Geothermal Energy from Petroleum Wells: Abandoned Well Repurposing, Geothermal Gradient Assessment, and Heat Extraction Economics

Geothermal Energy from Petroleum Wells: Abandoned Well Repurposing, Geothermal Gradient Assessment, and Heat Extraction Economics

Geothermal energy extracted from repurposed petroleum wells represents one of the most technically elegant and economically promising convergences in the energy transition: the petroleum industry has drilled hundreds of thousands of wells to depths of 2,000-6,000 meters into the earth, and in doing so has created access to vast quantities of thermal energy stored in the subsurface. When a well ceases to produce commercial hydrocarbons - either because the reservoir is depleted or because low commodity prices make continued production uneconomic - the well and its subsurface access are typically abandoned at a cost of $500,000-$5,000,000. The emerging alternative is to repurpose these wells as geothermal heat extractors: circulating a working fluid down the wellbore to absorb heat from the surrounding rock formations and returning it to the surface where the thermal energy is used for district heating, industrial process heat, or electricity generation. The economic case is compelling in principle: the drilling cost, which typically represents 30-60% of a conventional geothermal project's total capital expenditure, has already been incurred by the petroleum operation and is a sunk cost. The incremental investment to convert a petroleum well to a geothermal well is therefore a small fraction of the investment required for a dedicated geothermal project targeting the same thermal resource. The technical challenge is equally compelling: petroleum wells were designed and completed for hydrocarbon production, not thermal energy extraction, and their casing design, cement integrity, tubular dimensions, and wellbore geometry may not be optimal for the flow rates and fluid chemistry required for efficient geothermal heat extraction. This guide covers the complete engineering framework for petroleum well geothermal repurposing: the geothermal gradient assessment that determines how much thermal energy is available, the wellbore heat transfer analysis that predicts the temperature and flow rate achievable, the surface facility design that converts extracted heat into useful energy, and the economic analysis that determines when repurposing is preferable to conventional abandonment.

1. Geothermal Resource Assessment

1.1 Geothermal Gradient and Heat Flow

The geothermal gradient is the rate at which temperature increases with depth below the earth's surface. It varies significantly by geological setting: continental cratons and stable sedimentary basins have low gradients (15-25°C/km), while tectonically active regions, volcanic zones, and areas with high radioactive heat generation can have gradients exceeding 60-80°C/km. Most petroleum basins have gradients in the range of 25-40°C/km - sufficient to provide economically useful temperatures at the depths accessible with petroleum drilling technology:

Geothermal gradient calculation and bottom-hole temperature (BHT) estimation:

Temperature at depth z:
T(z) = T_surface + gamma x z

Where:
T_surface = mean annual surface temperature (°C)
gamma = geothermal gradient (°C/km)
z = depth (km)

Example: Petroleum basin in Alberta, Canada (WCSB analog)
T_surface = 8°C
gamma = 32°C/km (moderate gradient for sedimentary basin)

Well depth: 3,200 m TVD
T_BHT = 8 + 32 x 3.2 = 8 + 102.4 = 110.4°C at 3,200 m TVD**

**Well depth: 4,800 m TVD (deeper target):
T_BHT = 8 + 32 x 4.8 = 8 + 153.6 = 161.6°C at 4,800 m TVD**

**Temperature classification for geothermal applications:
T < 90°C: Low enthalpy → district heating, aquaculture, greenhouse heating
90-150°C: Medium enthalpy → industrial process heat, binary cycle electricity generation
T > 150°C: High enthalpy → flash steam electricity generation (efficient, single/double flash)

Geothermal heat flow calculation:
Heat flow Q = k x dT/dz x A (Fourier's law)
Where k = thermal conductivity of rock (W/m/°C), A = area

Sedimentary rock thermal conductivity: k = 2.1 W/m/°C (typical sandstone/shale sequence)
Heat flux (per unit area): q = k x gamma = 2.1 x (32/1,000) = 2.1 x 0.032 = 0.0672 W/m2 = 67.2 mW/m2**

**WCSB typical measured heat flow: 60-75 mW/m2 → consistent with calculation

Available thermal power in a 1 km2 area at 3,200 m depth:
q x A = 67.2 x 10^-3 x 10^6 = 67,200 W = 67.2 kW/km2 natural heat flux**

**This natural flux is far too low for practical heat extraction. Geothermal wells extract heat from the stored thermal energy in the rock mass (not just the natural flux), depleting the near-wellbore thermal reservoir over time. The relevant parameter for well-based extraction is the rock's volumetric heat capacity and the temperature drawdown acceptable before the well becomes uneconomic.

1.2 Wellbore Heat Transfer Analysis

The critical engineering calculation for geothermal well performance is how much thermal energy can be extracted from the wellbore into the circulating fluid, and at what temperature the fluid reaches the surface. This is a heat transfer problem in a cylindrical geometry where the heat source is the surrounding rock (at formation temperature) and the heat sink is the circulating fluid:

Closed-loop geothermal wellbore heat transfer calculation:

Configuration: Closed-loop coaxial heat exchanger in existing petroleum well
- Outer annulus (between wellbore wall and inner pipe): working fluid descends, absorbing heat
- Inner pipe: working fluid returns to surface

Well geometry:
Wellbore diameter: 8.5" (215.9 mm) - typical petroleum production well
Inner pipe OD: 4.5" (114.3 mm), inner pipe ID: 4.0" (101.6 mm)
Annular flow area = pi/4 x (0.2159^2 - 0.1143^2) = pi/4 x (0.04662 - 0.01306) = pi/4 x 0.03356 = 0.02636 m2 annular area**

**Working fluid: Water (most common)
Flow rate: Q = 0.012 m3/s (12 L/s = 45.7 m3/hr)
Velocity in annulus: v = 0.012/0.02636 = 0.455 m/s**

**Overall heat transfer coefficient between formation and annular fluid:
Resistance network: Formation → cement annulus → casing → working fluid

1/U_overall = R_formation + R_cement + R_casing + R_fluid

R_formation (major resistance, semi-infinite medium approximation):
R_formation = (1/(2 x pi x k_rock x L)) x ln(r_thermal/r_wellbore)
Where r_thermal = thermal diffusion radius ≈ sqrt(4 x alpha x t)
alpha = k_rock/(rho x cp) = 2.1/(2,400 x 900) = 9.72 x 10^-7 m2/s
t = operating time = 1 year = 3.156 x 10^7 s
r_thermal = sqrt(4 x 9.72 x 10^-7 x 3.156 x 10^7) = sqrt(4 x 30.68) = sqrt(122.7) = 11.08 m thermal radius after 1 year**

**R_formation per meter = 1/(2 x pi x 2.1) x ln(11.08/0.108) = (1/13.195) x ln(102.6) = 0.07579 x 4.631 = 0.3510 m·°C/W per meter of well**

**R_cement = ln(r_casing_OD/r_wellbore)/(2 x pi x k_cement) = ln(0.245/0.108)/(2 x pi x 0.7) = ln(2.269)/4.398 = 0.8188/4.398 = 0.1862 m·°C/W per meter**

**R_casing = ln(r_OD/r_ID)/(2 x pi x k_steel) = ln(0.245/0.224)/(2 x pi x 50) = ln(1.094)/314.2 = 0.08985/314.2 = 0.000286 m·°C/W per meter (negligible)**

**R_fluid (convective, annular flow): Nu = 0.023 x Re^0.8 x Pr^0.4 (Dittus-Boelter)
Re = rho x v x D_h / mu = 1000 x 0.455 x 0.1016/0.001 = 46,228 (turbulent)**
Pr = cp x mu/k = 4,182 x 0.001/0.598 = 6.99
D_h = D_outer - D_inner = 0.2159 - 0.1143 = 0.1016 m (hydraulic diameter)
Nu = 0.023 x 46,228^0.8 x 6.99^0.4 = 0.023 x 2,612 x 2.275 = 136.7**
h_fluid = Nu x k/D_h = 136.7 x 0.598/0.1016 = 804.5 W/m2/°C**
R_fluid = 1/(h x 2 x pi x r_wellbore) = 1/(804.5 x 2 x pi x 0.108) = 1/(546.4) = 0.00183 m·°C/W per meter (also negligible)**

**Total thermal resistance: R_total = 0.3510 + 0.1862 + 0.000286 + 0.00183 = 0.539 m·°C/W per meter of well**

**Heat extraction rate per meter of well:
q_per_m = (T_formation - T_fluid) / R_total
At mid-depth (1,600 m): T_formation = 8 + 32 x 1.6 = 59.2°C
T_fluid (average annular temperature) ≈ T_surface + 0.5 x T_rise = 20 + 0.5 x ΔT

Iterative calculation needed. Simplified: use average formation temperature:
T_formation_avg = T_surface + gamma x (depth/2) = 8 + 32 x 1.6 = 59.2°C (average at mid-depth)
T_fluid_avg (estimated) ≈ 45°C (inlet 20°C → outlet ≈ 70°C, average 45°C)
delta_T_avg = 59.2 - 45 = 14.2°C
q_per_m = 14.2 / 0.539 = 26.3 W/m of wellbore**

**Total heat extraction (3,200 m well): Q_total = 26.3 x 3,200 = 84,160 W = 84.2 kW**

**Outlet fluid temperature:
Q = m_dot x cp x (T_out - T_in)
m_dot = rho x Q = 1,000 x 0.012 = 12 kg/s
T_out = T_in + Q/(m_dot x cp) = 20 + 84,160/(12 x 4,182) = 20 + 84,160/50,184 = 20 + 1.68°C

Only 1.68°C temperature rise → outlet temperature 21.68°C → NOT USEFUL for heat applications.

Problem identified: The flow rate of 12 L/s is too high relative to the available heat extraction rate. Need to reduce flow rate to increase temperature rise.

At Q = 0.0005 m3/s (0.5 L/s):
m_dot = 0.5 kg/s
T_out = 20 + 84,160/(0.5 x 4,182) = 20 + 84,160/2,091 = 20 + 40.2 = 60.2°C outlet temperature**

**But velocity in annulus: v = 0.0005/0.02636 = 0.019 m/s → laminar flow → lower heat transfer
Re = 1000 x 0.019 x 0.1016/0.001 = 1,930 (laminar) → Nusselt number changes to ~3.66 (laminar Nu)
h_fluid = 3.66 x 0.598/0.1016 = 21.6 W/m2/°C → R_fluid = 1/(21.6 x 2 x pi x 0.108) = 1/14.65 = 0.068 m·°C/W

R_total_laminar = 0.3510 + 0.1862 + 0.000286 + 0.068 = 0.606 m·°C/W**

**q_per_m = 14.2/0.606 = 23.4 W/m
Q_total = 23.4 x 3,200 = 74,880 W
T_out = 20 + 74,880/(0.5 x 4,182) = 20 + 35.8 = 55.8°C at 0.5 L/s flow rate**

**Optimal operating point: balance flow rate against outlet temperature for maximum thermal power delivery.
Optimum for district heating (target 60-80°C supply temperature): flow rate ≈ 0.3-0.5 L/s with outlet 55-65°C

2. Geothermal Well Types and Configurations

2.1 Configuration Options for Petroleum Well Repurposing

Configuration	Description	Typical Thermal Output	Best Application	Additional Capex
Closed-loop coaxial	Inner pipe inserted in existing casing. Fluid descends in annulus, returns in inner pipe. No contact with formation. Zero contamination risk. No formation permeability required.	50-300 kW thermal per well	District heating in moderate gradient basins. De-risked option (no formation involvement). Works in any well regardless of formation productivity.	$150,000-$400,000 per well
Open-loop (produced brine extraction)	Pump hot formation brine to surface, extract heat in surface heat exchanger, reinject cooled brine in separate well. Directly uses formation thermal fluid. Higher extraction rates possible.	500 kW - 10 MW per well pair	High permeability formations with hot saline water. Oilfield produced water management. Requires available injection well.	$300,000-$1.5M per well pair
Downhole heat exchanger (DHE)	Heat exchanger installed at depth in existing wellbore. Natural convection or pump circulates working fluid through the exchanger. Simplified surface equipment.	30-150 kW per well	Small-scale heating applications (single building, small community). Lower cost than full coaxial system.	$80,000-$200,000 per well
Enhanced Geothermal System (EGS) in petroleum wells	Hydraulic fracturing of hot dry rock (HDR) formation to create artificial permeability. Water circulated through fracture network between injector and producer wells. Much higher flow rates and temperatures possible.	1-20 MW per well pair (with stimulation)	Deep basement rock or tight formation with high temperature (>150°C). Enables electricity generation. High technical risk - stimulation unpredictable.	$2-10M per well pair

2.2 Produced Water Geothermal - The Oilfield Opportunity

Produced water geothermal heat extraction calculation:

Many mature petroleum fields produce large volumes of hot formation brine (produced water) co-produced with hydrocarbons. This produced water is currently treated as a waste stream requiring expensive management. It represents an untapped thermal resource:

Mature oilfield produced water characteristics:
Production rate: 45,000 STB/day produced water (high water cut late-life field)
Well temperature at surface: 85°C (hot brine from 2,800 m depth)
Surface ambient temperature: 15°C
Available temperature drop (to minimum useful temperature 45°C): 85 - 45 = 40°C

Thermal power available:
m_dot = 45,000 STB/day x 0.159 m3/STB x 1,040 kg/m3 / 86,400 s/day
= 7,155 m3/day x 1,040/86,400 = 7,155/83.077 = 86.1 kg/s

Q_thermal = m_dot x cp_brine x delta_T
cp_brine = 3,900 J/kg/°C (saline brine, slightly less than fresh water)
Q_thermal = 86.1 x 3,900 x 40 = 86.1 x 156,000 = 13,431,600 W = 13.43 MW thermal**

**This 13.43 MW of thermal power is currently dissipated to atmosphere via cooling towers or discharged to disposal wells at high cost. Capturing it for district heating or industrial process heat would:

1. Provide heating energy worth: 13.43 MW x 8,760 hr x $0.04/kWh = $4,706,800/year heating value**

**2. Avoid CO2 from gas boilers that would otherwise provide this heat:
At 200 g CO2/kWh (natural gas boiler): 13,430 kW x 8,760 hr x 200/1,000,000 = 23,562 tCO2/year avoided**

**Carbon value at $85/tCO2: 23,562 x $85 = $2,002,770/year carbon credit**
Total annual benefit: $4.71M + $2.0M = $6.71M/year from produced water thermal extraction**

**Installation cost (heat exchanger + surface piping + controls): $2.5M
Simple payback: $2.5M/$6.71M = 0.37 years (4.5 months) → outstanding economics**

**But: Produced water at 85°C is also highly saline and potentially corrosive. Heat exchanger material must be:
316L stainless steel (for <100 g/L TDS)
Titanium (for >100 g/L TDS or H2S contamination)
Hastelloy C276 (for HPHT sour brine)
Material cost premium: +$0.5-1.5M vs carbon steel

3. Surface Facility Design for Geothermal Heat Utilization

3.1 Binary Cycle Electricity Generation: Organic Rankine Cycle

For geothermal sources in the medium-enthalpy range (90-150°C), direct steam generation is not possible (temperatures are below the boiling point of water at atmospheric pressure), but electricity generation is achievable using an Organic Rankine Cycle (ORC). An ORC uses a low-boiling-point organic working fluid (such as R-245fa, isobutane, or n-pentane) that evaporates at the geothermal brine temperature and drives a turbine:

ORC electricity generation from 110°C geothermal source:

Geothermal brine temperature: T_in = 110°C
Reinjection temperature: T_out = 60°C (minimum useful temperature constraint)
Available temperature drop: delta_T = 50°C
Brine flow rate: m_dot = 30 kg/s (from multiple production wells)

Thermal power input to ORC:
Q_in = m_dot x cp x delta_T = 30 x 3,900 x 50 = 5,850,000 W = 5.85 MW thermal**

**ORC efficiency (Carnot analysis):
Carnot efficiency: eta_Carnot = 1 - T_cold/T_hot = 1 - (303)/(383) = 1 - 0.791 = 0.209 (20.9% theoretical maximum)**

**Actual ORC efficiency: approximately 50% of Carnot for real-world systems
eta_ORC = 0.50 x 0.209 = 0.1045 = 10.45%**

**Using R-245fa working fluid with more precise calculation:
eta_ORC = 0.72 x (1 - T_condenser/T_evaporator) x eta_turbine x eta_pump
T_evaporator = 100°C (273+100 = 373K), T_condenser = 30°C (303K), eta_turbine = 0.80, eta_pump = 0.70
eta_ORC = 0.72 x (1 - 303/373) x 0.80 x 0.70
= 0.72 x 0.1877 x 0.56 = 0.72 x 0.1051 = 0.0757 = 7.57%**

**Electrical output:
W_electrical = Q_in x eta_ORC = 5,850,000 x 0.0757 = 442,845 W = 442.8 kW electrical**

**Annual electricity generation: 442.8 kW x 8,760 hr x 0.95 (availability) = 3,683,000 kWh/year = 3.68 GWh/year**

**Revenue at $0.08/kWh: $294,640/year

ORC electricity generation is modest for medium-enthalpy sources. The economic case is stronger for direct heat use (district heating) than electricity generation from 110°C sources.

Heat pump amplification (upgrade medium-enthalpy to higher-grade heat):
Install heat pump driven by ORC electricity to upgrade 60°C reinjection temperature to 80°C district heating supply:
COP of heat pump at these conditions: COP = 0.45 x T_supply/(T_supply - T_source) = 0.45 x 353/(353-333) = 0.45 x 353/20 = 7.94**

**Heat pump thermal output: W_electrical x COP = 442.8 kW x 7.94 = 3,516 kW additional heating from ORC-powered heat pump**

Total heating delivered: Direct from brine (to 60°C return) = 5.85 MW + Heat pump upgrade = 3.52 MW = 9.37 MW total useful heat at 80°C for district heating

4. Economic Analysis: Geothermal vs Conventional Abandonment

4.1 NPV Comparison: Repurpose vs Abandon

Economic comparison for 3 petroleum wells at end of production life:

Well characteristics: 3 wells at 2,800 m depth, T_BHT = 97.6°C (8 + 32 x 2.8)
Conventional abandonment cost per well: $1.8M (P&A + surface restoration)
Total abandonment cost for 3 wells: $5.4M (immediate cash outflow)**

**Geothermal repurposing option (open-loop produced water extraction):
Formation brine production rate per well: 8,000 STB/day = 14.7 kg/s per well
Total brine flow: 3 wells x 14.7 = 44.1 kg/s
Surface temperature of brine: 90°C (slightly below BHT due to wellbore cooling)

Available temperature drop (to 50°C minimum): 40°C
Thermal power: 44.1 x 3,900 x 40 = 6,879,600 W = 6.88 MW thermal**

**Application: District heating for small town (population 3,500, 5,000 equivalent homes)
Heating demand: 6 MW average during heating season (7 months), 0.5 MW summer (domestic hot water)
Annual heating energy: (6 MW x 7 x 30 x 24) + (0.5 x 5 x 30 x 24) = 30,240 + 1,800 = 32,040 MWh/year**

**Available from geothermal (6.88 MW at 90% availability): 6.88 x 8,760 x 0.90 = 54,243 MWh/year (more than sufficient)**

**Geothermal covers 100% of district heating demand with 41% surplus

Revenue calculation:
District heating revenue: 32,040 MWh x $0.085/kWh = $2,723,400/year**

**Alternative fuel displaced (natural gas at $0.055/kWh thermal):
Natural gas cost avoided: 32,040 MWh x $0.055 = $1,762,200/year (customer benefit, not operator revenue unless utility model)

CO2 credit (23,562 tCO2/year avoided at $85/tCO2): $2,002,770/year
Total revenue + carbon: $2,723,400 + $2,002,770 = $4,726,170/year**

**Geothermal conversion capital cost:
Wellbore coaxial heat exchanger (3 wells): 3 x $280,000 = $840,000
Surface heat exchanger and distribution infrastructure: $2,100,000
Surface pumping and controls: $450,000
Abandonment liability avoided: -$5,400,000 (credit)
Net geothermal conversion cost: $3,390,000 - $5,400,000 = -$2,010,000 (net benefit: geothermal saves money vs abandonment even before revenue)**

**NPV of geothermal vs abandon:
NPV_abandon = -$5,400,000 (immediate cost, no future revenue)

NPV_geothermal = (-$3,390,000 Capex) + ($4,726,170/year revenue x PVF(8%, 25 years))
= -$3,390,000 + $4,726,170 x 10.675
= -$3,390,000 + $50,457,415
= +$47,067,415 NPV of geothermal repurposing**

**NPV difference (geothermal vs abandon): $47.07M - (-$5.4M) = $52.47M value creation from geothermal repurposing vs conventional abandonment**

This analysis demonstrates that in the right geological and market context (moderate geothermal gradient, proximate heat demand, carbon pricing), geothermal repurposing of petroleum wells can generate value of $10-50M per well cluster versus the conventional abandonment alternative.

4.2 Screening Criteria for Geothermal Repurposing Viability

Screening Criterion	Minimum Threshold	Preferred Range	Impact if Below Threshold
Bottom-hole temperature	≥ 60°C	80-150°C	Below 60°C: insufficient temperature lift for district heating without heat pump. LCOH too high.
Well depth	≥ 1,500 m	2,500-4,500 m	Shallow wells have low BHT regardless of gradient. Insufficient thermal power per well.
Casing condition	No confirmed casing leaks or integrity failures	Full cement bond, good casing grade	Compromised casing requires expensive remediation or prevents repurposing entirely. Must be assessed by CBL log.
Proximity to heat demand	≤ 25 km from heat load	≤ 10 km (less thermal loss and pipe cost)	Distribution pipeline cost increases linearly with distance. At >25 km, district heating economics deteriorate significantly.
Heat demand density	≥ 1 MW/km2 (dense urban or industrial)	≥ 5 MW/km2	Low demand density increases distribution pipe length per customer. Rural areas rarely economic without specific anchor industrial customer.
Carbon/energy price environment	Carbon price ≥ $40/tCO2 OR heat price ≥ $0.06/kWh	Carbon price ≥ $85/tCO2 AND heat price ≥ $0.08/kWh	Without carbon revenue or adequate heat price, simple payback exceeds 15 years → project uneconomic for most investors.

Conclusion

The wellbore heat transfer analysis in this article discovering that a 12 L/s flow rate through a coaxial closed-loop well at 3,200 m depth produces only 1.68°C temperature rise (61°C outlet), while 0.5 L/s produces a more useful 55.8°C outlet demonstrates the fundamental engineering trade-off in geothermal well design: flow rate and outlet temperature are inversely related for a given wellbore heat transfer rate. The engineer who maximizes flow rate to maximize total thermal power extracted will end up with a large flow of lukewarm water that has limited applications and cannot be efficiently used for heating or power generation. The engineer who restricts flow rate to achieve a useful outlet temperature extracts less total thermal power but delivers it in a form that can displace gas boilers, drive heat pumps, or feed an ORC power cycle. Optimizing this trade-off requires matching the wellbore heat extraction model to the specific application's temperature requirements district heating needs 60-80°C supply, ORC generation needs 90-130°C, and direct industrial use may need 150°C or higher. The optimal flow rate for each application is different, and the well's potential contribution varies accordingly.

The NPV comparison between geothermal repurposing and conventional abandonment - $47.07M NPV for geothermal versus -$5.4M for abandonment, creating $52.47M of value from the repurposing decision - is the economic argument that will eventually drive widespread adoption of this technology in mature petroleum basins. The key insight is that the abandonment liability ($5.4M avoided) converts from a cost to a benefit when credited against the geothermal conversion capex, making the net conversion investment actually negative: the operator receives value from avoiding abandonment while simultaneously building an asset that generates $4.7M per year in revenue. This economics-from-liability structure is unusual in capital project analysis and explains why geothermal repurposing gains commercial traction fastest in jurisdictions where petroleum abandonment regulations are strictly enforced and abandonment costs are substantial, because the avoided abandonment liability is larger and more certain than in jurisdictions where wells can be left in deferred abandonment status indefinitely.

For engineers and analysts building expertise in geothermal energy and petroleum well repurposing, the following references provide the essential technical and economic framework: Geothermal Energy from Petroleum Wells - Resource Assessment and Conversion Engineering covers wellbore heat transfer, surface facility design, and repurposing economics for petroleum well geothermal projects, while Organic Rankine Cycle Systems for Geothermal and Waste Heat Recovery provides the thermodynamic design methodology for ORC electricity generation from medium-enthalpy geothermal sources.

Want to access our geothermal repurposing toolkit with BHT estimator from gradient and depth, wellbore heat transfer model (coaxial flow vs temperature), produced water thermal power calculator, ORC efficiency and output estimator, and geothermal vs abandonment NPV comparison model, or discuss geothermal repurposing for a specific petroleum field? Join our Telegram group for geothermal energy and petroleum field repurposing discussions, or visit our YouTube channel for step-by-step tutorials on wellbore heat transfer, produced water geothermal design, and repurposing economics.

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