underbalanced drilling simulation

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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


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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


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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


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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


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Figure 8: Parasita string injection


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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.

http://www.uis.no/article.php?articleID=75244&categoryID=11199

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


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


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


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




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


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




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


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




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


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




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


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.




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


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




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


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;

60

% 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 ;

61

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;

62

% 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.

underbalanced drilling simulation

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