GRC Transactions, Vol. 45, 2021

Managed Pressure Control of Deep Closed-Loop Well
Construction and Operation
Eric van Oort1, Pradeepkumar Ashok1, Dongmei Chen1, Amirhossein Fallah1, Roman
Shor2

1

The University of Texas at Austin

2

University of Calgary

Keywords
Managed Pressure Drilling, MPD, Closed Loop Geothermal Systems, CLGS
ABSTRACTTo allow drilling and exploitation of deep CLGS wells, an integrated managed pressure
operation (MPO) concept is presented. An automatically controlled MPO system deployedduring drilling and heat extraction / production phases can maintain wellbore integrity, avoid
fluid contamination, control the pressure-volume-temperature (PVT) behavior of the working
fluid, and enable an open-hole completion and controlled heat extraction in the lateral portion of
the CLGS well. To demonstrate the feasibility of this concept, a new integrated thermal andhydraulic multi-phase flow model was developed. This model was coupled to an automatedmanaged pressure control algorithm to control both the phase dynamics of the drilling or
circulating fluid in the well, as well as hydraulic pressure in the well required to maintainwellbore stability of any open-hole sections. Simulations for deep CLGS well designs show thatthe developed simulation and control approach can describe and control the transient temperature
dynamics and power generation in such wells.

104van Oort et al.
1. General Introduction
Managed pressure drilling (MPD) techniques (Figure 1) provide a varied and versatile toolkit
that has served as an important enabler for oil and gas well construction, particularly whendrilling more challenging wells (Rehm et al., 2013). Main benefits derived from adoption of
MPD techniques during well construction include:
•

•
•
•
•
•
•
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Negotiating downhole drilling margins (difference between fracture pressure and either porepressure or mud pressure needed to prevent borehole shear failure, whichever of the latter
two is higher) better, with ability to manipulate the equivalent circulating density (ECD)
within the available margin.
Simplifying casing schemes, by extending casing points and eliminating casing/liner strings.
Avoiding NPT associated with well control, lost circulation, wellbore instability anddifferential sticking problems.
Direct control over bottom-hole pressure (BHP), with fast ability to arrest kicks andcirculating them out using the Driller’s Method for well control and kick circulation.
Early kick detection (EKD), through sensitive “delta-flow” measurements that sensitively
compare well inflow and outflow rates.
Ability to carry out dynamic pore pressure tests (DPPT) and dynamic formation integrity /leak-off tests (DFIT/DLOT) for determining the boundaries on the drilling margin.
Higher ROP by drilling with a lower density clean fluid with reduced overbalance pressure,
reducing chip hold-down
Better cementations through the use of Managed Pressure Cementing (MPC), allowing
reduction of circulating ECD’s during mud displacement that minimizes risk of induced lost
circulation

Figure 1 – Overview of MPD systems, with the 4 major “families” categorized as continuous circulation,
surface back-pressure, mud cap drilling, and dual gradient (for offshore applications).

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The MPD well construction benefits extend to geothermal drilling as well, and it is quite
surprising that there have been so few applications of MPD in the geothermal domain to date (forsome recent examples, see Pinkstone et al. (2018); Petrie and Doll (2021)). The following
benefits are expected from more wide-scale adoption of MPD techniques in the geothermal wellconstruction domain:•Continuous Circulation (CC) allows fluid circulation without interruption, even when making
drillstring connections. This technique creates a stable temperature and ECD profile in theannulus. This minimizes annular pressure fluctuations and associated “fatigue-cycling” on
the borehole wall that may cause instability. It also allows the well to be drilled with ahydrostatically underbalanced fluid becoming overbalanced by continuous circulation. Holecleaning is greatly improved, and the risk of pack-off-related stuck pipe incidents during
connections is eliminated. Last-but-not least, cooling of downhole tools is greatly improved
because fluid circulation is never stopped and the wellbore annulus is never allowed to reheat.

•

Surface Back-Pressure (SBP) comes with multiple benefits mentioned before, including
EKD, ability to perform DPPT, DFIT and DLOT measurements, active well control
response, ability to carry out MPC, etc. It can be used as an effective tool in managing
wellbore stability and mitigating lost circulation, a significant challenge in most GT wellconstruction projects. An important secondary benefit often observed when adopting SBP isa noticeable increase in rate of penetration (ROP), because light, clean fluids can often be
used (with added back-pressure providing the additional contribution to the desired BHP notprovided by the limited hydrostatic head of the fluid) that minimize chip hold-down.

•

Mud Cap Drilling (MCD) techniques have been developed in oil and gas for dealing withsevere lost circulation challenges when dealing with in-situ fractured formations, highvugular formations, karsts, etc. Rather than drilling blind, which provides no control and may
present significant safety risks, pressurized mud cap drilling (PMCD) in particular yields acontrolled operation with no mud returns or formation fluids/gases ever coming to surface.
This is particularly important when gas-bearing zones (containing H2S, CO2, hydrocarbon
gases) are intersected that present well control and associated safety risks. PMCD can be
simply implemented when using SBP functionality at the rigsite, because the hardware
required for the two operations (SBP and PMCD) is the same. The only major changes are
the availability and use of sacrificial fluid (SAC, usually freshwater or seawater) for drilling
and light annular mud (LAM) for annular control.

•

Dual Gradient Drilling (DGD) techniques have been developed for simplification andefficiency improvement in offshore deepwater drilling. Although a far stretch at present, one
may foresee a time when GT wells are drilled offshore in very deep water (e.g. along themid-Atlantic ridge and the Pacific Ring of Fire) in a “not-in-my-backyard” fashion,
benefiting from the adoption of DGD techniques. DGD implementation in both ECD
reduction and full-DGD modes have the ability to significantly reduce deepwater wellconstruction, with estimates up to ~40% time and cost reduction.

In the following, we will exclusively focus on the surface back-pressure (SBP) MPD variant inboth the drilling phase as well as the operations phase for deep closed loop geothermal systems(CLGS).

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2. Surface Back-Pressure MPO
The previous section argues that there are tangible benefits associated with considering MPD
techniques for use in GT well construction. The use of SBP-MPD, however, may not be limited
to the drilling phase but could be extended to the well operation during which heat extraction
takes place, particularly for CLGS wells. Manipulation of the back-flow valve on a GT well is
nothing new, but in the following we propose to perform this manipulation in an automated way
to achieve certain purposes, particularly when using an open-hole completion in the well withhigh-temperature formations directly exposed to heat-exchanging circulating fluid. We havetermed such use of SBP-MPD in the operations phase “managed pressure operations” (MPO).
With MPO, bottomhole pressure (BHP) can be actively managed and automatically controlledfor:(1) Phase control of heat exchanging fluid returning to surface, e.g., preventing water fromflashing to steam in the wellbore;(2) Control of thermosiphon effect, which has a natural tendency to reduce the BHP which
potentially could cause wellbore instability under certain circumstances; and,
(3) Allowing the exertion of additional BHP on open-hole formations to mechanically support
the wellbore to prevent failure or thermally induced creep behavior in case of open holecompletions. The latter assumes, of course, that the open-hole formations require suchborehole stability / creep-mitigation support under the prevailing in-situ stress, pore pressure
and temperature conditions.
Fluid phase behavior can be straightforwardly modeled by considering the thermodynamic
behavior of the fluid under different pressure and temperature conditions, as has been done forwater in Section 3. The thermosiphon effect can be modeled with a hydraulic model thatconsiders the effects of temperature and pressure on fluid density. The wellbore stability
requirements can be determined using appropriate rock mechanical failure modeling, considering
wellbore characteristics (depth, deviation, azimuth), the in-situ stress tensor, the pore pressure (ifpresent) as well as formation strength (Young’s modulus, Poisson’s ratio) and rock failure
parameters (unconfined compressive strength (UCS), cohesion, friction angle) as inputs. An
example of such modeling for the thresholds for shear failure (using the Modified Lade criterion,
Ewy (1999)) and tensile failure, as well as their difference, is shown in Figure 2. This example
considers the stability of a hard, normally pressured formation (loosely based on KTB
amphibolite, see Haimson and Chang, 2002) at 7 km TVD in a strike-slip faulting environment,with modeling parameters as given in Table 1.
Table 1 – Overview of rock mechanical modeling parameters used for Figure 2.

Variable

Value

Variable

Young’s Modulus E

68.8 GPa

Maximum Horizontal Stress SHmax andazimuthPoisson’s Ratio ν

0.26

Maximum Horizontal Stress SV

158 MPa68.6 MPa

Minimum Horizontal Stress Shmin

132 MPa

Pore Pressure

72.1 MPa

UCS
Friction Coefficient

0.6

Value

107

200 MPa, 60
degreesvan Oort et al.

Figure 2 – Wellbore stability modeling for the parameters given in Table 1, with (left) minimum borehole
fluid pressure to prevent shear failure according to the modified Lade criterion, (middle) fluidpressure to initiate tensile failure and fracturing, (right) difference plot, showing the available
drilling margin.

Figure 2 shows that in this case, wellbore stability requires a borehole fluid pressure higher thanthe hydrostatic pressure of water (72.1 MPa), which can be managed using a higher density
circulating fluid and/or active back-pressure from surface applied through SBP-MPD. Note thatmaintaining a wellbore overbalance pressure in the wellbore, however, can lead to time-delayed
failure due to mud pressure penetration, which raises the near-wellbore pore pressure (even intight rock with very low permeabilities) and lowers the near-wellbore effective stresses, driving
the stress state towards the failure envelope over time. Such time-delayed failure wasexperienced during the drilling of the KTB well in Germany (see Azzola et al. 2019, Borm et al.
1997). KTB amphibolite was shown to have a very low permeability (van Oort, 1996) on theorder of 0.1 nD (10-22 m2); however, even at such low permeability the effects of mud pressuretransmission still resulted in wellbore instability. The mechanism is shown graphically in Figure
3. Time-delayed failure can be prevented by hermetically sealing the borehole wall and plugging
all permeability, e.g., by chemical means, thereby preventing any pressure communication
between the wellbore and the adjacent formation.

Figure 3 – Instability in tight, low-permeability formations can be triggered by (left) insufficient mud
weight support (radial effective stress r too low or reduced e.g. by swabbing the well), or (right)
mud pressure transmission raising near-wellbore pore pressure, reducing effective stresses, anddriving the stress state over time towards failure. Red line shows a linearized Mohr-Coulomb failureenvelope.

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3. MPO Model Description
An integrated thermal and hydraulic model using transient conservation equations was used tosimulate dynamic well temperature profiles and SBP requirements. Details can be found in
Fallah et al. (2019, 2021). The conservation equations are derived from the transient NavierStokes equations for pipe flow and account for turbulent friction forces, liquid compressibility,
and temperature-dependent water properties:
K

]

@

@

K

H

....................................................................................................................................(1)
]

K

I@

H

K

K
I

K

...................................................................................................(2)

]

K

K

..................................................................(3)where is time, is the length along the direction of the well (measured depth, MD), isdensity, is velocity,is the rate of mass generation per unit volume from sources, p ispressure, is gravitational force per unit volume,
is wall friction per unit volume,isthe rate of momentum generation per unit volume from sources, is the internal energy, is thegravitational acceleration, is the vertical depth, is enthalpy, is thermal conductivity, istemperature,is the rate of external heat transfer per unit volume through the walls, andis the rate of enthalpy generation per unit volume from sources. Internal energy andenthalpy are defined as:
H I

]
]

K

.................................................................................................................................(4)K O ................................................................................................................................................(5)where@is the specific heat capacity at constant volume, andandare the reference
temperature and internal energy. The gravitational force and wall friction terms in the momentum

equation are calculated as:]@H I ...........................................................................................................................................(6)]............................................................................................................................................(7)where is the hole deviation from the vertical direction,is the Darcy-Weisbach friction
factor, and is the hole diameter. The external heat transfer in the energy equation between therock formation flow and heat exchanging fluid in the wellbore, which are separated by casing
and cement for cased-hole sections and are in direct contact for open-hole sections, is calculatedusing a heat transfer network discussed by Fallah et al. (2021). The boundary conditions used tosolve Eqs. (1-3) include the pump rate and inlet temperature at the wellbore inlet, as well as thewellbore outlet pressure which is controlled by the automated MPO system. The inlet pressure,
output flow rate, and outlet temperature are calculated numerically. The formation rock is
discretized radially to account for the formation temperature dynamics in close vicinity of thewell. Only the radial heat conduction inside the formation rock is considered due to thenegligible temperature gradients in the axial direction. The heat transfer between the wellbore
and the first formation node is calculated as:

109van Oort et al.
]..............................................................................................................................................(8)whereis the temperature of the first formation cell,is the temperature of the water in thewell, andis the thermal resistance. Total thermal resistance is calculated by summing theindividual resistances between the water and the first cell (i.e. convection in the water,
conduction through the casing and cement (which is zero in open-hole), and conduction in theformation rock). The heat transfer between the adjacent formation cells is calculated similarly,
where the resistance is only the conduction resistance through the rock. Each individual
conduction or convection resistance is calculated as:
HI]..................................................................................................................................(9)]..................................................................................................................................... (10)whereis the cross-sectional area of the well,and are the outer and inner radius of thesolid across which heat is being conducted,
is the conductivity of the solid, d is the diameterof the wall at which heat is being convected, and is the convection coefficient. The convection
coefficient is defined as:@]................................................................................................................................................... (11)where is the conductivity of water,
calculated from Eq. (12):TL@@@@@@@@@@@@@@@@@@@@@@@@@@
H]

I

is the diameter of the hole, andis the Nusselt number

@

L

@

.............................................................................................. (12)

N

where

and

are the Reynolds number and Prandtl number, respectively.

Considering freshwater as the closed loop circulation and heat exchanging fluid, fitted
polynomial models of water properties are used to calculate the density, viscosity, specific heat
capacity at constant pressure and constant volume, and thermal conductivity. Density is modeledby a first-order polynomial function of pressure combined with a second-order polynomial
function of temperature as:]N

PNPPRVPNQUYTK QPPQNUUQU ........................................................................... (13)where pressure is measured in Pa, temperature in , and density in kg/m3. Neglecting the effectof pressure, the viscosity, specific heat capacities, and thermal conductivity are assumed to befunctions of temperature and are modeled as:]

SNRW QPRNPRU QPYNQT QPK QNWR QPK YNYS QPUNQX QPUNUV QPK QNWY QP L@@@@@@@@@ \ QPP@........... (14)K VNTT QP L@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@QPP@] QNQV QPRNSU QPK QNVQK TNQW QP .....................................................(15)] SNTP QP

QNPQ QPSNYUK TNRT QP .....................................................(16)]K QNVT QPK UNVY QPUNWQ QP

110......................................................................(17)van Oort et al.
where temperature is measured in , viscosity in Pa.s, specific heat capacities in J/Kg.K, andthermal conductivity in W/m.K. Details of the semi-implicit numerical scheme and thediscretization of Eqs. (1-3), as well as the validation of the discretization method are based on themethod proposed by Evje and Fjelde (2002), with details given in Fallah et al. (2021). A
polynomial fit of water pressure as a function of temperature is presented in Eq. (18). The boilingpressure monotonically increases with the temperature. At any given temperature, water starts
boiling if the pressure is below the boiling pressure threshold.
] QNUW QP

RNTT QP

K SNSP QPQNWW QPK SNTV QP .........(18)

In Eq. (18), temperature is measured inand pressure in Pa. Deep in the wellbore itself, thehydrostatic pressure of the water column applies sufficient pressure to avoid boiling downhole,even for extreme temperature gradients and high absolute downhole temperatures. The welllocation where boiling is most likely to occur is on surface at the outlet due to the reducedhydrostatic pressure. Therefore, a proportional integral (PI) controller that enables MPO wasdesigned to maintain SBP above the boiling pressure by automatic choke opening adjustment.
The MPO system controls the fluid PVT behavior, maintains pressure control across the open
lateral, ensures well integrity, and avoids reservoir influxes and fluid contamination. Simulating
the automated choke control behavior relies on capturing the pressure wave dynamics and thefast transients associated with rapid choke adjustments. We simulate choke opening
manipulation such that:
]

H IK

L@@@@

]

@

H I ^@

K

L@@@@

@

........................................................... (19A)
H I \@......................................... (19B)

H I@is the boiling pressure on
where
is the SBP that is maintained by the choke,
surface (which is a function of the outlet temperature), andis the BHP required forborehole stability of creep control,
is the hydrostatic head of the circulating fluid, andis an additional safety margin (this margin was set to a nominal 1 MPa for the simulation
presented below). The control strategy outlined in Eqs.(19) is simple and straightforward, with acontroller being informed by temperature measurement of the fluid exiting the well and wellbore
stability information obtained before and potentially during the drilling phase. It could, however,be made more robust with digital twinning of the circulation operation and taking advanced
effects such as the influence of a changing temperature on wellbore stability into account.
4. Simulation Results
The above model is illustrated here for a U-shaped closed loop well with 7 km TVD and a 5 kmlong connecting lateral section. The diameter of the open-hole lateral section is 31.115 cm (12.25
in) and the build radius of the curve sections of the well is assumed to be 200 m. Water ispumped at 300 m3/h into a U-shaped well for 13 hours, followed by a 3-hour pumping at 400
m3/h, and 4 hours of pumping at 350 m3/h, for a total circulation time of 20 hours. The initial
temperature of the water in the well is assumed to be equal to the temperature profile of thesurrounding rock, linearly increasing from 40 at surface to 250 at 7 km TVD. The density,heat capacity, and thermal conductivity of the rock formation are set to be 2700 kg/m3, 1000
J/kg.K, and 2.5 W/m.K, respectively, representing average crust properties. During thesimulation, an automatic controller is used to apply enough backpressure to avoid water
evaporation and associated pressure reduction in the well. The inlet vertical sections are cased111

van Oort et al.
and cemented using 33.973 cm outer diameter casing. Casing and cement thicknesses for thecased sections are set to be 1 cm and 2.5 cm, respectively.
Fig. 4 shows the water, rock formation, and initial temperatures versus MD at different times.
The water temperature is initially assumed to be in thermal equilibrium with the rock formation(e.g., after an extended shut-in period of no circulation). When pumping starts, high-temperaturewater in the horizontal section is pumped out of the well and replaced by cold water from theinlet section of the well. After continuing pumping for a few hours, a semi-steady-state isreached where all the water is displaced by the cold water from the inlet section of the well.
During the process, the surrounding rock temperature continues to decrease due to the heattransfer to the water. (i.e., thermal depletion of the well). As the water is circulated up in the
return section, the decreasing temperature of the surrounding rock (due to the thermal gradient)cause a heat loss from the water to the cold rock formation. The maximum gradient in thetemperature profile is observed at the beginning of the horizontal section, where the temperature
difference between the water and un-cased formation is at a maximum. It is observed that theincreased pump rate between 13 and 16 hours into the simulation reduces the temperature profile
along the well. This is because with the increased pump rate and fluid velocities within the
wellbore, water has less time to be heated up as it moves along the well. When the pump rate is
reduced at 16 hours, the fluid temperature increases again due to the reduced velocities in thewell. However, the effect of lower fluid velocities is offset by the continuous thermal depletionof the surrounding rock.

Figure 4 - Temperature profile at different times during well operation.

Fig. 5 shows the outlet temperature, net thermal power generation, and outlet flow rate. Fig. 6
shows the SBP and choke opening versus time. As the outlet temperature increases between 0134 min, the boiling pressure increases according to Equation (18). The automated controller
calculates the boiling pressure, adjusts the choke opening, and applies sufficient SBP to avoid
evaporation and maintain well control. A maximum SBP of 2.4 MPa is applied at 134 minutes
when the exit temperature peaks. As the temperature and boiling pressure decrease, the choke is112van Oort et al.
slowly opened to reduce unnecessary excess SBP, while maintaining a safety margin of 1 MPa(assuming that no excess safety margin is required for open-hole stability control in thehorizontal lateral). Varying the pump rate will affect the outlet temperature, and the choke is
automatically adjusted to maintain the 1 MPa safety margin while the boiling pressure varies.
5. Conclusions
Although MPD techniques have not yet found widespread application in GT well construction,
the case is made in this paper to consider all forms of MPD (continuous circulation, surface
back-pressure, mud cap drilling, and potentially even dual gradient drilling for future offshore
deepwater GT wells) for GT well construction due to tangible benefits that can make operations
safer and more efficient, thereby lowering drilling costs. MPD offers new ways of dealing withwell control, borehole instability and stuck pipe, lost circulation control etc. to be yet fully
explored in the GT domain. In addition, there may be an opportunity to use SBP-MPD control
methodologies in the well operation / heat extraction phase of closed loop wells as well, byoffering automated choke control that can handle phase behavior control and thermosiphon
control of the circulating fluid, as well as borehole stability management of any open holeformations. This type of control is illustrated here using a representative example for a 7 km
TVD well using a comprehensive hydraulics model coupled with a thermal model.

Figure 5 - Outlet temperature, thermal power
and outlet flow versus time.

Figure 6 - SBP and choke opening versus time.

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Acknowledgement
This work was carried out under the auspices of the RAPID consortium at the University ofTexas at Austin, and we thank the 2021 RAPID sponsors (Baker Hughes, Cenovus,
ConocoPhillips, Eavor, Halliburton, Hess, H&P, JOGMEC, Nabors, NOV, Oxy, and Saudi
Aramco) for their support and guidance.
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