wiper trip oil drilling

What is wiper trip ??

By mustafa naqvi posted 02-14-2014 09:38 am.

Mustafa Naqvi 02-15-2014 12:08 PM

Delaynne Grillo 02-14-2014 07:12 PM

Brandon Broom 02-14-2014 03:46 PM

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Introduction

Experimental setup, results and discussion, conclusions, acknowledgments, si metric conversion factors, coiled-tubing wiper trip hole cleaning in highly deviated wellbores.

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Walker, S., and J. Li. "Coiled-Tubing Wiper Trip Hole Cleaning in Highly Deviated Wellbores." Paper presented at the SPE/ICoTA Coiled Tubing Roundtable, Houston, Texas, March 2001. doi: https://doi.org/10.2118/68435-MS

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Compared with stationary circulation hole cleaning, the use of the wiper trip produces a more efficient clean out.

For a given operational condition, there is an optimum wiper trip speed at which the solids can be completely removed.

Nozzles with a correctly selected jet arrangement yield a higher optimum wiper trip speed and provide a more efficient clean out.

The hole cleaning efficiency is dependent on the deviation angle, fluid type, particle size, and nozzle type.

Correlation's have been developed that predict the optimum wiper trip speed and the quantity of solids removed from and remaining in the wellbore for given operating conditions. The wiper trip provides an advantage for hole cleaning and can be modeled to provide efficient operations.

Solids transport and wellbore cleanouts can be very effective using Coiled Tubing techniques, if one has the knowledge and understanding of how the various parameters interact with one another. Poor transport can have a negative effect on the wellbore whether it is for coiled tubing drilling or cleanouts, which may cause sand bridging and as a result getting the coiled tubing stuck. Coiled Tubing can be a very cost-effective technology when the overall process is well designed and executed. The highly deviated/horizontal well has placed a premium on having a reliable body of knowledge about solids transport in single and multi-phase conditions.

In our previous studies 1 – 2   , a comprehensive experimental test of solids’ transport for the stationary circulation was conducted, which included the effect of liquid/gas volume flow rate ratio, ROP, deviation angle, circulation fluid properties, particle size, fluid rheology, and pipe eccentricity on solids transport. Based on the test results the data was analyzed, correlation's were developed, and a computer program was developed.

In this study, the wiper trip hole cleaning effectiveness was investigated with various solids transport parameters such as, deviation angle, fluid type, particle size, and nozzle type. Based on these test results, an existing computer program was modified and adjusted to include these additional parameters and their effect on wiper trip hole cleaning.

The flow loop shown in Figure 1 was used for this project. It was developed in a previous study 1 – 2   . The flow loop has been designed to simulate a wellbore in full scale. This flow loop consists of a 20ft long transparent lexan pipe with a 5-inch inner diameter to simulate the open hole and a 1-1/2" inch steel inner pipe to simulate coiled tubing. The flowloop was modified and hydraulic rams were installed to enable movement of the tubing (see figure 2 ). The inner pipe can be positioned and moved in and out of the lexan to simulate a wiper trip. The loop is mounted on a rigid guide rail and can be inclined at any angle in the range of 0°–90° from vertical.

Schematic of cuttings transport flow loop

Photo of solids transport flow loop with wiper trip extension for a 5" wellbore and 1-1/2" coiled tubing

When the coiled tubing is in the test section, circulating the sand into the test section and build an initial sand bed with an uniform height cross the whole test section. Then pull the coil out of the test section with a preset speed.

The recorded parameters include flow rates, initial sand bed height before the coiled tubing is pulled out of the hole (POOTH), and final sand bed height after the coil tubing is POOTH, fluid temperature, pressure drop cross the test section and wiper trip speed. The data collected from the instrumentation is recorded using a computer controlled data acquisition program, see reference 1 for more information.

In this study, over 600 tests have been conducted using three different particle sizes 2   , over a range of liquid and gas rates at angles of 65° and 90° from vertical. The way in which the wiper trip affects the various solids transport parameters was investigated. The results and discussion in this paper focus on the situation that involves wiper trip hole cleaning in which the tubing is pulled out of the hole, while circulating water, gel, and multiphase gas combinations.

‘Wiper trip’ is defined in this paper, as the movement of the end of the coiled tubing in and out of the hole, a certain distance. For various reasons the study focused on the wiper trip situation of pulling the coiled tubing out of the hole. The critical velocity correlation developed in a previous study 1   can be used to predict the solids transport for the coiled tubing run-in-hole (RIH).

The wiper trip is an end effect. When the circulation fluids are pumped down through the coil and out of the end, and returned to surface through the annulus, the flow changes direction around the end of the coil and the jet action only fluidizes the solids near the end of the coil. When the flow conditions are less than the critical condition solids will fall out of suspension for a highly deviated wellbore. Then the sands transport with the sliding and dragging mode.

Based on the experimental observation in this study, for a given set of conditions, there is an optimum wiper trip speed at or below which sands can be removed completely when the coil is pulled out of the hole. When the coil tubing is POOTH at a wiper trip speed higher than the optimum wiper trip speed, there is some sand left behind. In general, more sand is left in the hole as the wiper trip speed is increased. The hole cleaning efficiency is defined as the percentage of sand volume removed from the hole after the wiper trip versus the initial sand volume before the wiper trip. 100% hole cleaning efficiency means that the hole was completely cleaned. In general a higher pump rate results in a higher optimum wiper trip speed. The vertical axis of figure 3 is equal to 100% minus the hole cleaning efficiency. For a given type of nozzle and deviation angle, there is a minimum flowrate at which the hole cleaning efficiency is near to zero. For low pump rate, the remaining sand volume in the hole increases non-linearly with the dimensionless wiper trip speed. However, with high flowrate, the remaining sand volume in the hole increases linearly with the dimensionless wiper trip speed. Figure 3 displays these three parameters that can be correlated and used to select adequate flowrates and wiper trip speed to ensure an effective cleanout operation. If the pump rate is too low or the coiled tubing is pulled out of the hole too fast solids will be left behind.

Hole cleaning efficiency for water at 90° with Nozzle B

There are other variables, which can affect the hole cleaning effectiveness during wiper trip cleanouts. The effect of the following variables are investigated in this study:

Nozzle type

Particle size

Deviation angle

Multi-phase flow effect

Effect of nozzle type.

In this study three different nozzle types were investigated. For simplicity the nozzles can be referred to as Nozzle A, B, and C. Each of these three nozzles had different jet configurations and size. The effective wiper trip hole cleaning time was investigated for each nozzle type and the optimum wiper trip speed for a wide range of flow rates was determined. Previous ‘rules of thumb’ assumed that the cleanup of a wellbore takes approximately two hole volumes for a vertical wellbore. From these experimental studies, it has been observed that these ‘rules of thumb’ are inadequate.

Figure 4 displays the number of hole-volumes required to clean the hole using water in a horizontal section of a well for the three different nozzle types. There is a non-linear relationship between the number of hole volumes and the in-situ liquid velocity. For a given type of nozzle, the number of hole-volume needed is constant when the in-situ liquid velocity is high enough. However with a low in-situ liquid velocity, the number of hole-volume increases dramatically with the decreasing of the pump rate. An important thing to note is that, in certain ranges, the hole will not be sufficiently cleaned out if the minimum in-situ velocity is not attained and this value will vary depending on the type of nozzle. It is essential to select the proper nozzle configuration and wiper trip speed to ensure an effective cleanout. The solids transport parameters that are interacting with one another (shown in figures 3 and 4 ) can be correlated using a dimensionless wiper trip speed parameter. From this information the proper nozzle, flowrates, and wiper trip speed can be selected to provide an effective cleanout.

Effective hole cleaning volume with different nozzle types for water at 90°

Effect of particle size

The previous study results 2   indicate that there is a particle size that poses the most difficulty to clean out with water for the stationary circulation mode and from the study it is of the order of 0.76mm diameter frac sand. In contrast to stationary circulation hole cleaning, the wiper trip hole cleaning situation reveals different conclusions based on particle size. In this study three types of particles ranging in size were investigated: 1) Wellbore fines, 2)frac sand, 3) drilled cuttings. Figure 5 displays the results of the investigation of particle size that included a wide range and the results suggest that for the horizontal wellbore with a high pump rate, larger particles have a higher hole cleaning efficiency than smaller particles do. But for low pump rate, it was just opposite.

Effect of particle size on the hole cleaning efficiency with water at 90°

The effect of particle size on solids transport is different between stationary circulation and wiper trip hole cleaning. Due to the complexity of the interaction between the various solids transport parameters it is a challenge to generalize and draw conclusions. For more information on particle size effects please refer to reference 2.

Effect of fluid type

Wiper trip hole cleaning adds a new dimension with respect to fluid type. In contrast to stationary circulation hole cleaning where gel could not pick up the solids and only flowed over top of the solids bed 2   , for the highly deviated wellbore the wiper trip hole cleaning method transports the solids effectively. Due to the turbulence created at the end of the coiled tubing from the fluid, gels have the ability to pick up and entrain solids and transport them along the wellbore. For small particles like wellbore fines the use of gel for long horizontal sections is beneficial. The larger particles such as frac sand or drilled cuttings, tend to fall out at a more rapid pace.

The effect of fluid type on the hole cleaning efficiency is shown in figure 6 . There is no significant different between Xanvis and HEC for all tested flowrates. There is no difference between water and gel except for very low pump rates i.e. at very low shear rates, when gels outperform water/brines. Therefore, in the case where the liquid in-situ velocity is low, pumping gel would clean the hole better.

Effect of fluid type on the hole cleaning efficiency at 65°

Effect of deviation angle

The experimental results in the previous study 1   shows that the highest minimum in-situ liquid velocity is needed around 60°. The effect of deviation angle on the hole cleaning efficiency with the wiper trip mode is shown in figure 7 . The general trend at higher flowrates typical for 1-1/2" coiled tubing is that there is not a significant difference in solids transport effectiveness between horizontal and 65 degrees. There are distinct differences for fluid types as well, for example with water, solids transport proves more difficult at 65 degrees than at horizontal, but, with Xanvis gel, 65 degrees is easier, than horizontal.

Effect of deviation angle on the hole cleaning efficiency with water

Multi-phase flow is very complex and if used incorrectly can be a disadvantage and provide poor hole cleaning, whereas if the addition of the gas phase is understood, there are advantages that prove beneficial for solids transport. Figure 8 and 9 display the multi-phase flow effect for various gas volume fractions. The addition of the gas phase up to a gas volume fraction (GVF) of 50% in stationary circulation, hole cleaning can be improved by up to 50%. Whereas with wiper trip hole cleaning, the addition of the gas phase up to GVF 50%, only produces an improved cleanout effectiveness of 10–20%. For example, if the well was 80% cleaned out with water in the wiper trip hole cleaning mode, with the addition of the gas phase, the solids transport effectiveness could be increased to 85%. Even though with stationary circulation hole cleaning there is a substantial increase in hole cleaning effectiveness with the addition of the gas phase, the use of the wiper trip method is more effective, than just the addition of the gas phase. The addition of the gas phase is beneficial in low pressure reservoirs and where there are limitations due to hydrostatic conditions.

Effect of the addition of the gas phase on the hole cleaning efficiency for water at 90°

Effect of gas volume fraction on the optimum wiper trip speed for water/gas at 90°

As shown in figure 8 , there is not a significant effect on solids transport effectiveness with the addition of the gas phase at high relative in-situ liquid velocities. As the relative in-situ liquid velocity is decreased to a low value, solids transport effectiveness is dependent on the addition of the gas phase. As the gas phase is added the solids transport effectiveness decreases, until more gas is added and the relative in-situ velocity starts to increase, which causes an improvement in solids transport effectiveness.

Figure 9 displays the effect of adding gas to the system resulting in a decrease in optimum wiper trip speed. The three curves represent situations that involve the addition of gas and the reduction of the liquid flow rate, keeping the total combined flow rate constant. There is a greater dependency on the addition of gas at the higher total flowrates on the optimum wiper trip speed compared to the lower flowrates. As more gas is added with a constant total combined flow rate the optimum wiper trip speed decreases, but the solids transport effectiveness generally improves when gas is added to the system with a fixed liquid flow rate as shown in figure 8 . The complexity of the multi-phase flow behavior makes more difficult to generalize the test results. More data is required to develop a reliable correlation to predict the effect of the gas phase on the optimum wiper trip speed and the hole cleaning efficiency.

Based on the experimental study and the analysis of the hole cleaning process, the following conclusions can be made:

Compared with stationary circulation hole cleaning, the use of the wiper trip produces a more effective clean out.

For a given set of well conditions, there is an optimum wiper trip speed at which the solids can be completely removed. The optimum wiper trip speed is dependent on the deviation angle, fluid type, particle size, and nozzle type. Nozzles with correctly selected jet arrangements yield an effective cleanout operation.

The investigation of particle size included a wide range and the results suggest that when the borehole is at various inclined angles for particles from 0.15 mm up to 7mm in diameter, there is a significant effect on solids transport. Spherical particles such as frac sand, are the easiest to clean out and wellbore fines prove more difficult, but the larger particles such as drilled cuttings pose the greatest difficulty for solids transport.

Fluid rheology plays an important role for solids transport, and to achieve optimum results for hole cleaning, the best way to pick up solids is with a low viscosity fluid in turbulent flow but to maximize the carrying capacity a gel or a multiphase system should be used to transport the solids out of the wellbore.

The large number of independent variables influencing solids transport demands that a computer model be used to make predictions effectively.

This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

The authors would like to express their appreciation to BJ Services Company for the opportunity to present this paper.

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• Calculation of Maximum Allowable Annular Surface Pressure (MAASP)
• Casing Make-Up Torque
• Waste Management Strategy - cuttings discharge
• Inflow Testing Procedure
• HSE Plan (Example)
• Single-shot inclination-only survey tools (TOTCO)
• Well Control Drills and Exercises
• Classification of BOP and well control equipment.
• Oil Companies
• Drilling program example (Semi-Sub)
• 12.25" guidelines for tripping, making connections and back reaming
• Completion Operation - Best Practices
• Drilling programme 12.25" section HPHT
• Cold Weather Operations Checklist
• Coring Checklist
• Weatherford Overdrive casing running and pick up/lay down machine - Checklist
• 16" Potential Problems - Best Practices
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12.25" guidelines for tripping, making connections and back reaming

Making connection.

• Wipe the full stand once by pumping out and reaming back down
• Wipe the bottom single once by pumping out and reaming back down
• The driller must nominate a responsible person to control the mud pumps (e.g DD, Toolpusher, AD). This person will be responsible for shutting down the pumps quickly in the event of a pack-off.
• The Drilling Supervisor will be on the rig floor from start of the trip out of hole until the string is in cased hole.
• Record up-weight, down-weight, rotating weight and off bottom torque.
• Have a single of drill pipe available in the V door.
• List of tight spots/intervals encountered during connections and previous trips
• BHA schematic with measurements between stabilizers and bit
• Go down and re-establish up-weight, down-weight, rotating weight and off bottom torque.
• Apply overpull - starting with 20klbs - mark the pipe - go down - check the down drag - if negligible increase in down-drag then proceed by trying greater overpull.
• Apply 30klbs overpull - mark the pipe - go down - check the down drag - if negligible increase in down-drag then proceed by trying greater overpull.
• Apply 40klbs overpull - mark the pipe - go down - check the down drag - if negligible increase in down-drag then proceed by trying greater overpull.
• Continue applying the above technique using 10klb increments up to a maximum of the weight of the BHA.
• If on any overpull attempt, the down drag indicates that the pipe is becoming jammed, then make several attempts with less overpull.
• If after several attempts there is no further progress (as seen from marks on the pipe) then go down, circulate clean - then try again.
• If still no success to pass, then go down again and commence back-reaming procedures. Do not attempt to pump out of the hole as this may cause hydraulic compaction whereas rotation may disperse the blockage.
• Do not make wiper trips unless hole conditions - such as unmanageable increase in torque or drag - dictate.
• If during a trip, the crew have to change tour, ensure that the Tool Pusher on tour is at the brakes until a full handover is done between the drillers.

Back-reaming

• Back-reaming should be used as the last resort and with the same flow rate that was used during drilling.
• Back-ream for 5m maximum, circulate cuttings clear of the BHA, then try to pull through the obstruction again using the above procedure - without pumps or rotation.
• During back-reaming the driller must nominate a responsible person to control the mud pumps (e.g DD, Toolpusher, KPO Drilling Supervisor). This person will be responsible for shutting down the pumps quickly in the event of a pack-off.
• In the event of a pack-off:- stop the pumps - go down with the pipe (maintaining rotation) - re-establish circulation - circulate clean.
• Attempt to pull through obstruction again without pumps or rotation.
• Repeat the above process - with patience. The objective is to POOH with the absolute minimum of back-reaming.

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Wiper Trips Effect on Wellbore Instability Using Net Rising Velocity Methods

Background:.

This paper discusses the wiper trip effects on well instability in shale formations.

Objectives:

Problematic shale interval sections have been studied for the time spent on the wiper trip operations. Lifting efficiency and well wall instability change with the time analyzed. Detailed drilling operation, formation heterogeneity, rheological and filtration characteristics of polymer water-based mud are discussed. Physical and chemical properties of the drilled formation and drilling fluid are also studied.

Materials and Methods:

Wiper trips are analyzed using a typical drawing program to find the relations between the most controllable parameters. For that, two calculation models have been implemented to find the net rising cutting particles velocity in the annular. The relation between the net rising velocity and wiper trips is analyzed. Laboratory works have been done to support the findings of field work.

Strong relations have been found between the wiper trip impacts and lithology types of the penetrated shale.

Conclusion:

A modified drilling program is proposed in relation to changes in casing setting depth and drilling fluid properties that make the operations more efficient in cost and time.

Article Information

Identifiers and Pagination:

Article history:, 1. introduction.

In general, wiper trips can be short or long for cleaning purpose or for making the wall more smooth and stable. A short trip is an action or some operation for tripping out / or in the drill string to a certain planned depth inside the open hole section. Performing a short trip helps to remove the cutting bed and to improve the smoothness of the wall. Sometimes a short trip can be done when there is a long sliding section via a mud motor. It is beneficial to do so because sliding with the mud motor creates a lot of cutting beds that are not effectively removed.

A long wiper trip is a similar action as a short trip, but the trip is longer. Typically, the drill string is pulled out from the open section and then is tripped back in the hole to the previous depth. This type of wiper trip can remove a lot of cutting beds. However, these trips take additional rig time. Not only time is spent, but also there is the risk of creating other problems as wellbore instability, formation damage, etc. Hole condition, torque, drag and field experience will dictate whether you need to do either a short trip or long wiper trip.

Drilling fluid is one of the most important elements of any drilling operation for hydrocarbon exploration [ 1 H. Rabia, Well Engineering & Construction , Entrac Consulting Limited, . ]. Penetrating different types of formations need very close attention to the design of the drilling fluid for minimizing drilling problems and cost. Drilling fluid is the only system in the well construction that keeps us in continuous contact with the wellbore. The extent to which drilling mud properties must be controlled varies with the geologic condition [ 2 C. Gatlin, Drilling and Well Compitions , Department of Petroleum Engineering, University of Texas: Texas, USA, . ]. A properly designed drilling fluid performs several essential functions during its circulation from the surface to the bottom of the well and up again to the surface [ 3 M. Khodja, J.P. Canselier, F. Bergaya, K. Fourar, M. Khodja, N. Cohaut, and A. Benmounah, "Shale problems and water-based drilling fluid optimisation in the hassi messaoud algerian oil field", Appl. Clay Sci. , vol. 49, no. 4, pp. 383-393. [ http://dx.doi.org/10.1016/j.clay.2010.06.008 ] ]. The most important functions are to clean the well from the drilled cuttings and maintain wellbore stability. Wellbore instability may be due to chemical reactions of the drilling fluid with the drilled formations or due to mechanical issues. Many studies have been done on both the chemical and mechanical factors separately and in combination . Chenevert has studied mechanical properties of shale after hydration since the 1960s [ 4 M. Chenevert, "Shale control with balanced-activity oil-continuous muds", J. Pet. Technol. , vol. 22, no. 10, pp. 1-309-1-316. [ http://dx.doi.org/10.2118/2559-PA ] ]. There are also many studies combining both of these factors [ 4 M. Chenevert, "Shale control with balanced-activity oil-continuous muds", J. Pet. Technol. , vol. 22, no. 10, pp. 1-309-1-316. [ http://dx.doi.org/10.2118/2559-PA ] - 6 A. Hale, and F. Mody, "Borehole-stability model to couple the mechanics and chemistry of drilling-fluid/shale interactions", J. Pet. Technol. , vol. 45, no. 11, pp. 1093-1101. [ http://dx.doi.org/10.2118/25728-PA ] ].

Through controlling the wall stability, many operational problems toward more optimized drilling can be eliminated. In general, the primary objective of any cost control program is to maintain a low daily estimate of total expenditures for the entire drilling operation [ 7 L. Preston, DRILLING PACTICES MANUAL , 2 nd ed.Penn Well Publishing Company: Tusla, Oklahoma 74101, . ]. Cost of the drilling fluid ranges between10% to 20% of the total cost of a well drilling operation. For that, drilling fluid performance can affect overall well construction costs in several ways through the wellbore instability which is the largest source of well problems [ 3 M. Khodja, J.P. Canselier, F. Bergaya, K. Fourar, M. Khodja, N. Cohaut, and A. Benmounah, "Shale problems and water-based drilling fluid optimisation in the hassi messaoud algerian oil field", Appl. Clay Sci. , vol. 49, no. 4, pp. 383-393. [ http://dx.doi.org/10.1016/j.clay.2010.06.008 ] ].

At the beginning of the 1950s, many soil mechanic experts were interested in the shale swelling, which are important for maintaining wellbore stability during drilling, especially in water-sensitive formations. It is reported that shale accounts 75% of all formations drilled by the oil and gas industry, and 90% of wellbore stability problems occur in shale formations [ 5 G. Chen, M.E. Chenevert, M.M. Sharma, and M. Yu, "A study of wellbore stability in shales including poroelastic, chemical, and thermal effects", J. Petrol. Sci. Eng. , vol. 38, no. 3, pp. 167-176. [ http://dx.doi.org/10.1016/S0920-4105(03)00030-5 ] , 6 A. Hale, and F. Mody, "Borehole-stability model to couple the mechanics and chemistry of drilling-fluid/shale interactions", J. Pet. Technol. , vol. 45, no. 11, pp. 1093-1101. [ http://dx.doi.org/10.2118/25728-PA ] ], [ 8 L.C. Coelho, A.C. Soares, N.F.F. Ebecken, J.L.D. Alves, and L. Landau, "The impact of constitutive modeling of porous rocks on 2-D wellbore stability analysis", J. Petrol. Sci. Eng. , vol. 46, no. 1, pp. 81-100. [ http://dx.doi.org/10.1016/j.petrol.2004.08.004 ] , 9 H. Darley, "A laboratory investigation of borehole stability", J. Pet. Technol. , vol. 21, no. 07, pp. 883-892. [ http://dx.doi.org/10.2118/2400-PA ] ]. The first and most element in controlling wellbore instability is the drilling fluid passing through the (i) transport drill, cutting of the hole and separation of cuttings from the drilling fluids on the surface, (ii) formation a thin filter cake on the walls of the wellbore and preventing the inflow of drilling fluids into the formations and (iii) inhibiting the inflow of formation fluids into the wellbore [ 10 E. Dingsøyr, E. Pedersen, and K. Taugbøl, Oil based drilling fluids with tailor-made rheological properties: Results from a multivariate analysis. , vol. 12, Annual Transactions of the Nordic Rheology Society, . ]. Due to the swelling problems, a bridge, pack-off and tight spots will accrue. Several works focused on the selection of drilling fluid for a specific clay formation [ 11 H. Darley, "A laboratory investigation of borehole stability", J. Pet. Technol. , vol. 21, no. 07, pp. 883-892. [ http://dx.doi.org/10.2118/2400-PA ] - 13 V.F. Pernot, Troublesome shale control using inhibitive water-base muds , . ]. More recent studies on shale - fluid interactions suggest a new approach to Water-Based Muds (WBM) designs [ 14 R.F. Lomba, M. Chenevert, and M.M. Sharma, "The role of osmotic effects in fluid flow through shales", J. Petrol. Sci. Eng. , vol. 25, no. 1, pp. 25-35. [ http://dx.doi.org/10.1016/S0920-4105(99)00029-7 ] , 15 E. Van Oort, "On the physical and chemical stability of shales", J. Petrol. Sci. Eng. , vol. 38, no. 3, pp. 213-235. [ http://dx.doi.org/10.1016/S0920-4105(03)00034-2 ] ]. Consideration is given to maintain borehole stabilization in reactive shale by reducing hydration (swelling) and/or clay dispersion. Most of the laboratory works were also done on analyzing the effect of additives on different types of drilling muds. Besides all the advances and developments in the rheological properties, still, there are some operational works like wiper trips that need more consideration and later analysis. In general, the purpose of wiper trips and reaming is to give smoother and clean well before casing running. Wiper trips and reaming can be combined with the use of the most suitable drilling mud [ 16 P.M. Bommer, A Primer of Oilwell Drilling. , University of Texas at Austin, . ]. Wiper trips can also increase the reactivity of shale formations by disturbing filter cake situation in the previously drilled intervals.

In Kurdistan, most of the well instabilities accrue in shale formations. Formations of Kolosh, Aliji and Tanjiro are the most problematic formations in drilled wells. Problems of clay dispersion or shale swelling that lead to well collapse, tight spots and pack-off are dominant problems of chemical reactions of drilling fluid with penetrated formations. Well instability for the other formations beneath theses like Shiranish, Kometan and Qamchuqa is due to mechanical instability. Wiper trips can give positive results in some formations which mostly contain limestone and negative results in other shale formations.

Daily drilling operations and most wiper trips in clay formations for more than 26 wells drilled in Taq Taq oil field, Bazian block and Meran block in Kurdistan, north of Iraq have been collected. Shale formations were the main sources of well drilling operation problems. Section 12 ¼´´ of well Bazian no. 1 (Bn-1) was selected as a key interval to be monitored closely for this study. The operation reports of drilling, mud circulating system, fluid additives, casing and cementing operations data were all collected for the 12 ¼´´ section. Following of all the wellbore problems and recording drilling parameters during wiper trips, monitoring the effect of drilling fluids additives effects on the rheological properties and its relation to wellbore stability was conducted . Data obtained from drilling and geological daily reports were analyzed to find out the effect and role of the changes in mud rheological properties. Two different calculation methods have been implemented for calculating the net rising velocity of the drilled cutting. Analyses of the cutting and coring samples were performed in Koya University laboratory for the rheological effect in the drilled section.

2. KEY WELL BN-1 LOCATION

3. METHODOLOGY

3.1. stratigraphy.

Table 1 shows the top formations from the surface to the final True Vertical Depth (TVD) down to the Shiranish formation at 1800 m. The green highlighted formations in Paleocene and Cretaceous are representing the 12 ¼´´ section. These formations contain a high percentage of clay and marl. The detailed lithological description was based on collecting cutting samples after every 5 m of drilling continuously from the Mud Logging Unit (MLU). The primary reservoir targets were Shiranish, Kometan and Qamchuqa limestones of Cretaceous age. The secondary target was in the lower Jurassic and Upper Triassic.

3.2. Sub-Surface Information

The most important petroleum systems in Iraq are the Jurassic, Cretaceous, and Tertiary Petroleum Systems. Bn-1 was the first exploration oil well in Bazian block penetrated the Tertiary System to TVD of 3833m, so there was a very little information on the pore and fracture pressure gradients. Due to the shortage in prognosis information, a conservative drilling fluid program was designed based on little information gathered from offset data, especially wells drilled in west and east oil fields in Taq Taq and Miran, respectively. There were some indications that the Kolosh and Aliji formations are tectonically stressed as in the nearby Kewa Charmala no. 1 (KC-1) oil well 7 km west of Bn-1 and there was a potential that this is the case in Bn-1 also due to similarities in folding and faulting.

The Jurassic and Triassic formations may be slightly over-pressured. Limited well information was available due to the lack of oil wells penetrated to this depth in all Middle East. Heavy mud losses were expected which will affect Logging While Drilling (LWD) data transmission. The main properties of the prepared WBM-Polymer before drilling were 11 ppg, Yield Point Yp of 20-25 lb/100 ft and pH of 9.5-10.

Geologically, the low and high folded zones are characterized by harmonic folds. Cretaceous or older rocks are exposed in their cores; Paleogene and Neogene rocks form the adjacent synclines. The amplitude of the folds increases towards the NE until the anticlines override each other due to thrusting with the elimination of the intervening synclines. In the north of Iraq along the Turkish border, Paleozoic to Cretaceous rocks are exposed in the cores of tight anticlines bounded by thrust faults [ 18 S.Z. Jassim, and J.C. Goff, Geology of Iraq, DOLIN, sro, distributed by Geological Society of London , . ].

3.3. Reservoirs

The Tertiary oil is migrated from deeper reservoirs. The folds in high and low folds Zones grow mainly during the Pliocene. Two types of oil are contained within the Tertiary reservoirs, these are high API gravity oils in NE Iraq and low API gravity oils in the Mosul High of N Iraq. Since the Tertiary and Late Cretaceous sources in NE Iraq are immature to early mature, the light oil (37 API) in Kirkuk field must have migrated from deeper source rocks through fractures [ 18 S.Z. Jassim, and J.C. Goff, Geology of Iraq, DOLIN, sro, distributed by Geological Society of London , . ].

3.4. Interval Summary

The 8 ½´´pilot, Bottom Hole Assembly (BHA) was used to drill from the setting depth of 13 3/8´´ casing shoe at 1109 m down to 1843 m as a final True Vertical Depth (TVD) to penetrate Aliji, Tanjero and Shiranish formations, respectively. Losses while drilling were expected. In total thirty-meter, cores were planned to be taken periodically when instructed by the subsurface team.

Measuring and Logging While Drilling (MWD and LWD) were used to locate horizons with hydrocarbon content and to identify areas most suitable for coring. Incidences of stuck pipe and differential sticking in the offset wells were recorded in the formations of Kolosh, Aliji, and also Shiranish. All the 8 ½´´drilling BHA contain a straight mud motor to convert the drilling mode, in case the well de via tes from the vertical and/or parameters shall be adjusted to correct the path. If the de via tion cannot be corrected with the current BHA, it shall be replaced with a directional BHA. Black oil of around 45°API gravity with some associated gas was expected to be found in this section.

3.5. Section Operation Data

Running in Hole (RIH) 8 ½´´BHA started on November 11, 2009, after the drilled intermediate section as in Table 2, to drill down to 1436 m in the two days, with 525 gpm, 45 rpm, Weight On Bit (WOB) 2-4 tons, torque 3-4 kft.lbf, Stand Pipe Pressure (SPP) 1950 psi and 11 ppg with some minor problems on the surface, all are fixed on time (Table 2 ).

On November 13, 2009, the drilling reached the depth of 1658 m with the indications of some hole problems like tight spots, so the back reaming to 1212 m has been processed. After these tight spot indications, the decision was to start with wiper trips up and down at every drill stand once prior to each connection. At the depth 1780 m there was a deviation from the vertical drilling start to appear in azimuth 248º with 0.76º dog leg severity. To solve that, the drilling mode changed to slide drilling instead of conventional for the intervals of 1844.3 m to 1847.3 m, 1869 m to 1872 m and 1895.6 m to 1898.6 m. On November 14, 2009, the drilling reached to 1920 m, with 480 gpm, 11 ppg, 45 rpm and SPP 2300 psi. The drilling continued for the next day to its Total Depth (TD) of 2097 m, with 510 gpm, 45 rpm and SPP = 2500 psi. MWD survey was taken as required for checking the de via tion & sliding to the trajectory in control till TD.

To overcome tight spots, hole pack off and other hole instability problems, the decision was to Pool Out of Hole (POOH) and lower a slick 8 ½´´BHA for more wiper trips on November 17, 2009. The mentioned BHA went down on elevators from 1196 m to 1220 m only. After experiencing tight hole, Top Drive System (TDS) was connected and started reaming down from 1220 m to 1547 m, with mud pump discharge 550 gpm, mud density 11 ppg, string rotation 80 rpm and stand pipe pressure 1400 psi. No significant losses were recorded and a moderate amount of cuttings observed coming back over shakers.

From November 18, 2009, up to the end of December 2009, there was no significant production in drilling. All the operations were going around solving the instability of the well that leads to the stuck of logging tools and then to making a side track as summarized in Table 3 .

3.6. Wiper Trip Records

The increase in the mud density gradually from 11 ppg to 14.5 ppg gave a relatively good result in controlling well instability in the lower part. Increasing the density caused the hydrostatic pressure to be increased also and overcome the dominant problems like bridge and packing-off to some extent. This supported the expectation that the lower part problems are different from the upper part problems in this section in term of well instability. Mechanical instability begins with penetrating Shiranish or from somewhere in the transition interval between Tanjero and Shiranish formations.

On December 31, 2009, reaming and washing were performed using 14.5 ppg drilling mud without significant resistance to 1945 m [ 23 Korean National Oil Corporation, "Daily Drilling reports", KNOC, Kurdistan, Iraq, Rep. 3 ]. January 1, 2010, the third attempt of casing operation commenced successfully. Using waterbush in the last attempt of RIH casing made the casing pipes to rotate by TDS (Top Drive System) and pass the bridged intervals to a depth till 1843 m. Casing operation was bridged at 1843 m with no ability to lower more or POOH. Parameters used in running the casing were, WOH from 16 to 40-ton, rotation 10 rpm, mud flow 40 spm and 14.5 ppg WBM-Polymer. This depth became the setting depth of 9 5/8´´ casing.

4. NET RISING CALCULATIONS

Net rising calculations are used here to verify and check the validation of the wiper trips operations before the casing-running. For that, if the cutting increased with the wiper trip operations, this will be a strong indicator for other problems that cannot be solved with the wiper trips [ 24 J. Li, and S. Walker, "Sensitivity analysis of hole cleaning parameters in directional wells", SPE J. , vol. 6, no. 04, pp. 356-363. [ http://dx.doi.org/10.2118/74710-PA ] ]. In this case, rapid improvement of parameters like flow rate, annular velocity, pipe rotation, ROP, mud weight (density), mud rheology and cutting size/shape should be performed. These parameters directly affect the standpipe pressure and frictional pressure down the hole [ 25 A.K. Vajargah, and E. van Oort, "Determination of drilling fluid rheology under downhole conditions by using real-time distributed pressure data", J. Nat. Gas Sci. Eng. , vol. 24, pp. 400-411. [ http://dx.doi.org/10.1016/j.jngse.2015.04.004 ] ]. The first and most effective parameter in this relation is the mud density. Through the mud density, there will be a high possibility to return pressure balance between the formation pressure and hydrostatic pressure and thereby, prevent settling more cutting down the hole. To find out the effect of wiper trips in Bn-1 on improving the drilling operations, we will start with the calculation of cutting slip velocity [ 26 A.T. Bourgoyne Jr, K.K. Millheim, M.E. Chenevert, and F. Young Jr, "Applied drilling engineering chapter 8 solutions", Society of Petroleum Engineers , . ].

In general, there are two methods to calculate cutting slip velocity [ 27 N.J. Lapeyrouse, Formulas and calculations for drilling, production, and workover, Gulf professional publishing , . ]. If the net rising velocity is positive, it means that the drilling fluid properties and the flow rate are with accepted values to carry out cutting to the surface. In this case, the wiper trips will leave a positive effect on the operations. On the other hand, if net rise velocity is negative, it means that the flow rate and fluid properties are NOT accepted to carry out the cuttings [ 28 B.S. Aadnoy, Fundamentals of drilling engineering. , Society of Petroleum Engineers, . ]. In this case, all the effects with wiper trips operations without any other improvement are useless.

The first method depends mostly on the real field data using equations (1 - 3) below:

The annular velocity Av is provided by equation (1):

Where, Av is an annular velocity in ft/min. Q is the flow rate or Triplex Pump Output in gpm (gallon per minute), Dh is the diameter of the hole in inch and Dp is the diameter of drill pipe in inch.

The cutting slip velocity Vs is given in equation (2):

Where Vs is the cutting slip velocity in ft/min, Pv is the plastic viscosity in centipoise, Mw is mud weight in ppg., Ds is the diameter of cutting in inch and Mws is cutting density in ppg.

The net rise velocity Nv is given by equation (3):

The general formula for getting Q in units of gpm is given in equation (4):

Where, SPM is Stroke per minute, R is the liner size (inch) and Ls is the stroke length (inch).

Calculation of the pump output Q in gpm before and after modification of mud properties gives 441.9 gpm and 368.2 gpm, respectively by using equation (4), where a Ls=6.5 inch and SPM=90 before and SPM=75 after modification. Input data for the equations above are given in Table 4 .

The net rising velocity is estimated to Nv = 55 ft/min and 38.67 ft/min before and after mud modification, respectively. The increase in hydrostatic pressure by changing the mud properties prevents wall collapse and increases wall stability at the same time as a positive velocity is maintained. Thus, wiper trip was not necessary.

The second method for calculating the net rising velocity is quite different from the first method [ 27 N.J. Lapeyrouse, Formulas and calculations for drilling, production, and workover, Gulf professional publishing , . ]. However, it is still a straight forward calculation. The cutting slip viscosity in centipoise is given by equation (5):

Where n is the power law exponent given by equation (6)

Where, θ600 is a value at 600 viscometer dial reading and is a value at 300 viscometer dial reading.

The fluid consistency K is given by equation (7)

The annular velocity Av is calculated by equation no. (1) and the slip velocity (Vs) in ft/min from equation (8):

The net rise velocity is again calculated from equation (3) above. Input data for the equations above are given in Table 5 .

The net rising velocity is estimated to Nv = 76.3 ft/min and 63.7 ft/min before and after mud modification, respectively. The estimated flow rate is good for hole cleaning because the annular velocity is more than cutting slip velocity.

Koya University laboratories were used in preparing many WBM-polymer drilling fluids with different densities, pH and other rheological parameters. High Pressure - High Temperature (HPHT) filtration tests were performed and a Viscosity-Gel meter (VG) was used to find rheological properties based on the Bingham-Plastic model equations.

• The drilled 12 1/4'' section can be divided into two parts. The upper part is composed of Kolosh and Aliji formations that contain a high percentage of clay and the lower part is mostly limestone of the Shiranish formation with a low percentage of clay and this was indicated by previous researchers like Saad Z. Jassim and Jeremy C. Goff also [ 29 S.Z. Jassim, and J.C. Goff, Geology of Iraq, DOLIN, sro, distributed by Geological Society of London , . ].
• Hole problems in the upper part are mainly caused by chemical interactions between drilling fluid and a high percentage of clay like problems of tight spots and bridges. The problems in the lower part are mostly mechanical instabilities due to the high percentage of limestone which can be solved through the increase of mud density. Problems like well pack-off and bridge were more dominant in this part [ 23 Korean National Oil Corporation, "Daily Drilling reports", KNOC, Kurdistan, Iraq, Rep. 3 ].

• Mud logging records unit and cutting sampling matched the lithological description. The lithological description of the penetrated formations Aliji, Tanjero and Shiranish is presented in Table ( 6 ). The Aliji formation contains a higher percentage of clay than Tanjero and Shiranish. The last two formations are composed mainly of fractured marly limestone with some clay beds.
• All the field and laboratory tests enabled us to realize that the density between 11-12 ppg can give a very good over-balanced drilling operation in drilling the upper part of 12 ¼´´ section and 14-15 ppg for the lower part.

• Drilling performance reduced due to long time and high cost consumed for the wiper trips operations towards solving the well instability [ 30 Korea National Oil Corporation, "MLU DATA, KNOC", Kurdistan, iraq, Rep. MLOG 0-627 ].
• Instability of shale formation caused the stuck of BHA, downhole tools fishing, loss of equipment and side tracking operations.
• High chemical reactivity of the shale resulted in poor hole logging, inability to the land casing on the planned setting point and poor cementing conditions/jobs. Essentially increase in nonproductive time and increase in total drilling cost.
• Little over balanced mud property can sustain well stability in the upper part of 12 ¼´´ section where the chemical reactions are the main causes of drilling hole problems.
• Based on the positive results of the calculated net rising velocity, the lower part of the section is tectonically stressed and composed mainly of limestone. Wiper trips in tectonically stressed sections will be the waste of time if we do not return the over balance situation.
• Wiper trips in the upper part of 8 ½´´ section will leave a positive effect and negative effect on the lower part of the section.
• PHPA (partially hydrolyzed polyacrylamide) improves rheological properties like viscosity and gel strength and makes a thin gelatin barrier covering borehole wall. These improvements decrease the invasion of the formation and clay dispersion also.
• Wiper trips with homogenous improve in drilling fluid properties can give positive effects in solving problems in the 12 ¼´´section.

CONSENT FOR PUBLICATION

Not applicable.

CONFLICT OF INTEREST

The authors declare no conflict of interest, financial or otherwise.

ACKNOWLEDGMENTS

The authors would like to thank the support from the Ministry of Higher Education in Kurdistan ( via Koya University Laboratory). Thanks also to our colleagues from the Luleå University of Technology in Sweden, Korea National Oil Corporation (KNOC) for many valuable discussions and technical support.

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Browse Contents

Volume 12 - 2019, volume 11 - 2018, volume 10 - 2017, volume 9 - 2016, volume 8 - 2015, volume 7 - 2014, volume 6 - 2013, volume 5 - 2012, volume 4 - 2011, volume 3 - 2010, volume 2 - 2009, volume 1 - 2008, table of contents.

• INTRODUCTION
• KEY WELL BN-1 LOCATION
• Stratigraphy
• Sub-Surface Information
• Interval Summary
• Section Operation Data
• Wiper Trip Records
• NET RISING CALCULATIONS

• Ideas for Action
• Join the MAHB
• Why Join the MAHB?
• Current Associates
• Current Nodes
• What is the MAHB?
• Who is the MAHB?
• Acknowledgments

Drilling 16” Vertical Hole Section Good Procedure

The key objectives of this section of the well will be to optimize penetration rates, keep the hole as vertical as possible and to protect the Water Zone while achieving the goal of lowest cost per meter. Two (2) pumps at minimum should be utilized to drill this section, as well as having large liners (7″) installed. With PDC bits , the section requires the use of up to 1,000 gpm flowrates from drill out to casing point. More consideration shall be paid to the types of drill pipes used. The jets of the bit should be dressed accordingly . The penetration rate is to be kept as high as possible dependent upon the capability of the solids control system, hole cleaning, and hole conditions.

Consideration should also be given to making high viscosity sweeps of the hole as necessary to keep the annulus from loading up with cuttings. Wiper trips are to be made on an as needed basis, rather than a regular time interval.

Mud weights as high as 11.4 ppg have been utilized while drilling this section due to possible shale cavings from the Cenomanian and pore pressure from the Albien. It is believed that 10.5 to 10.8 ppg will be an adequate mud weight through this hole section to casing point. It is desired to keep the mud weight as low as possible in order to reduce any risk of lost circulation and to maximize penetration rates. However, rig personnel should be aware of the situation and a kick drill should be held prior to drilling in the Albien.

Unless deviation is critical, there will be only one survey at TD with multishot since directional work is not normally attempted in this section.

Generally only one bit will be required to drill this hole section. Additionally, a bit will often be able to be used for two wells. All equipment should be ordered via FR and confirmed for availability. Prior to reaching 13 3/8” casing point, confirm setting depth which is currently set at 20 meters into the Dogger Lagunaire.

13 5/8” BOPE should be stump tested during this hole section so that any failures can be repaired prior to nipple up.

Ensure wear bushing is installed. Pick up bit, BHA and run in the hole. Tag cement above the float shoe; record tag up depth. Test casing to 1500 psi for 30 minutes. Displace hole to a light weight oil based mud with tight filtration controls. Drill out shoe and 3 meters of new hole using low WOB and reduced pump rates. Circulate and condition mud. Pull the bit into the casing and perform a Formation Integrity Test (FIT) to 13.5 ppg EMW using mud pump. If FIT is not obtained notify Drilling Engineer and Drilling Manager. Control drill until stabilizers are below the shoe utilizing a light weight oil based mud with tight filtration controls. Once stabilizers are below the shoe drilling parameters can be increased to optimize ROP. Continue drilling to casing point, a minimum of 20 meters into the Dogger Lagunaire. The exact casing point will be specified in individual well prognosis.

Turonian formation has been giving us some problems and even sticking drill string. Historically after working pipe across the formation by reaming and/or wiper trip the problem stops through TD of the section. Reaming and/or wiper trip across it is strongly recommended. Short trips at approximately half way of the hole section or whenever the hole condition dictates.

Upon reaching casing point circulate bottoms up, make wiper trip as necessary, drop multi shot survey and POOH while SLM. LD Stabilizers & 9½” drill collars.

At present no logs are being run on this section with the exception of an Schlumberger CBL which is run after completion of drilling operation on the P2 hole section. Any changes to this program will be identified on the individual well programs.

Rig up and run the 13 3/8” P1 protective casing string as follows:

Note: This procedure assumes the 13-3/8″ casing will be cemented utilizing Litecrete for a single stage job.

PDC Drillable Float Shoe – Up Jet, Single valve (Installed on bottom of first joint and thread locked) 2 joints 13 3/8” Protective Casing (thread locked) NR PDC Drillable Non-rotating Float Collar – Single valve (Installed on bottom of third joint and thread locked) 13 3/8” P1 Protective Casing to surface

Centralizer Program:

Run 1 Bow Type Centralizer 2 m above the shoe. Run 1 Bow Type Centralizer 2 m below the float collar. Run 1 Bow Type Centralizer one every third joint across collars until 50 m below base of Albien interval. Run 1 Bow Type Centralizer every other joint to 20” casing shoe.

It will become SONARCO standard practice that prior to the cement job the mud pump displacement be checked and recorded. All lines and valves related to the job should also be checked and recorded. Pressure test from mud pump to cement head to ensure no fluid can bypass back to the pit. Isolate suction pit and return pit and check pit level while displacing so that a positive measurement of pump displacement and return volume is possible. Verify that the float shoe and float collar are free from debris. C. Clean threads and ensure casing drift is satisfactory for next hole section Threadlock the shoe, shoe track joints, float collar, and the next box above the float collar. Increase the normal make up torque to allow for the increased friction on the thread locked joints. (usually 1.5 times normal)

Due to high friction factor for thread lock (±1.5) occasionally had difficulty to have proper make up, therefore, a practice to smear thread lock while making up pipe is acceptable.

Ensure casing is torqued to proper makeup. The box should be made up to with in 0.2” of the base of the triangle and the apex of the triangle or base of triangle +2 turns/-1 turn within the prescribed torque range.

Mark the triangle with yellow/white paint if available for easy identification. Joints that are questionable as to their proper make up, with regard to previous base line torque established and its triangle stand off, should be looked more closely, if necessary they need to be unscrewed and laid down for further inspection.

Use Bakerseal thread compound, (FF = 0.7 ). Fill the casing as it is being run and check the float equipment for proper operation after making up the float joints, and after the first joint above the float collar. Observe returns at the flow line to verify float equipment operation. Casing specs will be provided in well specific programs and can be found in the Casing Section of this program. (if different than standard) Ensure that the proper casing swage (c/w Lo-Torque valve) is on the rig floor while running the casing (Dowell Supplied). Do not rotate the casing as it is being run. Run the casing to bottom, placing centralizers as per the centralizer program. Fill the casing while picking up each joint (however don’t wait). Completely fill the casing every 10 joints. Tag bottom and pick up to setting depth, checking strap calculation. Land casing with the shoe off bottom. Ensure that no casing coupling is at or near the casing hanger landing position of the wellhead. Rig up the cementing if losses occur- these must be cured before starting the cement job head and circulate at least one complete hole volume. Mud densities in and out must be equal and the shakers clear of cuttings and debris. During circulation, reciprocate the casing, if operationally feasible. Consider surge and swab effects in making all reciprocation decisions on frequency and length of reciprocation cycles. Pressure test all cementing equipment and lines to 3,500 psi. While circulating hold an operations/safety meeting with all relevant personnel.

NOTE: Dowell is to provide a two plug cementing head. See Cementing Section for details.

Mix and pump spacers and cement as per the recommended cementing program. The lead slurry will be generally 12.2 ppg LiteCrete cement and tailed with 15.8 ppg “G” cement as per cementing section. Use Non-rotating plugs. Top of cement planned 100 m inside 20” shoe utilizing 30% openhole excess (or 20% over caliper if run). and top of tail cement planned to top of Malm formation

Note: Cement isolation of Albien will be critical.

Displace the cement with the rig pumps . Slow pumps before bumping the plug. Iif possible, bump the plug with 2,500 psi and hold for 30 minutes to test casing. If the pressure bleeds off, DO NOT ATTEMPT TO RE-APPLY IT , in case the plugs are bypassing which will mean the cement will be overdisplaced [1] . Check float operation by releasing pressure on the casing. If the floats are not holding, pressure casing to plug bump pressure and wait on cement until surface samples have set hard in a heated place (water bath at 150 deg F). If plug does not bump at calculated displacement considering pump efficiency, do not over-displace by more than ½ of shoe track volume.

Note : If the plug does not bump, the casing will be tested later prior to cleaning-out the shoe track.

After cementing operations are complete, W.O.C. if necessary, then lift surface BOP stack and land casing with 100% final cemented hanging weight. Do not slack-off or tension casing. Rough cut casing string, RD surface casing BOPE, final cut casing string and NU Thru-Bore wellhead equipment. NU 13 5/8” 5K BOPE, choke and kill lines, etc. Pressure test seals as required refer to REB Testing Standards Sheet. Test wellhead assembly to 70% of casing collapse or 2500 psi, whichever is less. Make up the BOP test plug, ensure the lower annulus valve is open prior to landing the test plug in the wellhead and that the valve remains open and is monitored during all BOP testing. Function and pressure test the BOP and choke manifold to 250 psi low and 3,500 psi high for 5 minutes each test. Function and pressure test annular preventer to 250 psi low and 2,500 psi high for 5 minutes each as per the BOP test procedures section of this wellplan. Pull test plug. PU and set bowl protector.

Required reports following running P1 protective casing are:

casing tally, casing report with a complete description of the casing string, cementing reports with a complete description of the cement calculations, volumes pumped, cement slurry makeup and interval times during cementing operations.

1. As happened on RB-53 ↑

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Drilling dynamics

The aim of drilling-dynamics measurement is to make drilling the well more efficient and to minimize nonproductive time (NPT).

• 1 Measured parameters
• 2 Applications with formation testing while drilling (FTWD)
• 3 Data delivery to driller
• 4 Application of downhole shock sensors
• 5 Hydraulics management with PWD
• 6 References
• 8 Noteworthy papers in OnePetro
• 9 External links
• 10 Category

Measured parameters

Approximately 75% of all lost-time incidents of more than 6 hours are caused by drilling-mechanics failures. [1] Therefore, extensive effort is made to ensure that the drilling-mechanics information acquired is converted to a format usable by the driller and that usable data are provided to the rig floor.

The most frequently measured downhole drilling-mechanics parameters are:

• Downhole mud pressures (pressure while drilling (PWD))
• WOB(Weight on bit)
• Torque on bit
• Temperature

Applications with formation testing while drilling (FTWD)

Formation testing while drilling (FTWD) provides key formation pressures for drilling optimization. The data provided by these measurements are intended to enable informed, timely decisions by the drilling staff and thereby improve drilling efficiency. The two main causes of NPT are hole problems (addressed by hydraulics measurement and wellbore-integrity measurement) and drillstring and tool failure (addressed by drillstring-integrity measurement).

Data delivery to driller

To have a positive effect on drilling efficiency, drilling dynamics must have a quick feedback loop to the driller. Recent advances have made it possible to observe the cyclic oscillations in WOB. [2] If the oscillations exceed a predetermined threshold, they can be diagnosed as bit bounce, and a warning is transmitted to the surface. The driller can take corrective action (such as altering WOB), and observe whether the bit has stopped bouncing on the next data transmission. Other conditions, such as “stick-slip” (intermittent sticking of the bit and drillstring with rig torque applied, followed by damaging release or slip) and torsional shocks, also can be diagnosed and corrected.

Application of downhole shock sensors

Another application is the use of downhole shock sensors, which count the number of shocks that exceed a preset force threshold over a specific period. This number of occurrences is then transmitted to the surface. Downhole shock levels can be correlated with the design specification of the MWD tool. If the tool is operated above design thresholds for a period, the likelihood of tool failure increases proportionally. Of course, a strong correlation exists between continuous shocking of the BHA and the mechanical failure that causes the drillstring to part. In most cases, lateral-shock readings have been observed at significantly higher levels than axial (along the tool axis) shock.

Hydraulics management with PWD

Hydraulics management with PWD has proved a key enabling technology in extended-reach wells where long tangent sections may have been drilled. Studies performed on such wells have shown that hole cleaning can be difficult and that cuttings can build up on the lower side of the borehole. If this buildup is not identified early enough, loss of ROP(Rate of Penetration) and sticking problems can result. A downhole annulus-pressure measurement can monitor backpressure while circulating the mud volume, and, assuming that flow rates are unchanged, it can identify precisely if a wiper trip should be performed to clean the hole. Fig. 1 shows an example in which cuttings have fallen out of suspension in the annulus during a period of sliding. Once rotation is resumed, the cuttings are agitated and suspended once more in the mudstream with a consequent increase in equivalent circulating density (ECD).

Fig. 1—Downhole sensors provide useful drilling measurements.

In wells in which there is a narrow window between pore pressure and fracture gradient (e.g., deep water), the uncertainties can be reduced greatly through the use of PWD and FTWD technology. Downhole measurement and transmission of leakoff tests eliminate errors associated with surface measurements. Real-time Equivalent Circulating Density (ECD) measurements pinpoint key pressure parameters frequently and accurately. Finally, real-time measurement of pore pressure identifies exactly the mud weight required.

• ↑ Burgess, T.M. and Martin, C.A. 1995. Wellsite Action on Drilling Mechanics Information Improves Economics. Presented at the SPE/IADC Drilling Conference, Amsterdam, The Netherlands, 28 February–2 March. SPE-29431-MS. http://dx.doi.org/10.2118/29431-MS .
• ↑ Hutchinson, M., Dubinsky, V., and Henneuse, H. 1995. An MWD Downhole Assistant Driller. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 22-25 October. SPE-30523-MS. http://dx.doi.org/10.2118/30523-MS .

PEH:Drilling-Data_Acquisition

Noteworthy papers in OnePetro

Dubinsky, V.S. and Baecker, D.R. 1998. An Interactive Drilling Dynamics Simulator for Drilling Optimization and Training, SPE Annual Technical Conference and Exhibition, 27-30 September. 49205-MS. http://dx.doi.org/10.2118/49205-MS .

Heisig, G., Sancho, J. and Macpherson, J.D. 1998. Downhole Diagnosis of Drilling Dynamics Data Provides New Level Drilling Process Control to Driller, SPE Annual Technical Conference and Exhibition, 27-30 September. 49206-MS. http://dx.doi.org/10.2118/49206-MS .

External links

• 1.6 Drilling operations

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Home > Books > Advances in Oil and Gas Well Engineering

Casing While Drilling

Submitted: 05 September 2023 Reviewed: 02 November 2023 Published: 13 March 2024

DOI: 10.5772/intechopen.113889

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Conventional drilling methods have faced significant operational and financial challenges, such as the cost of purchasing, inspecting, handling, and transporting drill equipment, and, most importantly, tripping in and out of the drill string whenever the Bottom Hole Assembly (BHA) requires replacement, a wiper trip, or total depth is reached. Tripping the drill string in and out not only contributes to Non Productive Time (NPT), but also causes well control issues such as wellbore instability and lost circulation. All of this has prompted the oil and gas sector, as well as any other engineering industry, to look for innovative techniques and approaches to address these issues. A new drilling method has emerged as a result of technological developments and continuous improvements to conventional drilling methods. Casing when drilling has been established as a result of technological developments and continuous improvements to traditional drilling processes. Casing Drilling is the process of drilling and casing a well at the same time, employing active casing to maximize production. This paper provides an overview of the casing while drilling method (CwD) and its practical application in well drilling. The typical drilling method and casing while drilling are also compared. The CwD approach outperforms the standard drilling method by a wide margin.

• non productive time
• bottom hole assembly
• casing while drilling

Author Information

Siraj bhatkar *.

• Department of Petroleum Engineering, MIT-World Peace University, Pune, India

Vinayak Wadgaonkar

*Address all correspondence to: [email protected]

1. Introduction

The rising need for and reliance on energy resources by mankind, especially those brought on by the discovery and exploitation of new commercial hydrocarbon deposits, entails the utilization of innovative innovations, such as drilling process optimization by lowering the expenses, the hazards, and the wasted time. While drilling, casing while drilling replacing traditional drilling string with casing string both to circulate and to transmit mechanical energy to the bit a well is being drilled with fluid. Casing while drilling has a lot of technical and cultural obstacles to overcome, but the significant advantages of this technology—such as shorter drilling times and fewer issues with the drilling string—make it a more and more attractive option to traditional drilling. Experience with using this technology has shown that it can speed up well execution and, occasionally, lower expenses relative to drilling depth.

According to data from the International Energy Agency [ 1 ], the world’s natural gas demand has been rising steadily since 2009, reaching 3757 billion m3, with the potential to climb to a 23–25% share of the world’s energy consumption by 2040. Since natural gas is the primary fuel substitute for coal in the electricity generation industry, despite the higher risks associated with the explosive nature of natural gases, the world’s increased demand for this fuel is primarily due to its lower environmental impact when compared to other fossil fuels, particularly with regard to air quality and greenhouse gas emissions [ 2 ]. Accordingly, 22% of the world’s electricity supply in 2014 was made up of natural gas. This may vary from 17 to 32% by 2060, representing a 300–1500 bcm absolute increase [ 3 ].

Gas producers develop drilling programs for both production and exploration in order to meet this demand. Production drilling aims to boost the rate of gas production from existing reservoirs. Exploration drilling seeks to find new gas sources [ 4 ]. Due to difficulties and technological mishaps that may occur during drilling that may increase the wells’ final cost, sizeable sums are frequently allotted to achieve such investment plans. However, these sums are frequently wasted before the program is completed [ 5 ]. More and more businesses experiment with and use novel drilling techniques and technology that decrease downtime, mitigate risk, and prevent technical mishaps during drilling in an effort to lower such unanticipated expenses of well drilling operations. Casing while drilling, also known as CwD (Continuous Bottom hole Pressure), Pressurized Mud Cap Drilling, and Dual Gradient Drilling, are alternatives to controlled pressure drilling [ 6 ]. Casing while drilling is an alternative to standard drilling that involves drilling the well and casing it at the same time [ 7 ].

Even though the casing while drilling method was developed in the 1920s, widespread use wasn’t conceivable until the last 10 years as a result of technical developments [ 4 , 8 ]. By minimizing drilling time and issues with the drilling string, the strategy was therefore shown to be successful in lowering overall drilling costs.

1.1 The tools for casing while drilling

Casing during drilling can be done with either standard drilling rigs that require little additional equipment or drilling rigs that are specifically designed for this usage.

The drilling rig, which consists of the three vital systems of drive, rotary, and circulation, must achieve the principal parameters of the drilling regime and consolidation of the well bore [ 9 ]. The conventional links are operated remotely in order to remove the derrick man from the monkey board, and the surface casing drive systems have been modified and improved to allow for casing while drilling. This allows the casing to be run in the hole, the drilling fluid to be circulated, and the casing to rotate safely on the derrick in place of the conventional tongs.

Surface Casing Drive Systems ( Figure 1 ) can be used for a wide range of casing sizes because they can be automatically controlled by PLC from the driller cabin and can be externally clamped for small casings (from 3 12 in to 9 5/8 in) or internally clamped for casing larger than 9 5/8 in.

Casing drive system.

Rotate the casing from above to provide torque to a bottom hole assembly that drills and cements; or

Run a retractable bottom hole assembly inside the casing that includes a bit and a reamer.

In order to drill by rotating the casing from the surface, which eliminated the ability to remove the bit, it was necessary to develop specialized drilling bits that had comparable performance to normal bits. Since they are simple to mill with PDC bits after cementing, these may act as casing shoes once the appropriate depth has been reached— Figure 2 .

Milling the drilling bit used for CwD.

In order to cement immediately after hitting TD, a float collar is typically installed within the casing while drilling.

The steel float collar ( Figure 3 ) almost matches the resistance of the casing, and its valve must withstand drilling fluid erosion as well as pump pressure and pressure from the casing itself. The casing is fitted with centralizers to keep the well on track, to control casing wear, and to line the casing up during cementing ( Figure 4 ). During directional drilling with casing, it is advised to utilize centralizers with rough surfaces and robust, non-rotating blades made of zinc alloy since they are incredibly durable (see Figure 5 ).

Float collar.

Wiper plugs.

Centralizer sub.

In order to accommodate the unique operating circumstances in the well, casing threads are different from those used for traditional drilling. As a result, the casing makers created a variety of casings to address the difficulties and harsh well conditions that emerged during casing while drilling. These connections must guarantee fatigue resistance, sufficient sealing capability, and torque resistance [ 10 ].

When casing while drilling, it may be necessary to use a recoverable/retractable drilling system since damaged equipment must be replaced before the casing depth is reached.

In order to retrieve the costly drilling equipment used for a directional casing, operators must quickly and effectively reach the formations beneath the casing shoe.

A bottom hole assembly (BHA), which can be inserted into and removed by a wireline, is used for drilling while casing. Its basic components are a bit and an under reamer at the bottom of the casing string to drill a hole large enough to allow the casing to pass freely. The BHA is placed in a nipple at the lower end of the casing string that can be retrieved by wireline without removing the casing from the well and is attached to a Drill-Lock Assembly (DLA) engaging axial lock and torsional lock. The releasable DLA transfers compression and torque loading while rotating the drilling and casing strings. It is advised to apply centralizers on the casing to stop sleeves from wearing out [ 11 ].

2. CwD benefits

Drill collar, Kelly, and drill pipe can twist off;

Drilling string sub-assemblies can pull out of threads or unscrew;

Drilling string can become trapped; and

Drill pipe can shatter or bend.

Another set of issues related to installing casing in wells with bent or collapsed holes can be avoided by doing it while drilling. Additionally, difficulties brought on by crossing unstable formations (borehole collapsing and over pull), crossing formations with loss of circulation, or crossing formations that have deteriorated from prolonged contact with drilling fluids can all be avoided [ 12 ].

These problems are solved by the so-called plastering effect, which is produced by spinning the casing string in a small annular region, sealing the formation pores, and fortifying the borehole walls.

According to Figure 6 , while drilling with a standard drilling string, the annular gap is bigger. By using casing during drilling, the annular space is reduced to a minimum, creating a wellbore that is more stable and sealed. Furthermore, the stiffness of the casing string creates a less convoluted hole, lowering the possibility of key seats or mechanical sticking, and the high annular rising velocity of the drilling fluid via this annular region enhances debris cleaning from the wellbore.

Annular space size in conventional drilling vs. casing while drilling.

By removing the time and effort required for casing string tripping, CwD also has the advantage of reducing drilling time overall. Since the float collar was inserted before drilling began, the drilling fluid is changed with cement once the casing-setting depth has been reached. For this reason, operations such as control tripping of the borehole to correct over pulling areas, circulating to remove solids from the fluid, performing electrometric operations, retrieving the bit by decomposing strings, and inserting casing by filling the casing string at each casing section are avoided [ 13 ].

2.1 Problems with the CwD casing design

A steel casing that is bolted together for CwD boreholes strengthens the casing design concerns. The commonly utilized casing is 6–12 m long, with diameters of 4–20 in, and wall thicknesses of 5–15 mm.

Prevent the wellbore from collapsing; − isolate formations that pose significant drilling challenges (formation overpressure or easily breakable);

Provide a sturdy support for the surface facilities (preventers, Christmas tree);

Transfer through the suspension system to the surrounding rocks the axial loading of the next casing sections or tubing and of the surface facilities weight;

To ensure sealing of layers containing different types of fluids; varying pressures.

Tensile force, compression, outer and inner pressure, and gravity are the forces affecting the casing string (see Figure 7 ). Additional forces (fatigue, torque, and buckling) act on the casing when drilling because of it. In order to determine the profile of a casing, the strength of the casing to these forces must be understood.

Forces acting on the casing.

The weight of the casing itself causes tensile force to exist. These will snap at the weakest area if the tensile force exceeds a critical level, which is equal to the tensile strength of the casing.

Given that the tensile strength of the casing’s connection is different from the strength of the casing body, the calculation must be performed for both components in order to take into account the lowest values when determining the casing profile. The fluid behind the casing’s hydrostatic column provides the majority of the outside pressure.

When the pressure exceeds the strength of the casing, the casing may collapse. We must take into account the relationship between the nominal diameter D and wall thickness t in order to calculate the critical pressure for casing made in accordance with API regulations. The ratio (thick wall casing) determines the outer pressure that is exerted on the inner casing wall at the minimal yield point.

The cutting action, as well as the friction of the casing against the borehole wall and/or the previously cased hole, result in torque at the drill bit at the bottom of the hole. Since the drill bit is above the bottom hole, the only source of torque is casing friction. Due to friction forces operating on the point where the borehole walls and casing make contact, the torque applied to the casing during drilling is typically larger than during traditional drilling, resulting in a strength moment whose vector direction is the opposite of the casing’s rotation. Thus, the moment at the bit is substantially lower than the rotating moment at the surface when the casing is rotating in the borehole and exerting a certain weight on the bit [ 14 ].

The cyclic load at various stress levels that are significantly below the material’s yield point causes fatigue. A minor fracture begins to grow from the high-stress point along the casing and eventually breaks it under sustained strain.

It becomes unstable due to buckling, which is caused by the bending moments produced by the geometry of the casing borehole and the compressive stress. If the casing is subjected to compressive stress that is greater than a specific threshold, the casing buckles into a sinusoidal or helical pattern.

Following buckling, the casing leans on the borehole walls; as a result, the lateral force from the point of contact may produce wear and raise the moment needed for rotation [ 15 ].

including preliminary sizing for cracking and crushing,

correcting the profile set in the first stage by lowering the casing collapsing pressure under tensile forces, and

Testing the tensile resistance of the casing and joints.

bending with tongs during make-up;

joint pull-out and slip crushing;

Corrosion and fatigue failure; and

Pipe wear from using drill strings and wireline instruments.

It is necessary to use safety coefficients during the design phase to execute casing while drilling under safe settings. Tensile forces should be given the strongest safety coefficients possible in order to account for additional stress caused by things like buckling, dynamic forces, sticking trends, and friction with the borehole wall. For the upper joint of the casing, a safety factor of 1.6 to 1.8 is used in relation to tension. The calculation hypotheses for such stress are less likely to be realized when the coefficient for breaking and crushing is smaller, for breaking 1.1 and 1.0, and for crushing 0.9.

3. Casing while drilling-related safety issues versus traditional drilling

Risk is the possibility of an occurrence that could be advantageous or detrimental to a project or activity. It can be defined as a combination of the likelihood that the risk will materialize and the implications of loss or gain. As a result, hazards can be divided into four categories: low, medium, high, and very high. The methodical process of locating, evaluating, and reacting to a project’s possible risks is known as risk management [ 16 ].

Drilling risks may be caused by geology, technical-operational problems, or a mix of the two while a project is being carried out. The so-called difficult geological formations are characterized by the physical and chemical properties of the rocks through which the borehole passes and by the properties of fluids contained in pores or fractures; subjective challenges are related to technology and method. In terms of projects, all risks are identified, risk exposure is evaluated by calculating the likelihood of occurrence and the impact, and then such risks are avoided or managed by putting in place an effective risk management system. The primary dangers that could arise during conventional drilling are depicted on maps in Tables 1 and 2 . Or during drilling, casing. Each project’s risk occurrence likelihood is individually estimated based on correlation wells, drilling technology, and techniques. Comparing the two tables leads to the conclusion that drilling with casing could result in a reduction or minimize drilling-related hazards, particularly those relating to traditional drilling string, to preserve circulation loss or borehole stability [ 17 ].

Drilling cost comparison between conventional drilling and CwD for vertical well.

Capital equipment cost required to convert conventional drilling rig into CwD rig.

• 1. Abubakar M, Chika JO, Ikebudu AO. Current trends and future development in casing drilling. International Journal of Science and Technology. 2012; 2 (8):567-582
• 2. Buntoro A. Casing drilling technology as the alternative drilling efficiency. In: IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Held in Jakarta, Indonesia, 25-27. August 2008. Houston, Texas, US: Society of Petroleum Engineers; 2008
• 3. Fontenot KR et al. Using casing to drill directional Wells. Oilfield Review. 2005; 17 (2):44-61
• 4. Gaurina-Međimurec N. Casing drilling technology. Rudarsko-geološkonaftni zbornik. 2005; 17 (1):19-26
• 5. Houtchens B, Foster J, Tessari R. Applying risk analysis to casing while drilling. In: Proceedings at the SPE/IADC Drilling Conference, Held in Richardson, Texas, 20-22. February 2007. Houston, Texas, US: Society of Petroleum Engineers; 2007
• 6. Halliburton. Floating Equipment [Online]. Houston, Texas, US: Halliburton; 2016. Available from: http://www.halliburton.com/en-US/ps/cementing/casing-equipment/floatingequipment/default.page?node-id=hfqela4z [Accessed: August 03, 2016]
• 7. Kerunwa A, Anyadiegwu CIC. Overview of the advances in casing drilling technology. Petroleum & Coal. 2015; 57 (6):661-675
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• 9. Sanchez F et al. Casing while drilling (CwD): A new approach to drilling Fiqa formation in the Sultanate of Oman – A success story. SPE Drilling & Completion. 2012; 27 (2):223-232
• 10. Shepard SF, Reiley RH, Warren TM. Casing drilling: An emerging technology. In: Proceedings at the SPE/IADC Drilling Conference, Held in Amsterdam, Netherlands, 27th February – 1st March 2001. Houston, Texas, US: Society of Petroleum Engineers; 2001
• 11. Schlumberger. Hydro-Formed Casing Centralizer [Online] Schlumberger. 2013. Available from: http://www.slb.com/~/media/Files/drilling/product_sheets/drilling_applications/casing_hydro_form_centralizers_ps.pdf [Accessed: August 01, 2016]
• 12. Tessari RM, Madell G. Casing drilling – A revolutionary approach to reducing well costs. In: Proceedings at the SPE/IADC Drilling Conference, Held in Amsterdam, Netherlands, 9-11. March, 1999. Houston, Texas, US: Society of Petroleum Engineers; 1999
• 13. Tesco. Casing Drive System [Online] Tesco. 2016. Available from: http://www.tescocorp.com/Rentals/Casing_Running_Tools/Casing_Drive_System.aspx [Accessed: August 03, 2016]
• 14. Warren TM, Angman P, Houtchens B. Casing drilling: Application design considerations. In: Proceedings at the SPE/IADC drilling conference, held in New Orleans, Louisiana, 23-25 February, 2000. Houston, Texas, US: Society of Petroleum Engineers; 2000
• 15. Warren TM, Houtchens B, Madell G. Casing drilling technology moves to more challenging applications. In: AADE 2001 National Drilling Conference, Held in Omni in Houston, Texas, 27-29. March, 2001. Houston, Texas, US: American Association of Drilling Engineers; 2001
• 16. Warren TM, Lesso B. Casing directional drilling. In: AADE 2005 National Technical Conference and Exhibition, Held at the Wyndam Greenspoint in Houston. Houston, Texas, US: American Association of Drilling Engineers; 5-7 April 2005
• 17. Aade. Weatherford. Defyer DPA Series [Online] Weatherford. 2014. Available from: http://www.weatherford.com/doc/wft154348 [Accessed: August 01, 2016]

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Wiper Trips Effect on Wellbore Instability Using Net Rising Velocity Methods

The Open Petroleum Engineering Journal

Background: This paper discusses the wiper trip effects on well instability in shale formations. Objectives: Problematic shale interval sections have been studied for the time spent on the wiper trip operations. Lifting efficiency and well wall instability change with the time analyzed. Detailed drilling operation, formation heterogeneity, rheological and filtration characteristics of polymer water-based mud are discussed. Physical and chemical properties of the drilled formation and drilling fluid are also studied. Materials and Methods: Wiper trips are analyzed using a typical drawing program to find the relations between the most controllable parameters. For that, two calculation models have been implemented to find the net rising cutting particles velocity in the annular. The relation between the net rising velocity and wiper trips is analyzed. Laboratory works have been done to support the findings of field work. Results: Strong relations have been found between the wiper trip ...

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Look up terms beginning with:

1. n. [Drilling]

The complete operation of removing the drillstring from the wellbore and running it back in the hole. This operation is typically undertaken when the bit becomes dull or broken, and no longer drills the rock efficiently. After some preliminary preparations for the trip, the rig crew removes the drillstring 90 ft [27 m] at a time, by unscrewing every third drillpipe or drill collar connection . When the three joints are unscrewed from the rest of the drillstring, they are carefully stored upright in the derrick by the fingerboards at the top and careful placement on wooden planks on the rig floor . After the drillstring has been removed from the wellbore, the dull bit is unscrewed with the use of a bit breaker and quickly examined to determine why the bit dulled or failed. Depending on the failure mechanism, the crew might choose a different type of bit for the next section. If the bearings on the prior bit failed, but the cutting structures are still sharp and intact, the crew may opt for a faster drilling (less durable) cutting structure. Conversely, if the bit teeth are worn out but the bearings are still sealed and functioning, the crew should choose a bit with more durable (and less aggressive) cutting structures. Once the bit is chosen, it is screwed onto the bottom of the drill collars with the help of the bit breaker, the drill collars are run into the hole ( RIH ), and the drillpipe is run in the hole. Once on bottom, drilling commences again. The duration of this operation depends on the total depth of the well and the skill of the rig crew. A general estimate for a competent crew is that the round trip requires one hour per thousand feet of hole, plus an hour or two for handling collars and bits. At that rate, a round trip in a ten thousand-foot well might take twelve hours. A round trip for a 30,000-ft [9230 m] well might take 32 or more hours, especially if intermediate hole-cleaning operations must be undertaken.

Alternate Form: trip

See: bit breaker ,  break circulation ,  derrick ,  derrickman ,  fingerboard ,  run in hole ,  tripping pipe ,  wiper trip

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Tech Feature

Drilling Rigs & Equipment

Activated Drilling Scraper optimizes debris recovery while reducing rig time

During a recent drilling campaign Coretrax's Activated Drilling Scraper (ADS) was deployed in the Middle East for efficient debris recovery and reduced rig time.

David Cook, US country manager, Coretrax

The ADS eliminates the requirement for a dedicated scraper trip.

Technology development is playing a crucial role in reducing emissions while driving efficient hydrocarbon recovery as the oil and gas industry increases its efforts to support international environmental targets. With global drilling activity set to increase by 19% this year compared to 2020 levels1, operators are increasingly looking to adopt new solutions which deliver more efficient and economical operations.

Debris recovery is an essential step of any drilling campaign to ensure that the well cleanliness is optimized before moving to the next stage of operations, creating clean setting areas for packers and reducing the risk of damage to subsequent tools being run.

Well integrity and production optimization company Coretrax developed its Activated Drilling Scraper (ADS) to lie dormant in the drilling bottom-hole assembly (BHA) until drilling has been completed to deliver a more efficient and effective debris removal and casing cleaning method.

When activated, a ball is dropped to activate the scraper and allow the scraper blades to engage with the casing ID. The casing can then be cleaned and prepared for the installation of packers, including liner hangers while pulling out of hole with the drilling BHA.

Coretrax recently deployed its ADS technology for a client in the Middle East, which successfully eliminated the requirement for a dedicated scraper trip once drilling was complete, resulting in reduced rig time and effective debris removal.

Driving Efficient Debris Recovery

During a recent drilling campaign in the United Arab Emirates, the operator required a more efficient solution for debris recovery which would reduce rig time without compromising the effectiveness of residue removal or personnel safety.

Coretrax’s ADS was selected as the most appropriate tool as it remains dormant in the string until activated, allowing the operations and liner hanger preparation to be completed in a single trip.

The design features high torque premium connections making it suitable to be in heavy-duty drilling BHAs even when drilling horizontal sections with significant torques and drags.

Once hydraulically activated, by dropping a ball from surface, the ADS’s blades provide 360° coverage for effective removal of debris. Multiple activated drilling scrapers can be run in tandem to scrape multiple casing strings in a single trip, further optimizing drilling operations and wiper trips.

While drilling, the ADS system was run in hole with a 6” drilling assembly with two drilling scrapers positioned in the 9-5/8” and 7” casing sections. The tagging depth of 15,378ft [~4687m] was reached, and the hole was circulated clean. The 7” scraper was then hydraulically activated, by dropping a 1.69” ball from surface, followed by a 2.75” ball to activate the 9-5/8” system.

The 7” and 9-5/8” inner diameter (ID) casing sections were then effectively scraped clean simultaneously across the required intervals of 14,070ft [4288.5m ] - 13,890ft [4233.6m] and 7,874ft [~2400m ] - 7,694ft [~2345m ], respectively.

The tools were then pulled out of hole and liner hanger operations were able to continue immediately. Following retrieval, the tools were found to be in good condition, with all stages efficiently activated.

The application of the ADS eliminated the requirement for a dedicated scraper trip to prepare the ID casings prior to setting the liner hanger, effectively saving the operator 30 hours in valuable rig time and delivering a more efficient, sustainable solution.

As operators are increasingly more closely scrutinized on ESG commitments, technology which effectively decarbonizes operations while delivering efficient oil recovery is crucial. With the world moving closers towards global net zero goals, bringing together technical advancements and multi-functional products combined in one package to deliver highly efficient products will be essential to the future of the oil and gas industry.