underbalanced drilling simulation
TRANSCRIPT
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Underbalanced Drilling Simulation
MSc Thesis
by
Dávid Kiss
Submitted to the Petroleum Engineering Department of
University of Miskolc
in partial fulfillment of the requirements for the degree of
MASTER OF SCIENCE
in Petroleum Engineering
09 May 2014
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Table of contents
1 Acknowledgment ........................................................................................................... 4
2 Summary ........................................................................................................................ 5
3 Introduction ................................................................................................................... 6
4 Underbalanced drilling theoretical background ............................................................ 7
4.1 Underbalanced drilling definition ........................................................................... 7
4.2 Overbalanced drilling ............................................................................................. 7
4.3 Reason of underbalanced drilling ........................................................................... 7
4.4 The underbalanced drilling techniques ................................................................... 8
4.5 Underbalanced drilling determination .................................................................... 9
4.6 Underbalanced drilling advantages ....................................................................... 10
4.7 Underbalanced drilling disadvantages. ................................................................. 11
5 Underbalanced drilling equipment .............................................................................. 12
5.1 Gas injection equipment ....................................................................................... 13
5.1.1 Air compressors ............................................................................................. 13
5.1.2 Nitrogen Generation System (NGU) ............................................................. 13
5.1.3 Booster compressors ...................................................................................... 14
5.1.4 The nitrogen generation system completion .................................................. 14
5.2 Well control equipment’s ...................................................................................... 15
5.2.1 Non return valves .......................................................................................... 15
5.2.2 Rotating Control Diverters (RCD) ................................................................ 16
5.2.3 Choke manifold ............................................................................................. 18
5.2.4 Separator equipment ...................................................................................... 19
5.2.5 Flares ............................................................................................................. 20
6 Drilling fluid and flow systems ................................................................................... 21
6.1 Drilling fluid ......................................................................................................... 21
6.2 Drilling with single phase fluid ............................................................................ 22
6.3 Gas injection ......................................................................................................... 23
6.3.1 Drillpipe injection .......................................................................................... 23
6.3.2 Annular injection ........................................................................................... 24
6.3.3 Parasite string injection ................................................................................. 25
7 Gases for underbalanced drilling ................................................................................. 27
7.1 Nitrogen ................................................................................................................ 27
7.2 Natural gas ............................................................................................................ 27
8 Underbalanced drilling modeling at Mezősas - Nyugat field ...................................... 28
8.1 Introduction ........................................................................................................... 28
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8.2 Description of the Mezősas - Nyugat field ........................................................... 29
8.3 Reason of underbalanced drilling at Mezősas - Nyugat field ............................... 29
8.4 Risk assessment, surface pressure and influx rate recommendation .................... 30
8.4.1 Risk assessment at different type of reservoir ............................................... 30
8.4.2 Surface Pressure Control recommendation ................................................... 31
8.4.3 The Williams 7100 Rotating Control Head ................................................... 32
8.5 The simulation optimization ................................................................................. 33
8.5.1 The built - in flowing areas............................................................................ 34
8.5.2 The built - in “for cycle”: .............................................................................. 35
8.5.3 The built - in productivity index .................................................................... 36
8.5.4 The built - in gas density model .................................................................... 38
8.5.5 The built - in friction factor model ................................................................ 39
8.6 Simulation ............................................................................................................. 40
8.6.1 Input data ....................................................................................................... 41
8.6.2 Simulation results .......................................................................................... 43
8.6.3 Simulation result examination at Very Low, 0.1mD permeability................ 50
8.6.4 Simulation result examination at Low, 1 mD permeability........................... 53
8.7 The Mezősas - Nyugat field’s evaluation and recommendation ........................... 56
9 Conclusion ................................................................................................................... 58
10 Appendices .................................................................................................................. 59
11 References ................................................................................................................... 65
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1 Acknowledgment
This thesis was written as a final part of my two long years to acquire a Master of Science
degree in Petroleum Engineering at the University of Miskolc. I am deeply grateful to
Tibor Szabo PhD (faculty adviser), László Katona (Mol Plc) and Róbert Hermán (field
adviser), and thanks them for all the help and guidance I received during the whole
semester. Furthermore, I would like to thanks for my professors, namely to: Imre Federer
PhD, Gábor Takács PhD, Zoltán Turzó PhD, Tibor Bódi PhD, Elemér Bobok PhD, Anikó
Tóth PhD who taught me during the four semesters and I acquired a lot of knowledge from
them. Finally I would like to thanks for Dr Kjell Kåre Fjelde who sent me the
underbalanced program and Áron Esztergomi who helped me on programming.
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2 Summary
Nowadays the Under Balanced Drilling (UBD) is increasing rapidly because of the
increasing nonconventional hydrocarbon field drilling where the reservoir permeability
should be Very Low. With the underbalanced drilling operation, the formation damage
should be avoided by the underbalanced fluid circulation. In the underbalanced drilling
theoretical background I dealt with the reason of the underbalanced drilling. I characterized
the underbalanced drilling advantages and disadvantages where the technology
applicability and limitation appeared such as the technology limitation at deep, high
pressure, high permeable well and the weak formation problem.
In my work I examined one well’s underbalanced drilling suitability at Mezősas –
Nyugat field. The Mezősas - Nyugat field has Very Low permeability, high pressure
bearing hydrocarbon reservoir where - during the field life - the overbalanced drilling
process caused formation damage at the wells which was the reason of low production rate.
I used underbalanced simulation program for one well simulation of Mezősas - Nyugat
field. The program was sent to me by Dr Kjell Kåre Fjelde, who takes the UBD modeling
lesson in the Norwegian University of Stavanger. I made modification in the program for
my well optimization. I built-in the program one friction factor equation for the applied
mud rheology, one productivity index equation for gas influx simulation and I modified the
gas density calculation which is based on the Pápay gas deviation factor. In my work I
examined the effect of increasing openhole depth which causes increasing gas influx, and
decreasing Circulating Bottom Hole Pressure (CBHP).For the simulation of this effect I
built - in the program “for cycle”. The “for cycle” can modify some parameter parallel with
the increasing openhole depth such as the gas influx, pore pressure and Well Head Pressure
(WHP). During the simulated data the given well of Mezősas - Nyugat field gave a good
result at Very Low permeability layer, but at Low - High permeability layer the simulation
result gave unacceptable value. During the simulation I recognized that underbalanced
condition is not suitable at Low - High permeable formation where the reservoir is
overpressurized gas bearing reservoir. With this simulation I can simulate the amount of
gas influx, the Circulating Bottom Hole Pressure (CBHP) and the effect of liquid flow rate,
mud density, annulus diameter, well head pressure. With this simulation the expected
events can be examined at underbalanced condition, which can occur in UBD field
operation.
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3 Introduction
Every technological improvement is started by a technological problem as we can see
at the Underbalanced Drilling (UBD). Nowadays more and more Underbalanced Drilling
Operations (UBO) is used worldwide to reduce wellbore formation damage problems. At
the UBD, the Circulating Bottom Hole Pressure (CBHP) is less than the effective near bore
formation pore pressure opposite the overbalanced drilling process. For these reasons,
during the UBO when the bit penetrates into the reservoir, hydrocarbon enters into the
borehole immediately and the influx hydrocarbon is flowing by the pumped mud. Finally
the mud-influx-cut mixture is separated with the surface separator equipment. Because of
the underbalanced operation the first barrier, namely the hydrostatic pressure of fluid
column is less than the pore pressure, new well control procedures are needed and other
technological equipment which will be dealt with the many advantages of UBD in the
further sections.
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4 Underbalanced drilling theoretical background
4.1 Underbalanced drilling definition
„We speak about underbalanced drilling when the Circulating Bottom Hole Pressure
(CBHP) of the drilling fluid - which is equal to the hydrostatic pressure of the fluid
column, plus associated friction pressures loss, choke pressure - is less than the effective
near bore formation pore pressure.” (Leading, 2002)
4.2 Overbalanced drilling
When the drilling is overbalanced the Circulating Bottom Hole Pressure (CBHP) is
higher than the reservoir pressure and the circulated fluid enters into the reservoir.
Furthermore, the mud cake fills up potentially the productive zones and damages the
permeability of the rock. The damage of reservoir, especially in horizontal wells, is often
difficult or complicated to remove or clean up when production starts.
4.3 Reason of underbalanced drilling
Reducing formation damage and enhancing productivity:
One of the main reasons of the UBD is to improve reservoir productivity by eliminating
reservoir damage caused by drilling fluids and filtrate migration into the reservoir.
Reduction of the skin factor is the main justification for UBD.
Minimizing pressure related drilling problems:
Some problem can be eliminated by the underbalanced drilling operation for example: to
eliminate fluid loss and to avoid other pressure related drilling problems such as
differential stuck pipe. During the underbalanced condition the penetration rate is higher
than at the overbalanced condition.
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Reservoir characterization during drilling:
The underbalanced drilling can be used for reservoir characterizing whilst drilling. The
reservoir productivity features can be identified during the process. Parallel to the drilling,
well trajectories and well lengths can be modified.
4.4 The underbalanced drilling techniques
Every method has to be used for the appropriate technological problem. The
underbalanced drilling techniques are currently divided into three parts by the Weatherford
division.
Underbalanced Drilling (UBD)
The underbalanced drilling is used to reduce formation damage at the pay zone. At the
underbalanced drilling process the Circulating Hydrostatic Bottom Hole Pressure (CBHP)
is less than the reservoir pressure. At the underbalanced drilling the well is designed to
allow the reservoir fluid to flow to the surface whilst drilling. This method is used at the
target zone.
Performance Drilling (PD)
The performance drilling is used at fractured layers where total fluid loss occurs. This is
the original air drilling technique. This technology ensures to achieve maximum
penetration rates and reduce the well bore pressure to a minimum possible value.
Managed Pressure Drilling (MPD)
The managed pressure drilling is used to exactly manage and control the annular
bottomhole pressure as close as possible to the reservoir pressure. It is usable where higher
pressure drawdown can cause high inflow into the borehole which cannot be handled.
MPD is also used where there are very narrow margins between formation pore pressure
and formation fracture pressure. (Kenneth, 2007)
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4.5 Underbalanced drilling determination
When the drilling is underbalanced the Circulating Bottom Hole Pressure (CBHP) is
continuously less than the reservoir pressure at the wellbore. The lower hydrostatic
pressure doesn’t cause the build-up of filter cake on the open reservoir formation. The mud
drilling solids can’t enter into the formation. This helps to improve productivity of the
wellbore and reduces any pressure related drilling problems. Whereas the wellbore
pressure is maintained below the reservoir pressure, continuous inflow takes place from the
hydrocarbon bearing formation. The process is carefully controlled during the entire
drilling process. The BOP stack remains as the secondary well control barrier as at the
conventional overbalanced drilling process. The underbalanced hydraulic system is a
closed system and the primary well control process is the combination of hydrostatic
pressure; circulation friction pressure and surface choke pressure which can be defined in
the following ways (Weatherford, 2006):
The hydrostatic pressure: considered as a static pressure and it is given by the
density of the circulating fluid, the density contribution of any drilled cuttings, the
contribution of influx fluid and gas.
The friction pressure: considered as a dynamic pressure which mainly depends on
the pipe and annulus cross section area, the fluid circulation speed and the fluid
parameters such as viscosity.
The choke pressure: it is applied at the surface with the help of choke manifold, the
applied choke pressure depends on the circulation fluid density, circulation friction
pressure and the drawdown that we want to apply between the effective circulating
bottomhole pressure and the reservoir pressure.
The pressure is controlled all the times and ensures to maintain flow control whilst drilling.
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4.6 Underbalanced drilling advantages
The properly designed and executed underbalanced drilling operation contains more
advantages:
Reduce formation damage: No invasion of solids or mud filtrate into the reservoir
formation. The Very Low permeability and porosity zones at overbalanced drilling
may never be properly cleaned up, which can result unproductive pay zone.
Reduce stimulation: Because there are no filtrate or solids invasion in an
underbalanced drilled reservoir, the reservoir stimulation is not necessary.
Early production: After the bit penetrates into the reservoir the well start to produce
hydrocarbon. It had to be noticed that the inflow can be a disadvantage if the
produced hydrocarbon cannot be handled.
Enhanced recovery: During the operation there is no invasive fluid and the pay
zone remains without damage, which cause enhances recovery.
Figure 1: Difference between overbalanced and underbalanced drilling
Source: Weatherford: Introduction To Underbalanced Drilling
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Differential sticking: At the underbalanced operation there is no loss circulation
and overbalanced pressure which push the drill pipe into the filter cake and cause
differential stuck. This is especially useful when we are drilling with coiled tubing
because of the lack of tool joint connections.
No fluid losses: Whiles the hydrostatic pressure is less than the formation pressure
at the borehole there is no loss circulation.
Improve Penetration Rate: There is a significant effect on the penetration rate
because of the lack of overpressure. The effect of the reduction in chip hold down
also has a positive impact on the bit life. (Mohamed, 2012)
4.7 Underbalanced drilling disadvantages.
As every technological process has some drawbacks beside the advantages thus the
underbalanced drilling operation also has some disadvantages which cause the limitation of
the operation as well as safety and economic limitations issues.
Increased drilling costs: Due to the additional equipment and crew, the drilling fee
is higher than the overbalanced drilling.
Utility of conventional Measure While Drilling (MWD) systems: The high gas
voids fraction cause compressibility and the fluid can’t transmit the MWD signal.
String weight is increase: Due to the lighter fluid the buoyance is small.
Possible excessive borehole corrosion: The nitrogen generation system leaves some
oxygen with the compressed nitrogen which should cause corrosion.
Wellbore stability: The weak formation can collapse because of the low hydrostatic
pressure, for these reasons it is very important to prevent formation from collapse
while drilling. The following in equation: Pcollapse ˂ Phydrostatic ˂ Ppore.
Flow control and safety problem: Deep, high pressure and highly permeable wells
can be problematic due to the well control and the separation limitation
Flaring of produced gas: Some government environment protection does not always
contribute to the flaring of the produced gas.
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5 Underbalanced drilling equipment
The UBD has a complex system and it requires some new equipment for the
appropriate well control and operation. During the planning process the equipment
selection started at the injection side and continued through the surface equipment via the
wellhead and separation system to the flare. (Weatherford, 2006) During the planning we
have to take into account more required area around the derrick. In this chapter I present
the UBD equipment step by step followed the fluid flow direction started from the
compressor system.
Figure 2: The circulation process
Source: Leading Edge Advantage International Ltd 2002
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5.1 Gas injection equipment
The gas injection equipment varieties depend on the appropriate injected gas. The
gas can be carbon dioxide, natural gas, or nitrogen. During the planning process the
applied gas is selected by the financial, technological consideration. In this section I am
going to present the nitrogen gas injection equipment which contains more items such as
air compressors, nitrogen generation, and booster system. At the planning process one of
the most important parameters is the nitrogen volume and the pressure requirements. The
other consideration is the more area and diesel supply.
5.1.1 Air compressors
The compressors are skid mounted and powered by a diesel engine. The
compressor is direct drive and two-stage helical screw compressor. The air compressor is
the first equipment in the nitrogen generating chain, after the outgoing compressed air
cooled and added to the nitrogen generation system. Most compressors produce a
maximum air flow of 900 scft/min at 300 psi to 350 psi pressure range, with a horsepower
rating of approximately 380 BHP at 1800 rpm.
5.1.2 Nitrogen Generation System (NGU)
The Nitrogen Generation System is a single containerized system which contains a
set of modules; each module contains millions of hollow fiber membranes. The individual
modules are built in a steel housing. The nitrogen production system feed with compressed
air, which first passes through filters to remove contaminant materials such as oil and
water. The flow rate through NGU’s varies inversely with nitrogen purity, if the output
volume of nitrogen is lower, the nitrogen will be purer. The membranes could produce
nitrogen as pure as 99.9 which can completely eliminate the danger of either downhole
combustion or oxygen corrosion. The system usually produces a maximum of 1500
scft/min of nitrogen through the membranes, but two times more compressed air is needed
because the NGU’s efficiency is 50 %. (Eng.Abd El, 2012) (Weatherford, 2006)
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5.1.3 Booster compressors
The outlet nitrogen pressure of the nitrogen generation system is not enough for the
injection, for this reason two types of boosters are normally used for the boosting, low
pressure boosters and high pressure boosters are connected in series. The boosters are
positive displacement compressors.
Low pressure boosters
The low pressure boosters boost the outlet from the nitrogen generator from 165 psi
to approximately 1800 psi. The low-pressure boosters normally contain two cylinders,
single or two-stage, double acting, reciprocating, inter-cooled and after-cooled. (Eng.Abd
El, 2012)
High pressure boosters
The high-pressure booster is normally a single cylinder, double-acting,
reciprocating, after-cooled pressure booster. The high pressure booster needs an inlet
pressure of 1400 psi and can boost up to a pressure of 4000 psia. (Eng.Abd El, 2012)
5.1.4 The nitrogen generation system completion
This equipment requires significant area at the derrick. During the Weatherford
recommendation one typical system chain has shown on the figure 3. It has the capability
of generating approximately 3000 scft/min of nitrogen at 4000 psi with the following
technological equipment:
Six 950 scft/min feed air compressors deliver 5700 scft/min of air at 350 psi.
The two Nitrogen Generators deliver 2850 scft/min of N2 at 350 psi.
The low pressure boosters raise this pressure from 350 psi to 1800 psi.
The final high pressure booster raises this pressure from 1800 psi to 4000 psi into
the standpipe.
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5.2 Well control equipment’s
In this section I want to introduce the equipment which ensures the controlled fluid
flowing.
5.2.1 Non return valves
Whereas the hydrostatic pressure less than the formation pressure at the
underbalanced drilling non return valves are necessary to prevent influx fluids up inside
the drillstring both tripping and making connection. The float valve is built-in above the
bit, sometimes it has to run above a downhole tool. Two types of non-ported drill string
floats are commonly used namely the flapper and spring loaded floats. (Weatherford, 2006)
Figure 3: The nitrogen generation system
Source: Weatherford: Introduction To Underbalanced Drilling
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The flapper type float valve
The flapper type valves contain a built-in latch; this structure eliminates the need to
fill the pipe during the tripping due to the valve open position. After the initial circulation
starts the latch automatically releases. When the circulation stops the valve closes. Some
flapper valves are allowed to read of pressures during shut in conditions. (Rig Train, 2001)
Spring loaded float valve
The literature calls it, as plunger or dart type float valve. The spring loaded float
valve has similar functions as mentioned above. The spring loaded valve is spring
activated, which opens to allow the direct circulation flow to pass around the dart
(plunger). (Rig Train, 2001)
5.2.2 Rotating Control Diverters (RCD)
The conventional BOP stack cannot be used for appropriate operated underbalanced
drilling and must not be used to control the well except in case of emergency, for these
reasons another barrier is needed, namely rotating control diverter system which ensures
that the BOP remains as the secondary well control system. The rotating control diverter
system and flow line with Emergency Shut Down (ESD) valves is normally installed on
top of the conventional BOP to provide underbalanced well control. The RCD is basically
the same as the annular BOP, there is a rubber element that is closing around the drill pipe
and the sealing rubber is installed on bearings that allow rotation relative to the RCD
housing during drilling. (Jostein, 2012) The rotating diverter system provides an effective
annular seal around the drillpipe during drilling and tripping operations. The annular seal
must be effective over a wide range of pressures and for a variety of drilling string, BHA
sizes and operational process. The rotating control head system comprises of a pressure
containing housing where packer elements are supported between roller bearings and
isolated by mechanical seals. There are currently two types of rotating diverters system.
(Weatherford, 2006)
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Active
The active rotating diverters use external hydraulic pressure to activate the sealing
element, and these types of active diverters increase the sealing pressure as the annular
pressure increases.
Passive
The passive rotating diverters use a mechanical seal. The sealing action activated
by well bore pressure. During the planning process the RCD equipment have to be chosen
with the following consideration:
The expected flow rates.
The expected pressures.
The type of pipe, which conducted through the diverter system.
Figure 4: Rotating diverter with pressure range
Source: Weatherford: Introduction To Underbalanced Drilling
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The selection criterion for rotating diverters is mainly based on expected static and
dynamic pressures. During the Weatherford suggestion currently there are four types of
rotating equipment which are suitable for high pressure applications. These are:
Weatherford /RTI RBOP
Shaffer PCWD
Williams 7100
RBOP
The presented RBOP 5K rotating control diverter systems are suitable until 3500 psi
with rotating at 200 rpm whiles the maximum static pressure can be 5000 psi and during
tripping it can be 2500 psi. The latest manufactured of rotating control diverters is
compatible with top drive. (Weatherford, 2006)
5.2.3 Choke manifold
Choke manifolds and standpipe manifolds are all important parts of an
underbalanced drilling operation. All manifolds should have at least the same rated
working pressure as the installed BOP stack. The manifolds should be designed to
accommodate pressure, temperature, abrasiveness and corrosive of the formation drilling
fluids. (Maurer, 1996)
UBD choke manifold
The choke manifold is used for underbalanced drilling which is a separated
manifold from the standard drilling choke manifold. Both manifolds will remain fully
independent of each other. The choke manifold is a combination of valves, pipelines and
chokes which designed to control the flow from the annulus of the well during the
underbalanced operation. It must be capable of:
Controlling pressures by using manually operated chokes or chokes operated from
a remote location.
Diverting flow to a burning pit, flare or mud pits.
Contain enough back up lines which could substitute any part of fail manifold.
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The choke manifold should be designed to handle the maximum expected volumes
from the well (4-inch minimum piping) equipped with dual chokes (one hydraulic and the
other manual). This redundancy allows that one choke is operating while the other is
isolated and maintained. During the planning the proper piping and flow control at surface
must be developed. Without this, the system can become a hazard to the overall surface
control system. (Weatherford, 2006) (Eng.Abd El, 2012)
5.2.4 Separator equipment
In most cases the separator is the first technological equipment that receives the
return flow out of the well. The separator equipment is usually working as a simple
gravitational separator. At the underbalanced operation typically 4 phase separator is
needed (cutting, oil, water, and gas) and it can be used vertical or horizontal arrangement.
The separation equipment choice is based on the amount of separated fluid, gases and
drilling fluid.
Horizontal separator
The well returns enter into the horizontal separator equipment and slowed by the
velocity-reducing baffles. Due to the gravity force, firstly the solid particles settle in the
first compartment. The settled solids are continuously removed by a solids transfer pump.
Above the solid particles the liquid goes through the first plate into the second
compartment where the oil and water separates, at the bottom of the second compartment
the water removed by flow line. The final section is the oil compartment where the oil is
removed by flow line. Naturally the gas comes out at the top of the separator. The flow
lines controlled by choke. The separator contains relief valve and an emergency shutdown
valve which is triggered on high/low liquid level and high, low pressure. The separators
also contain sight glasses to indicate liquid levels and the solids level.
Vertical separator
Due to the lack of space usually the vertical separator is preferred at offshore
operation and those fields where the expected gas content will be high. The vertical
separator working processes are similar as the horizontal separator equipment but it
contains only one vessel. The well returns enter into the top of the separator and the entry
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fluid and solid particles fall into the bottom of the separator while the gas continuously
came out from the liquid phase. Predominantly the cuttings settle at the bottom of the
vessel, where it can be removed. The liquids and gases are also separated by their density
differences. The gas locates at the top of the separator, the oil at the middle position and
the water between the oil and the solid particle. Each material is continuously led from the
separator and the equipment also mounted on the same choke and safety equipment that I
detailed at the horizontal separator.
5.2.5 Flares
While we are drilling underbalanced, hydrocarbons are produced which have to be
handled on the drilling location. The crude oil and condensate are stored; the gas is
normally flared whilst drilling. Those places where the government or environment
protection prohibited the flaring, gas re-compression and export injection can be
considered. There are two ways for the gas flaring: one of them is the flare pit the other is
the flare stack. Both flare pit and flare stack must be equipped with an automatic ignition
system and flame propagation blocks. During the planning one of the most important is the
equipment layout because of the noxious fumes, radiated heat, noise and flammable gas.
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6 Drilling fluid and flow systems
6.1 Drilling fluid
The selection of the fluid system is the key to the successful operation. The choice of
drilling fluid system is mostly based on the target zone pressure and the formation’s
geomechanical parameters. Those drilling fluid are usable for the UBD which cause the
smallest chance for the formation damage. The other important object is the cuttings
transport which mainly depends on the density, viscosity and the velocity of the fluid. For
these reasons during the gas circulation increased flow rate necessary and at that fluid
where the fluid density is small the cuts settle quickly, which cause problem in the bottom
of the hole. (Szabó, 2006) The fluid selection also depends on the reservoir characteristics,
well fluid characteristics, well geometry, compatibility, hole cleaning, temperature
Figure 5: Fluid gradients
Source: Weatherford: Introduction To Underbalanced Drilling
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stability, corrosion, drilling BHA, data transmission, surface fluid handling and separation,
formation lithology, health and safety, environment impact and fluid source availability.
Fluid gradients are calculated with the following formula:
6.2 Drilling with single phase fluid
The use of single phase fluids is one of the simplest forms of underbalanced drilling.
The first thing you have to be considered is the single phase fluid when the formation
pressure is higher than the Circulating Bottom Hole Pressure (CBHP) of the drilling fluid.
During the underbalanced operation where the reservoir pressure is higher than the pumped
fluid hydrostatic pressure usually enough single phase fluid for the underbalanced process,
for example mud, water, oil. During the circulation, the formation fluids enter into the
boreholes because the formation pressure is higher than the pumped fluid hydrostatic
pressure. At the drilling with single phase fluid the listed well control and separation
equipment is necessary, but in this process the gas injection equipment is missing.
Water based system
Water based system is the first thing you have to take into consideration at every
planning process because it is cheap and sustainable, finally accessible.
Oil Systems
If the water is deemed unsuitable because of the reservoir conditions, crude oil, base
oil or diesel can be considered as a drilling fluid. We have to consider that during the
operation the oil systems can dissolve formation gas or when drilling an oil bearing
reservoir the based oil and the influx crude oil will mix and cannot be separated from crude
oil. (Weatherford, 2006)
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6.3 Gas injection
When we want to reduce the single phase fluid density the use of gas injection into
the fluid flow is an option. Usually natural gas or nitrogen is used as an injected gas. In this
section I introduce 3 different methods for the gas injection.
6.3.1 Drillpipe injection
During the planning process the first consideration is the drillstring injection
because it is the simplest method. The Compressed gas is injected into the standpipe
manifold where it mixes with the drilling fluid. To prevent the flow up in the drillpipe,
non-return valves are necessary into the drillstring. The system’s benefit is that the gas
rates are less than parasite string injection and it can achieve lower bottomhole pressure
than with annular gas lift. The system drawback occurs at the stop pumping when bleeding
of any remaining trapped pressure in the drillstring, every time a connection is made. This
process increases the bottomhole pressure and it is difficult to avoid the pressure spikes at
the reservoir when using drillpipe connection. The other disadvantage is the use of pulse
type MWD tools. The injected gas – liquid mixture flowing through the MWD tools and
above 20% of gas fraction the tools cannot be used. This problem is solvable with special
MWD tools such as electromagnetic tool. A further drawback for drillstring injection is the
impregnation of the gas into any downhole rubber seals. At the Positive Displacement
Motors (PDM) once a trip is made, the rubber can explode or swell as a result of the
expanding gas not being able to disperse out of the stator quick enough. This effect
(explosive decompression) destroys not only the motors, but also affects any rubbers seals
which are used downhole. (Baker, 1999)
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6.3.2 Annular injection
At the annular injection gas flows through between the dual casing strings and as
the gas is injected via the annulus only a single-phase fluid is pumped down the drillstring.
The annulus between the intermediate casing and the parasitic liner is used for gas
injection only and very small annular area is required. With this technical solution the
pressure surge can be avoided during the pipe joint and the bottomhole pressure is more
stable than at the drill pipe gas injection. The other benefit is that the conventional MWD
tools can be operated. The drawback with this type of operation is that the size of the hole
is restricted and causes additional investment.
Figure 6: Drillpipe injection
Source: Baker Hughes: Underbalanced DrillingManual
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6.3.3 Parasite string injection
At the use of a small parasite string the string connects to the outside of the casing
for gas injection. Usually two 1” or 2” coiled tubing strings are normally connected to the
casing string above the reservoir where the casing is run in. The injected gas is pumped
down through the parasite string and injected onto the drilling annulus. At the wellhead
some modification is necessary to provide surface connections to the parasite strings. The
system can’t be used at deviated wells because during the installation the parasite string is
easily ripped off. The principles of operation and the system advantage are similar than the
annular injection.
Figure 7: Annular injection
Source: Baker Hughes: Underbalanced DrillingManual
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Figure 8: Parasita string injection
Source: Baker Hughes: Underbalanced DrillingManual
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7 Gases for underbalanced drilling
Some literature suggests the exhaust gas as an opportunity but it is extremely corrosive
and not recommended. The most usable gas for the UBD is the following:
Nitrogen
Natural Gas
7.1 Nitrogen
During the UBD the nitrogen is used more times to lighten the circulating fluid
column in underbalanced drilling operations. Nitrogen is an odorless, colorless, and
tasteless gas which creates 78 % of the Earth atmosphere. Nitrogen is non-toxic, non-
flammable and noncorrosive. It has very low solubility in water and hydrocarbons.
Nitrogen does not tend to form hydrate complexes or emulsions.
7.2 Natural gas
The natural gas is a very good option when the correct volumes and high pressure gas
is available. The natural gas is non-toxic and non-corrosive if it is sweet gas. Taking into
account that the natural gas is soluble in the hydrocarbons, the produced gas from the
system can be re-routed to the compression system which eliminating to flare the gas. The
drillstring injection method is not recommended, as the gas is vented every time a
connection needs to be made.
28
8 Underbalanced drilling modeling at Mezősas - Nyugat field
8.1 Introduction
During the literature research I contacted with Dr Kjell Kåre Fjelde, who takes the
computational reservoir and well modeling lesson in the Norwegian University of
Stavanger at the Department of Petroleum Engineering. (Fjelde) He sent me underbalanced
modeling lesson note and a Matlab code that I used in my thesis. During my work I made
some modification into the Matlab code for my well optimization. I built-in friction factor
model into the program for the appropriate mud friction factor calculation, which is the
power law model correlation. I also modified in the program the gas density model.
(Turzó) The other built-in equation is the productivity index equation. (Bódi, 2007) This is
created for the gas inflow simulation during the underbalanced operation which is mainly
based on the open pay zone length and permeability. The other effective parameter is the
pressure different between the reservoir pressure and the Circulating Bottom Hole Pressure
(CBHP) that should be controlled with the Rotating Control Diverter (RCD), liquid flow
rate and with the mud density. I considered some parameters constant in the productivity
index equations, such as the wellbore radius and drainage radius. During the simulation I
used over pressurized reservoir which is based on real well data that I used from Mezősas -
Nyugat field. During the data analysis I established that only one liquid circulation is
appropriate for the drilling because the Circulating Bottom Hole Pressure (CBHP) will be
less than the formation pressure. This process is beneficial both economically and
technologically. On the other hand, special compressor station and N2 generation unite are
not necessary.
29
8.2 Description of the Mezősas - Nyugat field
The Mezősas - Nyugat field is 240 km far from Budapest, it is border county of
Hajdú-Bihar and Békés, between Mezősas and Komádi village. The Mezősas - Nyugat
field problems are the traps weak porosity and permeability. The field property
determination is based on laboratory measurement of core samples from 14 wells. The
traps are bordered by tectonic elements and these are located in separated hydrodynamic
system blocks. Every trap is overpressurized which exceeds 70% of the normal pressure.
8.3 Reason of underbalanced drilling at Mezősas - Nyugat field
Between 1992 and 1999 in the Mezősas-Nyugat field 13 wells was drilled in
conventional way, namely with overbalanced drilling and another well was drilled in
Mezősas southwest region area. After the well completion the production started but those
wells did not perform the expected production volume. Improvement was waited for the
hydraulic fracturing and the acidizing but the required production growth failed.
Furthermore, for the solution of the problem, horizontal well was drilled, but it wasn’t so
effective either. Because of the formation bad facies, trap weak porosity, permeability and
the listed historical facts, underbalanced drilling can be the best solution considering the
growth of production. The other necessary condition is the formation strength which is
appropriate for the underbalanced operation because the hydrocarbon bearing reservoir is
conglomerate which strength is suitable for this operation.
30
8.4 Risk assessment, surface pressure and influx rate recommendation
I used the Weatherford Underbalanced Control book’s Classification System for
evaluation of underbalanced drilling simulation which based on the International
Associated of Drilling Contractors (IADC). This part gives a risk assessment for the type
of reservoir, reservoir pressure gradient, surface pressure, influx rate. During the planning
of Mezősas - Nyugat field’s well I considered this recommendation.
8.4.1 Risk assessment at different type of reservoir
The Weatherford Underbalanced Control book gives risk assessment suggestion for
the reservoir pressure and the reservoir type in the Underbalanced Classification Matrix.
The next example provides a quid to risk assessment.
The classification matrix numbers meaning are the following:
1 - Gas Drilling
2 - Mist Drilling
3 - Foam Drilling
4 - Gasified Liquid Drilling
5 - Liquid Drilling
Figure 9: Underbalanced Classification Matrix
Source: Weatherford: Introduction To Underbalanced Drilling
Underbalanced Classification Matrix
Productivity Enhancement
bar/m
Sw
eet G
as W
ells
So
ur G
as W
ells
Sw
eet O
il Wells
So
ur O
il Wells
0.0470 1 1 1 1
0.0823 2 2 2 1
0.0979 4 3 4 2
0.1176 4 3 4 4
0.1411 4 3 4 5
>0.1411 5 5 5 5
LOW MODERATE HIGH
RISK RISK RISK
31
The Mezősas – Nyugat field reservoir is Sweet gas reservoir and the reservoir pressure
gradient is 0.168 bar / m which falls into the high risk zone and during the numbering I
chose mud circulation for the simulation.
8.4.2 Surface Pressure Control recommendation
The other suggestion is the Weatherford Surface Pressure Control which gives
surface pressure recommendation at different types of fluid systems where the surface
pressure is in the safe operation values. During the Mezősas – Nyugat field’s well
simulation I used mud system where the applicable surface pressure maximum rate is 500
psi which is approximately 34 bars.
Figure 10: Surface Pressure
Source: Weatherford: Introduction To Underbalanced Drilling
32
8.4.3 The Williams 7100 Rotating Control Head
I chose the Weatherford Williams 7100 Rotating Head pressure range and flow
range for the Mezősas – Nyugat field’s well simulation. The Weatherford gave the exact
pressure, influx volume that can be managed with this equipment. This Rotating Control
Diverter (RCD) pressure and flow range limitation good consideration for the safe design
opposite that the wellhead pressure range is 34 bar.
Pressure
Range 1 = 50% RCD dynamic rating.
Range 2 = 50% to 90% of the RCD dynamic rating.
Surface Flow Rates
Range 1 = 60% of the separator system flow rate capacity or the upper erosion limit.
Range 2 = 60% to 90% of the separation system flow rate capacity or the upper erosion
limit. Erosional velocity is normally taken as 54 m/min
Once a baseline trend of flow rates and pressure have been established, any change
or deviation from trends in fluid returns, annular bottomhole pressure readings or standpipe
pressure should be investigated with other surface data and the necessary course of action
should be decided if well control procedures have to be activated.
Figure 11: Underbalanced Flow Control Matrix
Source: Weatherford: Introduction To Underbalanced Drilling
Adjust System bottom
hole pressure
Adjust System bottom Adjust System bottom
hole pressure hole pressure
Surface Pressures For Williams 7100 Rotating Head
>283.100 Shut in on Rig BOP Shut in on Rig BOP Shut in on Rig BOP
Underbalanced Flow Control Matrix
Flow rates 0 to 80 bar 80 to 155 bar > 155 bar
m3/day
0 to 141.500 Managable Shut in on Rig BOP
141.500 to 283.100 Shut in on Rig BOP
33
Depending on the changes observed and other information available, three possible
actions are likely, and using traffic light colors makes the matrix easily understandable. In
the Mezősas – Nyugat field’s UBD simulation I also used these recommendations:
Continue underbalanced drilling as normal green light. green
Perform corresponding action. yellow
Stop drilling and shut-in well on the rig BOP. red
8.5 The simulation optimization
For my well optimization I modified the program. I built in the program more
equation that I present in the next subsection. During the simulation I considered the
Weatherford recommendation and I chose the following data:
Figure 12: limitations
reservoir risk high risk
aplied fluid system mud -
surface pressrue lim. 34 bar
accepted influx rate 141.500 Nm3/day
34
8.5.1 The built - in flowing areas
The planned target zone True Vertical Depth (TVD) is between 2620 m and 2750
m. When we want to implement the underbalanced drilling at the target zone, first we have
to exclude the upper zone, because of the unproblematic underbalanced operation, namely
openhole collapse and upper layer influx. For avoid the listed problems, 7” casing was
built in 2620 m depth. I used the usual drill pipe outside diameter at the simulation which
is 3 ½. I prepared simplified well geometries for the hydraulic simulation with both of
casing inside and drill pipe outside diameter. During the simulation I used the plotted
pressure gradients.
The simplified well geometry with pressure gradient:
Figure 13: The simplified well geometry with plotted pressure gradient line
35
8.5.2 The built - in “for cycle”:
The planned openhole section is 130 m which is hydrocarbon bearing reservoir and
I divided this section into 13 different lengths. With this 10 m increment I can exactly
simulate the influx changing. I built in “for cycle” into the program. The “for cycle” can
increase some parameter parallel with the increased 10 m increment rate such as the pore
pressure, openhole length, RCD pressure.
The “for cycle”:
% density: kg/m3,
% welldepth m
% preservoir bar
% openhole m
% prealsurface bar
% pore pressure calculation = preservoir =
% 2620 m is the top of reservoir. The pore pressure gradient is 0.168 bar/m.
% 2620*0.168=440 bar
% 2620 m - 2750 m is gas reservoir. Gas pressure gradient is 0.21 bar/10 m
for i=(0:13),
density = 1520;
welldepth = 2620 + i*10;
preservoir= 440 + i*0.21;
boxlength = welldepth/nobox;
openhole = 0 + i*10;
prealsurface = (1 + i*2)*10^5;
%prealsurface = 3*10^5;
[pbot,error] = itsolver(nopoints,boxlength,welldepth,gasrate,liquidrate);
end
36
8.5.3 The built - in productivity index
During my work I built-in exact productivity index equation into the simulation for
the given well gas influx analysis. Based on the given information I considered the
reservoir as a gas reservoir because of safe design and security consideration. I used the
general gas productivity index equation for the simulation. For the gas viscosity calculation
I used the Lee at al. gas viscosity equitation which gives appropriate value at different
pressure and temperature. I regarded some data constant such as the drainage radius, well
bore radius. The drainage radius was determined with distance measurement between wells
on the field scale map. (Bódi, 2007)
The productivity equitation:
( ( ))
Where:
Qg = gas flow rate, m3/s
k = permeability to gas, m2
h = net formation thickness, m
Tsc = standard condition temperature, K
P = Reservoir pressure, Pa
Pwf = Flowing Bottom Hole Pressure, Pa
T = Reservoir temperature, K
Psc = standard – condition pressure, Pa
µg = gas viscosity, Pa s
z = deviation factor, -
re = distance from the center of wellbore, m
rw = wellbore radius, m
37
The Lee at al. gas viscosity equitation
In the Lee at al. gas viscosity equitation the parameter is given in field units, due to
this fact I convert the metric unit into field unit at this calculation. (Takács, 2012.)
)
Where:
Y = 2.4 – 0.2X
µg = gas viscosity, cp
ρ = gas density, g/cm3
P = pressure, psia
T = temperature, R
Mg = gas molecular weight = 28 yg
yg = CH4 gas relative density, -
Z = gas deviation factor, -
38
8.5.4 The built - in gas density model
Tpr = pseudoreduced temperature, K
Ppr = pseudoreduced pressure, bar
T = actual temperature, K
P = actual pressure, bar
z = gas deviation factor, -
Bg = gas volume factor,-
ρ = density, kg/m3
(Turzó), (Pápay)
39
8.5.5 The built - in friction factor model
Annular flow of Power Law fluid:
Frictional pressure drop:
Reynolds number
Where “do” is the annulus OD and “di” is the ID.
Laminar flow:
Turbulent flow
Δp = friction pressure drop, Pa
do = drill pipe outer diameter, m
di = casing inner diameter, m
f = friction factor,-
V = average velocity, m/s
ρ = mixture density, kg/m3
Re = Reynolds number,-
n = flow behavior index,-
Δz = pressure loss increment, m
(PetroWiki, 2014)
40
For the friction factor model I used the following mud data (Jim Friedheim, 2005):
8.6 Simulation
During the Weatherford suggestion I did permeability sensitivity investigation. I
regarded 34 bar pressure range for the expected maximum RCD pressure range. However
the Weatherford Williams 7100 Rotating Head can handle the pressure until 80 bar
pressure rate but at the applied fluid system the suggested maximum surface pressure rate
is 34 bar. The planned well openhole section is 130 m between 2620 m TVD depth and
2750 m TVD depth. I built in the program one simulation method which simulates the
influx parallel with the increase depth at constant permeability. There is more option for
Circulating Bottom Hole Pressure (CBHP) modification which can be also modified in the
simulation:
the RCD pressure can be increased
the pump mud flow rate can be increased
the mud density can be increased
Figure 14: Mud rheology
Shear strain
600
300
200
100
6
3
PV
YP
1500 kg/m3 Based Mud
106
62
18
Shear stress
46
29
9
8
44
41
8.6.1 Input data
The given permeability data mostly gives Very Low permeability value between
the depth of 2620 and 2750 m. During the simulation I used more permeability range for
the permeability sensitivity investigation. I used only one permeability range in each
simulation. However it doesn’t cover the reality, but it is a good consideration for the
simulation.
Figure 15: Permeability data
0,01
0,1
1
10
100
1000
10000
2600 2650 2700 2750 2800
Pe
rme
abili
ty (
mD
)
TVD (m)
Core sample permeability
42
In the next data table some data was given by measurement or estimation because
of the lack of information. The drainage radius was given by bisection of well distance
between two wells. The well distance was measured on the field scale map. The collapse
pressure gradient wasn’t given in the field data, for this reason, I gave one acceptable value
for the simulation which can be the appropriate pressure gradient for the formation. I
started the simulation from 1500 kg/m3 mud density which can give approximately 30 bar
pressure drainage between the pore pressure and the Circulating Bottom Hole Pressure
(CBHP). The mud flow rate was 600 l/min in the first simulation. If the simulated result
wasn’t satisfactory regarding the Weatherford suggestion, I modified the RCD pressure,
liquid rate and the mud density.
Figure 16: Input data
Top of form. TVD 2620,0000 m
Bottom of form. TVD 2750,0000 m
Open hole 130,0000 m
7" Casing in. diamater 0,1661 m
3 1/2" Drillpie out. diamater 0,0889 m
6" Drill bit diamater 0,1524 m
Drainage radius 400,0000 m
Wellbore radius 0,0762 m
Collaps presssure grad 0,1200 bar/m
Reservoir pressure grad 0,1680 bar/m
Gas pressure grad 0.0210 bar/m
Fracture pressure grad 0,1900 bar/m
Thermal gradient 5,6700 C/100m
Temperature sc. 15,0000 C
Planed mud density 1500,0000 kg/m3
Planed flow rate 600,0000 l/min
CH4 density sc. 0,7170 kg/m3
CH4 relative density 0,6000 -
43
8.6.2 Simulation results
Very Low, 0.05 mD Permeability pay zone without any intervention:
In the first step I simulated the influx and the Circulating Bottom Hole Pressure
(CBHP) change at Very Low permeability value. At Very Low permeability, during the
given simulation data, the gas influx are in the safe suggested range beside at low constant
RCD pressure. Negligible amount of influx gas can be seen in the first recovered data
where the permeability value is 0.05 mD. The maximum value of gas influx is only 15 450
m3/day. This value hasn’t decreased the Bottom Hole Pressure (BHP) in huge steps. For
this reason intervention is not necessary.
Figure 17: Very Low, 0.05 mD permeability pay zone without any intervention
liquid rate: 600 liter/min
TVD openhole collaps CBHP pore fracture RCD permeablity influx
m m bar bar bar bar bar mD m3/day
2620 0 314 412 440,0 498 3 0.05 -
2630 10 316 412 440,2 500 3 0.05 1 641
2640 20 317 410 440,4 502 3 0.05 2 096
2650 30 318 351 440,6 504 3 0.05 7 900
2660 40 319 410 440,8 505 3 0.05 4 638
2670 50 320 412 441,1 507 3 0.05 5 605
2680 60 322 410 441,3 509 3 0.05 6 495
2690 70 323 408 441,5 511 3 0.05 9 914
2700 80 324 410 441,7 513 3 0.05 11 029
2710 90 325 411 441,9 515 3 0.05 12 066
2720 100 326 406 442,1 517 3 0.05 13 028
2730 110 328 408 442,3 519 3 0.05 13 912
2740 120 329 403 442,5 521 3 0.05 14 720
2750 130 330 405 442,7 523 3 0.05 15 450
mud density: 1500 kg/m3
44
Very Low, 0.1 mD permeability pay zone without any intervention:
At 0.1 md permeability pay zone simulation firstly I didn’t take any intervention.
During this simulated data, the accelerated bottomhole pressure decreasing should cause
openhole collapse, but the influx gas is in manageable situation yet. Because of the low
Circulating Bottom Hole Pressure (CBHP) at 130 m openhole section, I increased the RCD
pressure rate in the next simulation.
Figure 18: Very Low, 0.1 mD permeability pay zone without any intervention
liquid rate: 600 liter/min
TVD openhole collaps CBHP pore fracture RCD permeablity influx
m m bar bar bar bar bar mD m3/day
2620 0 314 412 440,0 498 3 0.1 -
2630 10 316 409 440,2 500 3 0.1 2 174
2640 20 317 407 440,4 502 3 0.1 4 946
2650 30 318 402 440,6 504 3 0.1 9 400
2660 40 319 398 440,8 505 3 0.1 12 234
2670 50 320 393 441,1 507 3 0.1 14 917
2680 60 322 388 441,3 509 3 0.1 21 769
2690 70 323 383 441,5 511 3 0.1 29 775
2700 80 324 372 441,7 513 3 0.1 44 114
2710 90 325 368 441,9 515 3 0.1 43 110
2720 100 326 363 442,1 517 3 0.1 53 789
2730 110 328 352 442,3 519 3 0.1 84 956
2740 120 329 347 442,5 521 3 0.1 70 592
2750 130 330 342 442,7 523 3 0.1 83 658
mud density: 1500 kg/m3
45
Very Low, 0.1mD permeability pay zone with increasing RCD pressure:
Because of the chance of the bottomhole collapse, I did the simulation one more
time with increasing RCD pressure. During the simulation I increased the RCD pressure
with decreasing openhole section. With this modification the bottomhole pressure
remained large enough for the openhole stability.
Figure 19: Very Low, 0.1mD permeability pay zone with increasing RCD pressure
liquid rate: 600 liter/min
TVD openhole collaps CBHP pore fracture RCD permeablity influx
m m bar bar bar bar bar mD m3/day
2620 0 314 410 440,0 498 1 0.1 -
2630 10 316 408 440,2 500 2 0.1 2 014
2640 20 317 407 440,4 502 3 0.1 4 211
2650 30 318 406 440,6 504 4 0.1 6 624
2660 40 319 404 440,8 505 5 0.1 9 159
2670 50 320 403 441,1 507 6 0.1 11 914
2680 60 322 402 441,3 509 7 0.1 14 957
2690 70 323 400 441,5 511 8 0.1 17 973
2700 80 324 399 441,7 513 9 0.1 21 228
2710 90 325 398 441,9 515 10 0.1 24 754
2720 100 326 397 442,1 517 11 0.1 28 355
2730 110 328 395 442,3 519 12 0.1 31 997
2740 120 329 394 442,5 521 13 0.1 35 781
2750 130 330 393 442,7 523 14 0.1 39 855
mud density: 1500 kg/m3
46
Very Low, 0.2 mD permeability pay zone with increasing RCD pressure:
At 0.2 mD permeability simulation I increased the RCD pressure range parallel the
increased openhole section. The RCD pressure reached the pressure limitation at 130 m
openhole section for this reason I did this simulation again with the liquid rate
modification.
Figure 20: Very Low, 0.2mD permeability pay zone with increasing RCD pressure
liquid rate: 600 liter/min
TVD openhole collaps CBHP pore fracture RCD permeablity influx
m m bar bar bar bar bar mD m3/day
2620 0 314 410 440,0 498 1 0.2 -
2630 10 316 406 440,2 500 4 0.2 4 348
2640 20 317 402 440,4 502 6 0.2 9 681
2650 30 318 397 440,6 504 9 0.2 16 190
2660 40 319 393 440,8 505 11 0.2 24 103
2670 50 320 387 441,1 507 14 0.2 33 452
2680 60 322 382 441,3 509 16 0.2 43 537
2690 70 323 377 441,5 511 19 0.2 54 698
2700 80 324 373 441,7 513 21 0.2 66 222
2710 90 325 370 441,9 515 24 0.2 77 854
2720 100 326 368 442,1 517 26 0.2 89 345
2730 110 328 367 442,3 519 29 0.2 99 523
2740 120 329 367 442,5 521 31 0.2 108 909
2750 130 330 367 442,7 523 34 0.2 116 978
mud density: 1500 kg/m3
47
Very Low 0.2 mD permeability pay zone with increasing RCD pressure and increased
1000 liter/min. flow rate:
At 0.2 mD permeability pay zone and with 600 liter/min mud flow rate the well is
manageable with the help of RCD, which reached the suggested surface pressure
limitation. For this reason I modified the liquid flow rate up to 1000 liter/min. At this
interaction during the simulated data, the well is remained safe, regarding both RCD
pressure, gas influx and collapse problem.
Figure 21: Very Low, 0.2mD permeability pay zone with increasing RCD pressure and increasesd 1000l/min flow
rate
liquid rate: 1000 liter/min
TVD openhole collaps CBHP pore fracture RCD permeablity influx
m m bar bar bar bar bar mD m3/day
2620 0 314 419 440,0 498 1 0.2 -
2630 10 316 419 440,2 500 3 0.2 2 923
2640 20 317 419 440,4 502 5 0.2 6 487
2650 30 318 419 440,6 504 7 0.2 10 399
2660 40 319 418 440,8 505 9 0.2 14 756
2670 50 320 418 441,1 507 11 0.2 34 474
2680 60 322 417 441,3 509 13 0.2 25 947
2690 70 323 415 441,5 511 15 0.2 33 147
2700 80 324 413 441,7 513 17 0.2 44 153
2710 90 325 410 441,9 515 19 0.2 51 632
2720 100 326 408 442,1 517 21 0.2 63 246
2730 110 328 405 442,3 519 23 0.2 77 978
2740 120 329 402 442,5 521 25 0.2 89 805
2750 130 330 400 442,7 523 27 0.2 102 395
mud density: 1500 kg/m3
48
Low, 1mD permeability pay zone with increasing RCD pressure and increased 1500
l/min. mud rate:
However, the Mezősas - Nyugat field reservoir permeability is Very Low - which is
based on research data - it may occur that this well will contain Low or Moderate
permeable pay zone. For this reason I examined the well’s behavior at Low permeability
value. At 1 md, the well became uncontrolled opposite the increased flow rate and the
increased RCD pressure. The well influx was more than the Weatherford suggested
limitation, and from 110 m openhole the RCD pressure exceeded the prescribed value. Due
to these facts, mud density modification can be the appropriate solution for the next
simulation.
Figure 22: Low, 1 mD permeability pay zone with increasing RCD pressure and increased 1500 l/min flow rate.
liquid rate: 1500 liter/min
TVD openhole collaps CBHP pore fracture RCD permeablity influx
m m bar bar bar bar bar mD m3/day
2620 0 314 429 440,0 498 1 1 -
2630 10 316 425 440,2 500 4 1 17 928
2640 20 317 413 440,4 502 7 1 64 162
2650 30 318 390 440,6 504 10 1 94 000
2660 40 319 379 440,8 505 13 1 178 687
2670 50 320 368 441,1 507 16 1 285 804
2680 60 322 366 441,3 509 19 1 279 878
2690 70 323 365 441,5 511 22 1 345 045
2700 80 324 366 441,7 513 25 1 388 777
2710 90 325 370 441,9 515 28 1 393 112
2720 100 326 372 442,1 517 31 1 438 221
2730 110 328 377 442,3 519 34 1 584 208
2740 120 329 378 442,5 521 37 1 629 145
2750 130 330 380 442,7 523 40 1 672 698
mud density: 1500 kg/m3
49
Low, 1mD permeability pay zone with increasing RCD pressure, increased 1500
l/min. mud rate and increased 1520 kg/m3 mud density:
During the recovered data, the gas flow rate remained uncontrolled opposite the
increased flow rate, increased mud density and the increased RCD pressure. For this reason
in the next steps I plot the recovered data for the problem understanding.
The problem examination
For the problem understanding I compared the Very Low Permeability pay zone and
the Low Permeability pay zone simulation result with the plot of the recovered data.
I depict the Circulating Bottom Hole Pressure (CBHP) change at Very Low permeability
pay zone and at Low permeability pay zone parallel with the increased openhole depth. I
depict the CBHP change without influx and with influx parallel with the increased
openhole depth. I depict also the pore pressure and the collapse pressure range parallel
with the increased openhole depth.
Figure 23: Low, 1 mD permeability pay zone with increasing RCD pressure, Increased 1500 l/min mud rate and
increased 1520kg/m3 mud density
liquid rate: 1500 liter/min
TVD openhole collaps CBHP pore fracture RCD permeablity influx
m m bar bar bar bar bar mD m3/day
2620 0 0 434 440 498 1 1 -
2630 10 0 433 440 500 3 1 6 795
2640 20 0 419 440 502 5 1 57 724
2650 30 0 392 441 504 7 1 95 167
2660 40 0 378 441 505 9 1 166 078
2670 50 0 369 441 507 11 1 216 795
2680 60 0 365 441 509 13 1 281 129
2690 70 0 365 441 511 15 1 323 031
2700 80 0 365 442 513 17 1 364 342
2710 90 0 367 442 515 19 1 462 111
2720 100 0 368 442 517 21 1 506 537
2730 110 0 371 442 519 23 1 476 297
2740 120 0 373 443 521 25 1 511 004
2750 130 0 376 443 523 27 1 544 256
mud density: 1520 kg/m3
50
8.6.3 Simulation result examination at Very Low, 0.1mD permeability
First of all I did one simulation without influx because I want to know the
drawdown between the pore pressure and the Circulating Bottom Hole Pressure (CBHP).
During the given data it gives 30 - 10 bar pressure different, which is a good result
regarding the underbalanced condition. In the next step I simulated the CBHP with gas
influx. During the simulation I increased the RCD pressure parallel with the increased
openhole length. I used constant mud density and liquid flow rate value. I got good result
where the CBHP is manageable. The gas influx and the surface pressure are also remained
in the suggested value.
0.1 mD permeability pay zone simulation, openhole depth vs. CBHP changes
Figure 24: 0.1 mD permeability pay zone simulation, openhole depth vs. CBHP changes
2600
2620
2640
2660
2680
2700
2720
2740
2760
300 350 400 450
TVD
(m)
Pressure (bar)
Openhole vs CBHP
CBHP at influx
collapse
pore
CBHP at zero influx,3 barRCD
51
0.1 mD permeability pay zone simulation, pressure profile
The pressure profile is appropriate for the underbalanced demand regarding to the
surface pressure and the annulus pressure. The Annulus pressure is between the collapse
and pore pressure line. The collapse, fracture, pore pressure line validity are between 2620
m - 2750 m depth because the upper layer was excluded by 7” casing.
Figure 24: 0.1 mD permeability pay zone simulation, pressure profile
0
500
1000
1500
2000
2500
3000
0 100 200 300 400 500 600
TVD
(m
)
Pressure (bar)
Pressure profile
annulus
collapse
fracture
pore
52
0.1 mD permeability pay zone simulation, fluid velocity
The mixture velocity gives acceptable result for the erosional velocity limitation
value which is 54 m/min (0.9 m/s) during the Weatherford suggestion.
0.1 mD permeability pay zone simulation, mixture density
The mixture density decreased rapidly from 1000 m depth where the gas starts to
expand.
Figure 25: 0.1 mD permeability pay zone simulation, fluid velocity
Figure 26: 0.1 mD permeability pay zone simulation, mixture density
0
500
1000
1500
2000
2500
3000
0 0,5 1 1,5 2 2,5 3
TVD
(m
)
velocity (m/s)
Fluid velocity
liquid velocity
gas velocity
mixture velocity
0
500
1000
1500
2000
2500
3000
0 500 1000 1500 2000
MD
(m
)
mixture density (kg/m3)
Mixture density
mixture density
53
8.6.4 Simulation result examination at Low, 1 mD permeability
At 1 mD permeable pay zone I did simulation with the same idea than at the 0.1
mD permeable pay zone. I did some modification in the program. I increased the flow rate
from 600 l/min to 1500 l/min and I also increased the mud density from 1500 kg/m3 to
1520 kg/m3. At those simulations where I disregarded the influx, there was only 5 bar
pressure drawdown between pore pressure and the Circulating Bottom Hole Pressure
(CBHP). After 50 m openhole section the simulation become overbalanced where I
disregarded the gas influx. At the simulation of methane gas influx, the CBHP decreased
rapidly and almost reached the collapse line opposite the increased surface pressure, mud
density and the flow rate modification. I tried to get better result with higher RCD pressure
increment, but the influx didn’t decrease so much and beside the huge amount of gas influx
the RCD pressure reached its limitation.
1 mD permeability pay zone simulation, openhole vs. CBHP changes
Figure 27: 1 mD permeability pay zone simulation, openhole vs. CBHP changes
2600
2620
2640
2660
2680
2700
2720
2740
2760
300 350 400 450 500
TVD
(m
)
Pressure (bar)
Openhole vs FBHP
CBHP at influx
collapse
pore
CBHP
54
1 mD permeability pay zone simulation, pressure profile
The pressure profile is appropriate for the underbalanced condition because the
surface pressure 27 bar and the annulus pressure between the Circulating Bottom Hole
Pressure (CBHP) and the pore pressure line, but the amount of gas influx remained in
unmanageable value. The collapse, fracture, pore pressure line validity is between 2620 m
- 2750 m depth because the upper layer was excluded by 7” casing.
Figure 28: 1 mD permeability pay zone simulation, pressure profile
0
500
1000
1500
2000
2500
3000
0 100 200 300 400 500 600
TVD
(m
)
Pressure (bar)
Pressure profile
collapse
annulus
pore
fracture
55
1 mD permeability pay zone simulation, fluid velocity
During the simulation huge amount of gas influx caused high gas velocity. For this
reason the mixture velocity does not give acceptable value regarding the erosional velocity
limitation which is 54 m/min (0.9 m/s) during the Weatherford suggestion.
Figure 29: 1 mD permeability pay zone simulation, fluid velocity
0
500
1000
1500
2000
2500
3000
0 5 10 15 20 25 30
TVD
(m)
velocity (m/s)
Fluid velocity
mixture velocity
gas velocity
liquid velocity
56
1 mD permeability pay zone simulation, mixture density
The mixture density decreased rapidly from the bottom of the well which caused
further gas influx.
8.7 The Mezősas - Nyugat field’s evaluation and recommendation
During the data analysis I established that only the Very Low permeability layers
(<1mD) are suitable for Underbalanced Drilling (UBD) at overpressurized gas bearing
reservoir. The overpressurized, Low - High permeability (>1mD) gas bearing reservoir is
not suitable for the underbalanced drilling. At the Low (1mD) permeable reservoir layer’s
simulation the gas influx remained in unmanageable condition opposite the increased mud
density, liquid rate and increased Rotating Control Diverter (RCD) pressure which can
cause overbalance situation without gas influx. The problem is that the methane gas can
rapidly lighten the mud density at Low (>1mD) permeability and this process causes more
gas influx during the increasing openhole pay zone. Thanks to the literature resource I
found more underbalanced drilling operation’s report at gas field reservoir which was tight
gas reservoir where the permeability is less than 0.1 mD. This information also justifies my
simulation result beside the Weatherford and International Associated of Drilling
Contractor (IADC) recommendation.
Figure 30: 1 mD permeability pay zone simulation, mixture density
0
500
1000
1500
2000
2500
3000
0 200 400 600 800 1000 1200
TVD
(m)
mixture density (kg/m3)
mixture density
mixture density
57
Based on the permeability data at the Mezősas - Nyugat field which are mostly
between Very Low – Low permeability value and based on the received field data and
simulated data the Mezősas - Nyugat field can be suitable for the Underbalanced Drilling,
but for the exact decision more reservoir information, more data analysis and investigation
are needed.
58
9 Conclusion
At Low 1 mD permeability I tried to solve the influx and the surface pressure problem
with increased mud density 1520 kg/m3, increased 1500 l/min liquid rate. However the
Circulating Bottom Hole Pressure (CBHP) and gas influx decreased, but it remained in
unmanageable condition. The system reached the gas influx limitation after 30 m openhole
depth.
At Very Low permeability the gas influx is not significant beside constant 3 bar RCD,
low 600 l/min flow rate and at 1500 kg/m3 mud weight. At 0.1 mD permeability pay zone
simulation with increased RCD pressure the CBHP line followed the pore pressure line
with a 30-10 bars drawdown.
Above Very Low permeability value the gas influx becomes unmanageable. At
relatively few pressure differences (approximately 5 bar) cause huge amount of gas influx -
especially at increasing openhole length - which causes further CBHP decreasing. This
reason causes unmanageable condition.
For these reasons the overpressurized, Low - High permeable gas bearing reservoir is
unsuitable for the underbalanced drilling, based on simulated data and Weatherford
suggestion. Little pressure drawdown can cause huge amount of gas influx into the
borehole which became out of control and it causes hazardous and dangerous situation.
With this simulation the expected influx in the next openhole section can be predicted.
This simulation gives a good overview for the gas influx, flow rate, mud density and WHP
pressure impact. For this reason the simulation can help understand the expected events,
which can occur in field condition.
59
10 Appendices
Matlab Codes:
main.m
% A program developed for calculating well pressures in a % well where we have both liquid and gas flow. The model assumes that we % have steady state conditions (constant flowrates at surface) and no time % variations. The model is based on calculating the correct bottomhole % pressure for certain gas and liquid flow rates and takes into account % both the hydrostatic pressure and frictional pressures.
% All calculations are done using SI units (Pa for pressure),m3/s for % rates.
% Here we specify the vertical depth of the well and % and the number of boxes we want in our calulations. % Based on this, the boxlength is found and used in the calculations.
global density; global welldepth global permeability global openhole global liquidrate global prealsurface global nobox global preservoir;
% nopoints is an index array keeping track of the end point of the boxes.
% Other initialisations like fluid properties and viscosties etc are done % deeper down in the code structure. Please note that you have the change % values there if you want to do changes in these routines. This is also % true for the inner/outer diameter of the annulus.
% Now we will call a function that calculates the pressure along the well % for a given liquid flowrate and a gas rate. We call this function % solver because it is the zero point solver (e.g. regula falsi that % iterates until it finds the correct pressure. This solver routine again % calls upon a function "f(Pbottom)" called wellpressure. The rotine % solver actually finds the correct bottomhole pressure that makes the % function wellpressure become zero "f(Pbottom) = 0". Then we have found the correct % pressure profile.
% INPUT variables % Rates are given in m3/s. We assume only liquid flow first. % Liquid rate is 1500 l/min. Convert to m3/s % Gas rate is in m3/min. Convert to m3/s % Permeability is given in mD
liquidrate = 1500/1000/60; gasrate = 0/60; nobox = 20; permeability = 0; nopoints = nobox+1;
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% density: kg/m3, % welldepth m % preservoir bar % openhole m % prealsurface bar % reservoir pressure calculation = % 2620 m is the top of reservoir. The pore pressure gradient is 0.168 bar/m. % 2620*0.168=440 bar % 2620 m - 2750 m is gas reservoir. Gas pressure gradient is 0.21 bar/10 m
for i=(0:13),
density = 1520; welldepth = 2620 + i*10; preservoir= 440 + i*0.21; boxlength = welldepth/nobox; openhole = 0 + i*10; prealsurface = (1 + i*2)*10^5; %prealsurface = 3*10^5;
[pbot,error] = itsolver(nopoints,boxlength,welldepth,gasrate,liquidrate); end
itsolver.m
function [pbot,error] = itsolver(nopoints,boxlength,welldepth,gasrate,liquidrate)
% The numerical solver implementeted here for solving the equation f(x)= 0 % "wellpressure(pbot)= 0" is called the % Method of Halving the Interval (Bisection Method)
% You will not find exact match for f(x)= 0. Maybe f(x) = 0.0001. By using % ftol we say that if f(x)<ftol, we are satisfied. Since our function % gives results in Pascal, we say that ftol = 1000 Pa gives us a quite good % answer.
ftol = 1000;
% Specify the search interval". xguess is the pressure you guess for the % bottomhole. We here use hydrostic pressure of liquid in the well as our % initial guess. This is of course not nes. correct since we have gas and % friction effects in addtion. But it might be a good starting point for % the iteration. (Remember x is in Pa). 1 Bar = 100 000 Pa. % Set number of iterations to zero
noit = 0;
global density
xguess = density*9.81*welldepth; xint =80000000; x1 = xguess-xint/2.0; x2 = xguess+xint/2.0;
f1 = wellpressure(x1,gasrate,liquidrate,nopoints,boxlength); f2 = wellpressure(x2,gasrate,liquidrate,nopoints,boxlength);
% First include a check on whether f1xf2<0. If not you must adjust your % initial search intervall. If error is 1 and zero pbot, then you must % adjust the intervall here.
if (f1*f2)>=0 error = 1; pbot = 0; else % start iterating, we are now on the track. x3 = (x1+x2)/2.0; f3 = wellpressure(x3,gasrate,liquidrate,nopoints,boxlength);
while (f3>ftol | f3 < -ftol) noit = noit +1 ;
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if (f3*f1) < 0 x2 = x3; else x1 = x3; end
x3 = (x1+x2)/2.0; f3 = wellpressure(x3,gasrate,liquidrate,nopoints,boxlength); f1 = wellpressure(x1,gasrate,liquidrate,nopoints,boxlength);
end error = 0; pbot = x3; a = x3/10^5; global prealsurface; global permeability; global openhole; global influx; global nobox global sumfric; global sumhyd;
disp( sprintf('pbot: %d, (bar: %d, density: %d, permeability: %d,openhole: %d,influx: %d,welldepth:
%d,nobox: %d,sumfric: %d,sumhyd: %d)', [round(a), round(prealsurface/10^5),
density,permeability,openhole,round(influx),welldepth,nobox,round(sumfric/10^5),round(sumhyd/10^5)])); end
wellpressure.m
function f = wellpressure(pbotguess,gasrate,liquidrate,nopoints,boxlength)
% NB, At first stage we assume that our outlet pressure is 1 Bar (atm % pressure). This is the physical boundary condtion that we have to ensure % that out model reaches. If a choke is present. The surface pressure will % be different. It measns that if the choke pressure is 300 000 Pa then the variable below should be % set to this. You change it her:
global prealsurface global sumfric; global sumhyd; global welldepth global permeability global openhole global influx global preservoir
%We now start by the deepest box with the pressure we assume: pbotguess and % for each box, we calculate the pressure and flowrates. In the end, we end up with some surface % rates and a surface outlet pressure. The calculated outlet surface % pressure should equal the physical outlet condition (now 100 000 Pa). We % can therefore define our wellpressure(pbot)=pcalcsurface-prealsurface. % The function will be zero if the correct bottomhole pressure is found.
% Set outer/inner diameter of annulus. Define effective flowarea. Assume a % 7" liner (ID 6.3") and a 3 1/2" drillpipe.
do = 0.166; di = 0.0889;
flowarea = 3.14/4*(do*do-di*di);
% Specify viscosities [Pa s]. In real life they depend on pressure and temp
viscl = 0.001; viscg = 0.0001;
% Define gas slippage parameters. k = 1.2; s = 0.55;
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% gravity g = 9.81;
% The mass rate is the same at surface/atmosphere and at bottomhole since we have steady state. This is
later % used to find the rates at downhole conditions.
liqmassratesurf = liquidrate*roliq(100000.0); liqmassratebhp = liqmassratesurf;
gasmassratesurfinj = gasrate*rogas(100000.0); gasmassratebhpinj = gasmassratesurfinj*rogas(100000.0);
viscg2=0.000027; K=(permeability/1000)*10^-12; Tsc=17+273.15; Psc=1*10^5; termgradiens=5.67/100; T=(termgradiens*welldepth)+273.15; yg=0.6; Tpc=103.9+183.3*yg-39.7*yg^2; Ppc=48.69-3.566*yg-0.766*yg^2; Tpr=T/Tpc; Ppr=preservoir/Ppc; z=1-((3.52*Ppr)/(10^(0.9813*Tpr)))+((0.274*Ppr^2)/(10^(0.8157*Tpr))); PI=((3.14*openhole*K*Tsc)/(T*Psc*viscg2*z*(8.56-0.75))); gasmassratesurfres = PI*((preservoir*10^5)^2-(pbotguess)^2);
influx = gasmassratesurfres*86400;
if (gasmassratesurfres <0) gasmassratesurfres = 0; end
gasmassratebhpinj = gasmassratesurfinj*rogas(100000.0); gasmassratebhpres = gasmassratesurfres*rogas(100000.0); gasmassratebhp = gasmassratebhpinj+gasmassratebhpres;
% Now we loop from the bottom to surface and calculate accross all the % segments until we reach the outlet. % Define the variables needed. Initialise them first for comp efficiency. % vl - liquid vel, vg -gas velocity, % vgs,vls are superficial velocities. % eg-el - phase volume frac gas and gas % p - pressure., rhol liquid density, rhog gas density
vl = zeros(nopoints,1); vg = zeros(nopoints,1); vls = zeros(nopoints,1); vgs = zeros(nopoints,1); eg = zeros(nopoints,1); el = zeros(nopoints,1); p = zeros(nopoints,1); fricgrad = zeros(nopoints-1,1); hydgrad = zeros(nopoints-1,1);
% Before we loop, we define all variables at the inlet of the first % segment(at bottom). As starting point we use the fact that we know the mass % rate of the different phases (same as on top of the well)
% First find the rates in m3/s (downhole) liquidratebhp = liqmassratebhp /roliq(pbotguess); gasratebhp = gasmassratebhp/rogas(pbotguess);
% Find the superficial velocities vls(1) = liquidratebhp/flowarea; vgs(1) = gasratebhp/flowarea;
% Find Phase velocities
vg(1) = k*(vls(1)+vgs(1))+s; eg(1) = vgs(1)/vg(1); el(1) = 1-eg(1); vl(1) = vls(1)/el(1);
63
% Set pressure equal to guessed pressure p(1) = pbotguess;
% Now we loop across the segments.
sumfric = 0; sumhyd = 0;
for i =1:nopoints-1
% use the inlet values for each seg. to calculate hydrostatic % and friction pressure across each segment.
hydgrad(i) = (roliq(p(i))*el(i)+rogas(p(i))*eg(i))*g;
% hydgrad(i) = roliq(p(i))*g;
fricgrad(i) = dpfric(vl(i),vg(i),el(i),eg(i),p(i),do,di); p(i+1)=p(i)-hydgrad(i)*boxlength-fricgrad(i)*boxlength; vls(i+1)=vls(i)*roliq(p(i))/roliq(p(i+1)); vgs(i+1)=vgs(i)*rogas(p(i))/rogas(p(i+1));
vg(i+1) = k*(vls(i+1)+vgs(i+1))+s; eg(i+1) = vgs(i+1)/vg(i+1); el(i+1) = 1-eg(i+1); vl(i+1) = vls(i+1)/el(i+1);
sumfric = sumfric+fricgrad(i)*boxlength; sumhyd = sumhyd+hydgrad(i)*boxlength;
end pout = p(nopoints); f = pout-prealsurface;
%sumfric %sumhyd %gasmassratesurfresinmin %p %el %eg %vg %vl
dpfric.m
function friclossgrad = dpfric(vl,vg,el,eg,pressure,do,di)
% Works for two phase flow. The one phase flow model is used but mixture % values are introduced. % calculate friction loss gradient (Pa/m) % Calculate mix reynolds number
rhol = roliq(pressure); rhog = rogas(pressure); romix = rhol*el+rhog*eg; vmix = vg*eg+vl*el;
n = 0.7732751; K = 0.4989274; Re=(((do-di)^n)*(vmix^(2-n)))*romix/((8^(n-1))*(((3*n+1)/(4*n))^n)*K); if Re<3250-1150*n; fricfactor=16/Re; else fricfactor = 0.001; for i=1:10, fricfactor = (1/(((4/n^0.75)*log10(Re*fricfactor^(1-n/2)))-(0.4/n^1.2)))^2; end end
64
friclossgrad = 2*fricfactor*romix*vmix*abs(vmix)/(do-di); %fricfactor %Re %romix %vmix %friclossgrad % vl % do % di % re
rogas.m
function rhog = rogas(pressure)
%I use avarage temp. for the calculation in K
tk=358;
yg2=0.6; ro=0.717; Tpc2=103.9+183.3*yg2-39.7*yg2^2; Ppc2=48.69-3.566*yg2-0.766*yg2^2; Tpr2=tk/Tpc2; Ppr2=(pressure/10^5)/Ppc2; Z2=1-((3.52*Ppr2)/(10^(0.9813*Tpr2)))+((0.274*Ppr2^2)/(10^(0.8157*Tpr2))); Bg = 3.52*10^-3*((Z2*tk)/((pressure/10^5))); rhog = ro/Bg; %rhog %pressure %Z2
roliq.m
function rhol = roliq(pressure)
% A simple liquid dens model wich takes into pressure varations vs. pressure % is implemented. P0 is the atmosperic pressure. D0 is density at surface % conditions
po = 100000;
global density
rhol = density + (pressure-po)/(1000*1000);
65
11 References
(2014). Retrieved from PetroWiki: http://petrowiki.org/Fluid_friction
Baker, H. (1999). Underbalanced Drilling Manual.
Bódi, T. P. (2007). Hidrodinamilkai kútvizsgálatok alapjai. Miskolc.
Eng.Abd El, F. S. (2012). Underbalanced Drilling Of Horizontal Gas Well.
Fjelde, K. K. (n.d.). Modelling of Well Flow. Norway.
Jim Friedheim, B. H. (2005). Flat rheology drilling fluid.
Jostein, R. (2012). Managing pressure during underbalanced drilling.
Kenneth, P. M. (2007). Managed pressure drilling - What is it anyway? World Oil.
Leading, E. A. (2002). Introduction to Underbalanced Drilling.
Maurer, E. I. (1996). Underbalanced drilling and completion manual. Houston.
Mohamed, M. A. (2012). Investigation of transient scenarios in undrbalanced drilling.
Pápay, J. P. (n.d.). gas deviation factor.
Rig Train, T. D. (2001). Well Control For The Drilling Team.
Szabó, T. P. (2006). Alúlegyensúlyozott fúrási technológia folyadákainak vizsgálata.
Takács, G. P. (2012.). 2. Production Engineering Fundamentals. Miskolc.
Turzó, Z. P. (n.d.). Fluidumok tulajdonságai. Miskolc.
Weatherford. (2006). Introduction To Underbalanced Drilling.