drilling is lauded by the industry and supporters.
- BHA drag, applicable bit weight, and rig capacity limits occur with substantial increases in lateral length and hole diameter, especially when drilling high compression strength rock.
- Dependence on unrealistic drilling cost reductions towards financial viability.
3. Minimal hydraulic communication, small well-reservoir intersection causing hydraulic and thermal short-circuiting between the wells, extracting only 6% of the available heat.
4. Fracture congestion precluding timely heat replenishment and baseload potential.
5. Parasitic injection and cooling loads draining up to 90% of gross production.
Details of Multi-Well EGS Issues, Other Issues, and Some of the Industry’s Proposed Solutions
Multi-Well EGS Drilling Cost Ballooning
One proposed improvement to double low multi-well EGS output is to increase lateral lengths, fracture counts, and injection rate capability. The proposal doubles lateral lengths to 7,000’ or more and fracture quantities to 200, while increasing injection rates by 60%+, from 600 GPM – 800 GPM to 1300 GPM (80 l/s) towards doubling power output.
Pumping beyond an 800 GPM rate becomes impractical through the 7” (6” ID) diameter well casing commonly used in O&G and geothermal. Increasing injection to the higher proposed rate, and adding production tubing and isolation and other tooling, requires nearly doubling casing diameter to 13-3/8” and more than doubling the standard 8.5” hole size used for 7” casing hole size to 18.5”.
Doubling hole size, length, and corresponding well construction materials requires 300%+ increased time and expense. Further, the changes also mean that all drilling and casing costs above also increase. Even further, a substantially heavier 13-3/8” casing requires higher drilling rig ratings than typically offered of by the standard shale rig fleet. And the increase is also again doubled for the second-well EGS. Total per location wells’ installation cost is then in the tens of millions. Finally, doubling the fracture count can add several additional millions.
This particular proposal to double output totals 4X increased cost, or tens of millions, optimistically to increase optimistically 2MW intermittent to 5 MW. Even if actual output is higher, the case remains financially unviable, not even servicing debt.
Dependence on Highly Unrealistic Drilling Cost Reductions
Recent reports of sudden and dramatic 70% geothermal drilling time and cost reductions normal are not sustainable and representing as a new is simply irresponsible and misleading. The 70% reduction came about from a planned change in drilling locations and conditions, but was presented as the result of learning and planning. In the majority of drill site settings, it is the non-productive time that mostly determines drilling cost: lost circulation is most common, hydrocarbon influx is another problem, among many. The baseline wells used for comparison suffered from the presence of natural gas and formation instability (not known to have been published). Of course, the subsequent location did not suffer these delays, and the chosen geology happened also to drill faster than the baseline.
In the deeper drilling industry, there have been four step-change technologies occurring over the last 115 years: roller bits, jet nozzles, MWD et al, and the very recent advancements in PDC design and practice. Worth noting as the industry’s normal pace, PDC inserts have been commercially available for some 50 years and their true value only realized very recently.
Minimal Wellbore-Reservoir Hydraulic Connection Scheme
Is where the two or more perpendicular-well-fracture intersections result in thermo-hydraulic short circuiting, or injected flow following the path of least resistance towards the production well. The result is minimal reservoir contact, ‘sweep’, heat transfer, and energy recovery. Given the discrete path’s receiving excessive flow volumes, the minimized flow path also prematurely cools, challenging the system’s already constrained heat replenishment ability. Harvested reservoir area and energy recovery are on the order of 6%
The minimized hydraulic connection and resultant low-producing flows is considered a fundamental flaw, perhaps the primary flaw of multi-well EGS. Any underlying principle has to agree with its purpose, but it does not here, as the traditional well-fracture design is the opposite of what is needed. Heat recovery design in multi-well EGS is best described as an attempt to ‘heat-sweep’ reservoir surfaces, the size of several football fields, with two straws instead of a with full sized ‘broom’; tortuosity notwithstanding.
Yes, incremental improvements to improve recovery can be wrung, as has been ongoing since the method’s 1973 origin, but anything less than orders-of-magnitude improvements, into double-digit outputs, will simply not matter, respecting scalability and impact. Moreover, coordinating any advances across 100 or 200 fractures creates a new set of challenges.
The solution to multi-well EGS’s fundamental recovery problem is aligning the injection inlet and production outlet with the fracture’s plane, a co-planar well-reservoir construction, where the entire reservoir height is supplied with and recovers the heated working fluid. This is the DGS design.
Low Fracture Separation Blocking Timely Heat Replenishment and Baseload Abilities
Horizontal EGS has conflicting limits concerning the productive potential of any given interval. Given the recovery challenges facing multi-well EGS developers already described a developer’s solution towards increasing heat recovery is to place the maximum number of fractures, with fracture spacing in some cases as little as 30’. This congestion of HDR reservoirs precludes their timely reheating. Because geothermal production is only as good as its heat replenishment, a further design contradiction in the method is clearly present. Currently, a multi-million dollar EGS installation would need to be shut off after only a few hours operation in order to replenish. Conversely, attempts at running the system as baseload can only be done at output levels a fraction of the intermittent output, and generally <1 MW.
The contradiction also carries an interval length vs. fracture separation distance vs. fracture quantity vs. cost dilemma. The authors’ research has shown that, fully swept, HDR fractures require separation of approximately 1500’ in order to recharge undiminished, a 25X to 50X contrast with current multi-well EGS separation. At this distance, only five fractures would remain along, e.g., a 7,000’ lateral, not the 200 fractures currently contemplated by developers. However, because multi-well EGS sweep efficacy is estimated at only 6%, in simple terms, a more appropriate separation of 90’ may be in order, leaving 80 fractures, 1/5 lower than the quantity in use currently for shorter laterals. Inferred, is that approximately 1.5 MW might be producible as baseload after investing in two 18,000’ long wells drilled horizontally in granite. Even if tripled, such low output is not within reach of any market impact, much less climate.
Parasitic Loads
Most geothermal extraction requires reinjection and other operations that commonly consume upwards of 40% of gross energy production. However, adding the cooling required for ORC operations brings loss to some 90% resulting, optimistically, in 10% operational efficiency. This overwhelming loss is important, first, to noter the obvious lost revenue and resource spent to the atmosphere. Secondly, when injecting at high rates, subsurface water losses are exacerbated, amounting to potentially millions of gallons annually, amounts able to render a project or operation unviable. Third, reporting gross production levels can easily mislead reviewers and investors.
In stark contrast, some operations to not require injection expense, as they self-circulate via downhole fluid density differences and/or by vacuum. These include some hydrothermal fields, DGS to 400oF operating temperatures, and some AGS production.
CLOSED LOOPS / ADVANCED GEOTHERMAL SYSTEMS (AGS) consists simply of a wellbore and a production tubing. Wellbore design include various vertical or directional lateral types, connected wells, or use of thermally enhanced construction materials. On average, but with some exceptions, approximately 0.4 gross (MWt) is generated from average 325oF rock per loop-mile, or 12 miles of drilling to produce 5 MWt. Despite prospective exploitation in extreme temperatures and depths, AGS production will remain low due to very limited heating and heat replenishment surface area. Even from an example extreme setting to 50,000’ depth (which has not been done) into 1000oF BHT, such an installation would only produce 6 MW to 7 MW without some heat transfer surface area augmentation. Without this, the reheating working surface area is limited such that downhole temperatures can be halved in under 30 hours operation, even when circulating only a few hundred GPM. AGS, functionally identical to residential type applications, is mostly suited for direct use as building heat and similar.