Underbalanced Drilling Simulation

Transcription

1 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

2 Table of contents 1 Acknowledgment Summary Introduction Underbalanced drilling theoretical background Underbalanced drilling definition Overbalanced drilling Reason of underbalanced drilling The underbalanced drilling techniques Underbalanced drilling determination Underbalanced drilling advantages Underbalanced drilling disadvantages Underbalanced drilling equipment Gas injection equipment Air compressors Nitrogen Generation System (NGU) Booster compressors The nitrogen generation system completion Well control equipment s Non return valves Rotating Control Diverters (RCD) Choke manifold Separator equipment Flares Drilling fluid and flow systems Drilling fluid Drilling with single phase fluid Gas injection Drillpipe injection Annular injection Parasite string injection Gases for underbalanced drilling Nitrogen Natural gas Underbalanced drilling modeling at Mezősas - Nyugat field Introduction

3 8.2 Description of the Mezősas - Nyugat field Reason of underbalanced drilling at Mezősas - Nyugat field Risk assessment, surface pressure and influx rate recommendation Risk assessment at different type of reservoir Surface Pressure Control recommendation The Williams 7100 Rotating Control Head The simulation optimization The built - in flowing areas The built - in for cycle : The built - in productivity index The built - in gas density model The built - in friction factor model Simulation Input data Simulation results Simulation result examination at Very Low, 0.1mD permeability Simulation result examination at Low, 1 md permeability The Mezősas - Nyugat field s evaluation and recommendation Conclusion Appendices References

4 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. 4

5 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. 5

6 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. 6

7 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. 7

8 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) 8

9 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. 9

10 Figure 1: Difference between overbalanced and underbalanced drilling Source: Weatherford: Introduction To Underbalanced Drilling 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. 10

11 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. 11

12 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

13 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 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 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) 13

14 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) 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 N 2 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. 14

15 Figure 3: The nitrogen generation system Source: Weatherford: Introduction To Underbalanced Drilling 5.2 Well control equipment s flowing. In this section I want to introduce the equipment which ensures the controlled fluid 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) 15

16 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) 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) 16

17 Figure 4: Rotating diverter with pressure range Source: Weatherford: Introduction To Underbalanced Drilling 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. 17

18 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) 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. 18

19 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) 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 19

20 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 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. 20

21 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 21

22 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) 22

23 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 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) 23

24 Figure 6: Drillpipe injection Source: Baker Hughes: Underbalanced DrillingManual 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. 24

25 Figure 7: Annular injection Source: Baker Hughes: Underbalanced DrillingManual 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. 25

26 Figure 8: Parasita string injection Source: Baker Hughes: Underbalanced DrillingManual 26

27 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, nonflammable 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. 27

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 N 2 generation unite are not necessary. 28

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. 29

30 Sour Oil Wells Sweet Oil Wells Sour Gas Wells Sweet Gas Wells 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 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. Underbalanced Classification Matrix Productivity Enhancement bar/m > LOW MODERAT E HIGH RISK RISK RISK Figure 9: Underbalanced Classification Matrix Source: Weatherford: Introduction To Underbalanced Drilling The classification matrix numbers meaning are the following: 1 - Gas Drilling 2 - Mist Drilling 3 - Foam Drilling 4 - Gasified Liquid Drilling 5 - Liquid Drilling 30

31 The Mezősas Nyugat field reservoir is Sweet gas reservoir and the reservoir pressure gradient is bar / m which falls into the high risk zone and during the numbering I chose mud circulation for the simulation 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 31

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. Underbalanced Flow Control Matrix Surface Pressures For Williams 7100 Rotating Head Flow rates 0 to 80 bar 80 to 155 bar > 155 bar m3/day Adjust System bottom 0 to Managable Shut in on Rig BOP hole pressure Adjust System bottom Adjust System bottom to Shut in on Rig BOP hole pressure hole pressure > Shut in on Rig BOP Shut in on Rig BOP Shut in on Rig BOP Figure 11: Underbalanced Flow Control Matrix Source: Weatherford: Introduction To Underbalanced Drilling 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. 32

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: reservoir risk high risk aplied fluid system mud - surface pressrue lim. 34 bar accepted influx rate Nm 3 /day Figure 12: limitations 33

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 34

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 bar/m. % 2620*0.168=440 bar % 2620 m m is gas reservoir. Gas pressure gradient is 0.21 bar/10 m for i=(0:13), density = 1520; welldepth = i*10; preservoir= 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 35

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: Q g = gas flow rate, m 3 /s k = permeability to gas, m 2 h = net formation thickness, m T sc = standard condition temperature, K P = Reservoir pressure, Pa P wf = Flowing Bottom Hole Pressure, Pa T = Reservoir temperature, K P sc = standard condition pressure, Pa µ g = gas viscosity, Pa s z = deviation factor, - r e r w = distance from the center of wellbore, m = wellbore radius, m 36

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 = X µg = gas viscosity, cp ρ = gas density, g/cm3 P = pressure, psia T = temperature, R Mg = gas molecular weight = 28 y g y g = CH 4 gas relative density, - Z = gas deviation factor, - 37

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/m 3 (Turzó), (Pápay) 38

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/m 3 Re = Reynolds number,- n = flow behavior index,- Δz = pressure loss increment, m (PetroWiki, 2014) 39

40 For the friction factor model I used the following mud data (Jim Friedheim, 2005): Shear strain PV YP 1500 kg/m3 Based Mud Shear stress Figure 14: Mud rheology 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 40

41 Permeability (md) 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. Core sample permeability ,1 0, TVD (m) Figure 15: Permeability data 41

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. 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 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/m 3 Planed flow rate 600,0000 l/min CH4 density sc. 0,7170 kg/m 3 CH4 relative density 0, Figure 16: Input data 42

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 m3/day. This value hasn t decreased the Bottom Hole Pressure (BHP) in huge steps. For this reason intervention is not necessary. mud density: 1500 kg/m 3 liquid rate: 600 liter/min TVD openhole collaps CBHP pore fracture RCD permeablity influx m m bar bar bar bar bar md m 3 /day , , , , , , , , , , , , , , Figure 17: Very Low, 0.05 md permeability pay zone without any intervention 43