Drilling the Rate of Penetration and bit life.

Drilling engineering is an essential part of of the petroleum industry including the reservoir reservoir engineering and production engineering. At the begining of the Petroleum industry the main type of rotary drilling, introduced by Anthony Lucas, was the Overbalanced Drilling. The Overbalanced Drilling method is a method in which the control of the reservoir pressure is accomplished by the hydrostatic pressure of the driling fluid and the Equivalent Circulating Density – EMW. As a procedure the conventional drilling hasn’t changed very much over the years, the process is still open to atmosphere. But what has changed are the drilling conditions. Nowdays we are drilling deeper wells, wells with complex wellpaths and trajectories, reservoirs have larger pressures, because of the production of oil and gas from reservoirs we have depleted zones etc.. All of this factors means that our wells are more expensive to drill than the wells in the past. Because of that we need to find some new solutions in order to make the well economically feasible. Methods like Underbalanced drilling and Performance drilling were introduced. Preformance driling is a drilling method in which a low Bottom Hole Pressure- BHP is applied in order to enhance the Rate of Penetration and bit life. Underbalanced drilling is a method in which BHP that is used is smaller than the reservoir pressure. That means that we are allowing a certain amount of influx into our well from the reservoir. Main objective of the Underbalanced drilling is to minimise the reservoir damage induced by the drilling fluid. Subsurface rocks, through which we are drilling, are defined by the drilling pressure window. Drilling pressure window describes the lower and upper pressure values of hydrostatic pressure for our drilling project. Lower pressure margin describes the formation or reservoir pressure and the upper margin describes the fracture pressure of the rock. Real problem originates when the pressure window becomes narrow. In those cases the use of above mentioned methods is not safe becaouse the use of these methods can potentially result in kick fluid losses or wellbore instability which can lead to down stuck or even loss of downhole equipment situation. Proper solutions for these subsurface environments is the use of the Managed Pressure Drilling – MPD.

 

 

 

 

 

2. MANAGED PRESSURE DRILLING AND IT’S VARIATIONS

We Will Write a Custom Essay Specifically
For You For Only $13.90/page!


order now

By IADC  definition the Managed Pressure drilling is an adaptive drilling process used to precisley control the annular pressure profile throughout the wellbore. The objecitves are to ascertain the downhole pressure limits and to manage the annular hydraulic pressure profile accordingly (Hannegan). Main difference between the MPD and the conventional Overbalanced drilling – OBD is the type of the circulation system. OBD circulation system, as mentioned before is a system opet to athmosphere. This kind of fluid circulation system can result in a significant wellbore stabillity issues because of the comomon changes in BHP. These fluctuations are caused by constant restrictions of circulations during drillstring connections, specifically they result from a change in ECD when the pumps are turned on and off. The MPD technology is applicable in to avoid these changes in ECD by applying a certain amount of backpressure, and with that technique is possible to maintain Constant Bottom Hole Pressure().     MPD has a closed pressurizable circulation system similar to the UBD circulation system, but MPD does not invite the influx of formation fluid during drilling like UBD . Instead, the abillity to apply varying degrees of backpressure with a closed and pressurizable mud returns system is key to enabling technology to contain and safely control any influx that may be incidental to the MPD operation. The diference between the UBD can also be in the type of drilling fluid. In UBD we can use compressible fluids like air or mist and foam where in the MPD drilling we are using incompressible drilling fluids. The usage of incompressible drilling fluids results results in almost instant change in BHP. To finally distinct between these two methods we can say that the UBD is a reservoir-issued method and the MPD is drilling-issued method. MPD includes faster corrective action to deal with obesrved pressure variations. The abillity to dynamically control annular pressures facilitates drilling of that might otherwise be ecconomically unattainable prospects. It can also include the control not only over back pressure but over the fluid density, rheology, annular fluid level, circulating friction, hole geometry or combination of these factors (). MPD process employes a collection of tools and techniques which may mitigate the risks and costs associated with drilling wells. The system is designed to complemen the existing well contorl equipment and an important feature is that there is no change in existing rig well control equipment. The operations can be switched between the MPD system application and conventionaldrilling at any time using simple procedures. It’s control equipment does not replace the rig well-control equipment as the secondary protection barrier. Additional equipment is added to enhance the corntol of the first barrier. The main components of the MPD systems are:

1.     Rotating Controling System – RCD, and

2.     MPD choke valve.

3.     Precise mass flow meter

4.     Surface gass separator (degasser) if needed downstream of the choke manifold.

Systems with theese equipment can vary from manual to fully automated systems.

                                    

                   Figure 1 – Basic MPD system components

The main function of the RCD is to divert the upstream flow from the wellbore to the choke manifold while maintaining an effective seal between the drillstring and well. The RCD also   provides the rotating seal between the atmosphere and annulus during the MPD operations. The technology is based on aplying an advanced compound sealing rubber against the drillstring or Kelly surface, which provides an effective seal while allowing vertical movement of the pipe. MPD choke manifold is a critical component of the MPD equipment. It creats the variable flow restriction that controls the wellhead pressure, which in turn maintains relatively constant BHP in both static and dynamic conditions. The choke in MPD conditions is used to controll well pressure. Unlike in conventional drilling methods, MPD chokes are not used as a secondary well-control equimpent. MPD is intended to avoid continous influx of formation fluids to the surface. Any influx incidental to the operation will be contained safely by use of an appropriate process. This means that a choke in MPD operations is used for pressure control and less for flow control. Choke manifold must have the same pressure rating as the preventer stack. The choke system is part of the drilling equimpent and should not be considered as a part of the well-control equipment, and the RCD is a diverter and not a blow-out preventer (BOP). Choke alone can be operated manually or automatically. In automatic MPD choke systems, after an influx is detected, no change in flow rate is required. The choke automatically  closes to increase the backpressure at the surface until the influx is controlled. After the influx is controlled, the annular surface pressure is controlled to circulate the influx out of the well ().

 

Regarding the MPD process we have two main categories:

1.     Reactive MPD, and

2.     Proactive MPD.

Reactive MPD is described as when attempting to drill with a conventional wisdom casing set points and fluids program, the drilling program is tooled up at least with a RCD, choke and perhaps drill strig float. This tool layout enables more efficient and safe way to deal with unexpected downhole pressure environmetlan limits, e.g. lower or higher pore pressure or fracture pressure than expected. In Proactive MPD the fluids and casing programs are designed from the beginning with a casing, fluids and open hole program that takes full advantage of the ability to more precisely manage the pressure profile throughout the wellbore. This walk the line category of MPD technology is expected to offer the greatest benefits to offshore drilling (Hannegan).

Except of these two main categories we have numerous variations, and these are:

1.     Constant Bottom Hole Pressure- CBHP,

2.     HSE MPD,

3.     Pressurized Mud Cap Drilling MPD,

4.     Deepwater Dual Gradient MPD,

5.     Riserlees MPD, and

6.     Zero Discharge Riserless MPD.

2.1. Constant Bottom Hole Pressure MPD

This variation is attractive to consider when offset wells have shown kick-loss scenarios and well control issues associated with drilling into relatively unknown or narrow downhole pressure environment limits. Typically, such tight drilling windows manifest themselves first by loss of returns immediately upon resuming circulation after jointed pipe connetion. If the well wasn’t kicking in a static condition during connection this indicates the ECD as a result of restarting the rigs mud pumps has exceeded the formation pressure somewhere in the open hole section. This event describes the loss portion of kick-loss scenario. If the mud density is reduced with the goal of not exceeding the fracture gradient while circulating then the well is placed in a condition where the risk of  an influx of reservoir fluids during static conditions is increased. This is the kick portion of kick-loss scenario. CBHP method determines the BHP as following:

               BHP= Hydrostatic mud weight + ECD + Backpressure

By utilizing this relationship between the rig pump rate versus an applied annular surface backpressure, via RCD and Choke system, a constant bottomhole pressure can be achieved and maintained while drilling, tripping or making connections

                         

Figure 2- Constant Bottom Hole Pressure  MPD bottom hole pressure during connections

This figure explaines that with the application of the surface backpressure it is possible to use a lighter fluid than in conventional fluids program without the risk of influx during static periods or when the wellbore is not subjected to annulus friction pressure.

2.2. Returns Flow Control-HSE MPD

The objective of HSE MPD is to drill with a closed annulus returns system versus an opet-to-the-atmosphere drilling. This variation is primarily used when drilling with potentially hazardous zones that raise health, safety and envirnomental concerns such as us of caustic drilling fluids and into formations expected to have high concentrations of toxic gases such as H2S an CO2. The increase of safety is aided by the wellbore being virtually a closed system. Therefore the changes in wellbore pressure are typically more easily observed, reducing the potential kick magnizude to be limited to more manageable levels reducing overall risk and allowing for drilling operations to continue.

2.3. Pressurized Mud Cap Drilling MPD

This method is beneficial in cases where offset wells have encountered gorssly depleted zones and where extreme mud loss has resulted from drilling into fractures or into formation containing large cavernous voids. PMCD include drilling with sacrifial fluid with noreturns to surface. This sacrificial fluid is usually any plentifull or inexpensive fluid such as seawater with appropriate inhibitors. A mud cap of a light and viscous fluid is pumped down the annulus with a dedicated mud pump and maintained by a RCD and a dedicated drilling choke. The column height and density of the mud cap is predetermined with the objective of keeping surface backpressure requirements to a minimum. The sacrificial fluid is less dense than the fluid from the offset wells and where massive losses and well control issues prevailed which made wells undrillable. When drilling and pumping the sacrificial fluid, the fluid is prevented from flowing up the wellbore by hydrostatic head and viscosity of the mud cap and augmented by surface backpressure implemented by the RCD and choke.

                            

                                 Figure 3 – Illustration of Pressuried Mud Cap Drilling

2.4. Deepwater Dual Gradient Drilling MPD

An inert gas or light liquid is injected at some predetermined depth into the marine riser, as a mean to adjust BHP prehaps a pound per gallon equivalent (ppge), or more without changing base mud weight. The intent is not to reduce the BHP to a point less than formation pore pressure. Instead, the intent is to avoid gross overbalance, not exceed the fracture gradient. Dual gradient MPD may be accomplished in marine environments via concentric casing, parasite string, or in the case of floating rigs with booster pumps, via the booster pump line. Result is one depth-pressure gradient below the injection point, and another above, thus dual gradient.

 

2.5. Riserless MPD

A subsea rotating device and remote operating vehicle (ROV) is used when establishing a subsea location via riserless drilling with seawater. The ROV adjust subsea backpressure at the mudline. Closing the subsea choke increases BHP, virtually as if the subsea location was being drilled with a marine riser filled with mud and cuttings. Result is a overbalance degree greater than the drilling fluid itself would impart, useful to control shallow geohazards such as shallow water flow hazards.

2.6. Zero Dischagre Riserless MPD

Or dual gradient riserless drilling. A subsea pump is used in conjuction with a subsea RCD. Because of that mud and cuttings are returned to the rig for proper disposal. BHP may be adjusted via backpressure, rig and subsea pumprates or a combination thereof.

 

 

 

 

 

 

 

  

 

 

 

3. Limits of conventional drilling and its problems

To appreciate the potential benefits of MPD, it is important to understand and accept the limitations of conventional drilling and its hydraulics. The Hydraulics of conventional drilling with weighted mud with an open-to-atmosphere mud returns system were first developed at Spindletop Field, Beaumont Texas in 1901 by Anthony Lucas. Basic hydraulics of conventional drilling are drilling with a heavy mud and not inviting the influx because of the overbalance between the pressures hasn’t changed over the years. The hydraulics of rotary drilling and a conventional fluids system requires that the annulus returns arriving under the rig floor to proceed without the interuptions. When not circulating, the effective wellbore pressure is the mud weight hydrostatic pressure. When we are circulating the resulting equivalent mud weight is the sum of hydrostatic pressure of the mud and the Annular Friction Pressure losses. A significant limitation of the conventional drilling is that the only way to change or adjust the equivalent mud weight without the interruption to the drilling program is by changing the speed of the rigs mud pumps. The chage in the fluid density, subjected to volume availability in rigs tanks is the other alternative. As mentioned before, the wells that are drilled today are not so easy to drill in compare to the wells drilled in the history. Nowdays we are drilling in the HPHT environmets that are unquestionably more chalenging to drill safely and efficiently due to the nature of their drilling hazards and elevated consequences if not mitigated at write time. Many of these environments are characterised with the narrow pressure drilling windows and because of that drilling programs like these can become ?over the budget? using the conventional drilling windows. This is were the Managed pressure driling comes to equation. The primary objective of MPD is to optimize drilling processes by decreasing non-productive time (NPT), mitigating drilling hazards and to enable the drillig of otherwise technicalliy or economically un-drillable high complexity prospects.  Becaouse the MPD adrsses the NPT, the technology is of  greatest potential benefit to offfshore drilling programs where cost of dealing with drilling trouble zones is much higher than onshore. Although MPD has been safely and efficiently practiced with drilling from all types of onshore rigs and producing the desired results in the process, it is still considered a relatively ?new? drilling technology. Impressive uptake in offshore MPD applications is due in part to a requirement to drill in greater depths, through depleted zones or reservoirs and into narrow or relatively unknown equivalent mud weight drilling windows. The majority of the MPD systems uses a proprietary control algorithm to detect kicks or losses on a real time basis, and uses the surface choke to apply a certain amount of Surface Back Pressure ( SBP) to maintain the well under control, and allows quick and reliable drilling decisions to be made on actual pressure and flow data. The application of the Managed Pressure Drilling technology will optimize the drilling process by decreasing Non Productive Time and mitigating drilling hazard associated with conventional drilling techniques. Most importantly, the MPD system reduces drilling costs and limits drilling cost uncertainty by:

1.     Avoiding conventional drilling NPT problems such as lost circulation, shale instability, kicks, nuisance gas zones and diffrential sticking

2.     Increasing the ROP, increasing bit life and decreasing tripping frequency

3.     Enabling acces to potential assets/reservoirs previously belived to be un-drillable. Improving helath, safety and environmental conditions.

Drilling related issues such as excessive mud costs, slow rate of penetration, well bore ballooning/breathing, kick detection limitations, difficulty in avoiding fross overbalance conditions, differetially stuck pipe, twist offs and resluting well-control issues contribute to defining the offshore industry’s need for MPD technology. Most drilling hazards have one thing in common: they all may be adressed to some degree or other by drilling with more precise wellbore pressure management. It is where an automatic MPD system based on flow balance monitoring will add value to  the conventional drilling practice. To date there have been no ?train wrecks? or otherwise reportable well control incidents on offshore MPD projects where the root cause has been atributed to the technology itself or failure of its key enabling equipment. Main problems that are going to be adressed in this work related to the convetional drilling are:

1.     Well control,

2.     Equivalent Circulating Density

3.     Cost related problems

4.     Narrow pressure Windows

5.     Temperature efect on conventional drilling

6.     Drilling cost uncertinty.

3.1. Weighted mud non-productive time

Applying the conventional drilling wisdom, the possible ways to react to the unpredicted subsurface environments is either increasing the rig pumps rate or to change the fluid density. Second action is undesirable because it is a time consuming action. This event is the cause of the many NPT events and this commonly accepted practice it indirectly causes NPT and drilling costs through the:

1.     Reduction in drilling rate of penetration because of the increase of the overbalanceand mud solids content

2.     Increased driling costs ( mud cost and rig cost)

3.     Increased casing seats and strings

Rate of penetration is directly proportional to the mud weight, which is defined by the amount of sollids in the mud and the overpressure. In both cases the higher the solids content or overpressure, the smaller the ROP is. The dominant factor responsible for the reduction of the ROP is called ?chip hold down effect?. This refers to the capacity of the pressure differential between the mud and pore pressures to inhibit the process of crack growth from the crush zone out to the free surface and the subsequent lifting off of the new chip from the bottom of the hole. Clearly the oppening of this crack and the lifting of the chip against the bottom-hole pressure will be hindered if fluid cannot flow into the growing crack to relive the partial vacuum generated as the crack opens. This process will take time and will depend upon how easily fluid can flow into the growing crack. Also, the increase the mud weight we need to add a certain amount of solids to achieve wanted mud density. This increases the cost of the fluid itself. These solids, barite for example, are inert which means the don’t ineract with the mud. With this in mind  we need to also address the possible and very significant equipment wear where the bit, mud motors, pipe washouts and pump failures can occur. In the case of the narrow pressure windows the increase of the mud wieght means that probably we are going to exceed the fracture pressure of the rocks. The result is that we need the addtional casing string to overcome this problem. Increased number of casing seats means the increase of the total cost of well and also increase of the NPT. Also excessive number of casing strings can result with a well whose diameter at Total Depth- TD may be too small to accomodate production tubing large enough to produce economic volumes of hydrocarbons.

3.2. Well control

Regarding the well control situations the samo wisdom of increasing or decreasingthe mud weight is used if we encounter the over pressured or sub pressured zones. These actions can cause different problems and one of the is so called kick/loss situations of the mud weight system. By encountering the overpressure zone the spontaneus response in the overbalanced drilling is the increase of the mud weight. This actions cause so called balooning effect. Conventional weighting-up practices often compound a kick , consequently causing a wven larger kick. The reason is that with the increase of the mud weight we can exceed the fracture pressure of the rock or achieve a very large overpressure conditions, resulting in a loss of fluid situations. Because of this losses the fluid column level decreases and consequently the hydrostatic pressure of the fluid, causing even larger kick then the firs one. The higher the mud weight the stronger and faster a kick can become. It was observed that one the kick was encountered, it was very difficult to kill. The areas of the largest significance are so called High Pressure Low Volume nuissance areas. 

Related Posts

© All Right Reserved
x

Hi!
I'm Melba!

Would you like to get a custom essay? How about receiving a customized one?

Check it out