Abstract
Big Data Analysis from the worldwide field shows that lost circulation is a common phenomenon in drilling and the success ratio of remedial treatment for lost circulation is low. It is not only because of these complexities of the formation, but also because of the poor performances of the lost-circulation materials (LCM) and technologies. This paper proposes a new method in plugging, which is based on a particular physical method for lost circulation controlling and plugging while drilling. This method is different from these traditional treatments, which only use chemical methods. When pore-permeable and fractured leakage formations are encountered while drilling, We can use this new hydraulic tool, the drilling fluid will have a diffluence at a constant rate from the jet of the hydraulic tool which is installed on the drilling pipe and the fluid laden with particles can be injected into the natural or induced fractures of the borehole wall which may lead to lost circulation. Combined with the corresponding drilling fluids which have been tested in the laboratory, the additives such as ground marble, ground nutshells, and graphite in the drilling fluid are quickly pushed into the fractures because of the differential pressure provide by the hydraulic tool, then form a firm seal at the mouth of the fractures which could isolate fluid pressure in the wellbore and prevent effective pressure communication to interfere the extension of the fracture. What’s more, according to the stress cage theory, when these sealing particles which prop the fracture open, act as wedges to compress the rock around the wellbore, the hoop stress could be increased, so that the wellbore pressure containment (WPC) could be improved. Since the annular flow may have some interference with the side nozzle jet, this paper also numerically simulates the flow field of the annular air section through the fluid simulation software Fluent, and the simulation results show that the interference of the annular flow on the jet is very weak and basically has no effect. In addition, through the oilfield field test, it is known that this new physical plugging method has good plugging effect, and it can obviously improve the pressure-bearing capacity of the formation, which has great popularization value.
Keywords: Hydraulic tool, Lost circulation controlling and plugging while drilling
Subject terms: Energy science and technology, Engineering
Introduction
With the rapid development of the economy and increasing demand for energy, the number of deep wells, complex wells and non-conventional wells has gradually increased1,2. As a result, the lost circulation events that is defined as the loss of whole mud, in quantity, to exposed formation3, which have plagued the petroleum industry for many years, as a major complication in drilling operations when the wellbore pressure exceeds the breakdown pressure in the weak or depleted formation where the safe mud-weight windows are often very narrow4, have increased. In formations with high permeability, especially in fractured or depleted formation, lost circulation may occur5,6. When lost circulation occurs, there is always an inevitable waste of time, manpower, material and investment7. What’s more, the severe loss in circulation will lead to safety hazards and economic risks, such as wellbore instability, blow out, formation damage, even well abandonment and sidetracking of the well5,8.
In the early times, curation was the main remedy when encountering lost circulation with little or no preparation because of the limited technology available. As a consequence, the drilling process often was interrupted and non-productive rig time increased. Later there were some methods developed to tackle lost circulation without interrupting the operations of drilling, though some limitations still existed9. As well known, the chemical method was in common use to deal with the lost circulation in drilling. But there were high requirements on the property of the chemical material. For example, the chemical materials must have good adaptability to the loss zone. Also the LCM’s type, concentration, and particle size distribution are all important factors10,11. More importantly, the ability of carrier fluid to suspend the LCMs is a critical factor in high-pressure/high-temperature (HP/HT) or inclined wells12. And when the fluids were heavily laden with chemical materials, the rheology and fluid loss characteristics will certainly be affected. In general, because of the poor performances of the materials, the LCM was not always effective in dealing with lost circulation13. And after the pretreatment, the pressure-bearing capacity of the formation was often not enough, so lost circulation could happen again in the drilling operation.
Preventive treatments are more effective than remedial treatments when drilling, especially for depleted and weak formations14. Generally speaking, the most popular way in the field is wellbore strengthening (WBS)15, which is used to improve the WPC by increasing the hoop stress around the wellbore and creating isolation at the tip of the fracture to increase the fracture propagation resistance (FPR) and widen the narrow mud weight window. In order to achieve the goal, these induced or natural fractures must be held open and propped by using bridge materials, so the plug formed in the fracture not only acts as a wedge which can hold the fracture open and compress the adjacent formation within a zone around the wellbore to create an increase of the hoop stress, but also provide pressure isolation. This approach is called a stress cage, which is illustrated in Fig. 116. However, the formation of the stress cage has not always been reliable in some instances by only using the addition of some mud additives. As is well known, in order to achieve the reliability and stability of the induced stress cage, the first requirement is that the particles with sufficient size and concentration must be pushed into the fracture and the fracture must be enlarged, but a few issues remain with this solution17.
Fig. 1.
Concept of stress cage.
First, during the drilling process, when the pump rate is high, there is a collision between the particles and the LCM enter into the fracture passively while the drilling fluid flows up through the annulus to the surface. As a result, many particles may be heaped up on the wellbore wall rather than enter into the fracture18. Namely, these particles plaster on the wellbore wall and hinder more LCM getting into the fracture, so that only a small percentage of the additives can enter into the fracture, which may result in the increasing of the filter cake thickness and the risk of differentially stuck pipe11. As shown in Fig. 2a, this phenomenon can be referred to as “front plugging”. Evidently, the plug plastered on the wellbore has poor strength to withstand washout. So we want “throat plugging” and “middle plugging”, as shown in Fig. 2b and c, respectively. Second, in order to improve the integrity of the formation, a final blocked width must be sufficient to ensure the closing stress greater than equivalent circulating density (ECD)19. But sometimes the fracture pressure may be so low that the fracture will not be fully open. Third, the immobile mass formed in the fracture must withstand the positive pressure as well as the negative pressure created by swabbing or stopping the pump. If the immobile mass is not tight or stable enough, the material will be pushed back out of the fracture and the fracture must be re-opened so that repeated occurrence of lost circulation may emerge.
Fig. 2.
States of plug.
In this paper, to the issues discussed above, a solution is proposed. Figure 3 illustrates the concept of this solution. A hydraulic tool is used to offer an added lateral pressure to inject these particles into the fracture, which acts as this hammer shown in Fig. 1, so more solids will be allowed to enter into the fracture rather than accumulate on the wellbore wall. The differential pressure will enlarge the fracture and a more durable plugging that has good crush strength or crush resistance will be formed in the fracture because of the compaction provided by the jet impact force to avoid an occurrence that when the pressure surge happens in the wellbore, the bridging materials will be pushed back out of the fracture20. This solution can be called “a physical method for lost circulation prevention and plugging while drilling”. With the use of the hydraulic tool, it is possible to improve the wellbore pressure containment as quickly as possible when a new formation is exposed and control lost circulation before it occurs.
Fig. 3.
Concept of a physical method for lost circulation prevention and plugging whilst drilling. 1—drill collar; 2—hydraulic tool; 3—jet; 4—bit; 5—bit nozzle; 6—bottom; 7—thief zone; 8—wellbore wall; 9—annulus.
The hydraulic tool, as shown in Fig. 4a, is a pipe which has a threads box on both ends. In Fig. 4b, due to the limitation of experimental equipment, a small size sample having a pin on the upper end has been manufactured. In the drilling process, it is designed to run into the hole as a component of the BHA. The simple structure of this tool provides easy access to installment and high security. For example it can be fixed between the drill collar and the bit as a bit sub which is designed as a pup joint for greater protection against wear at the bottom threads of the bottom drill collar21. As soon as a new formation is exposed by the bit, it is necessary to ensure that freshly drilled formations are always protected. During the fluid circulation, a given volume (9-15%) of drilling fluid will be divided through the two lateral nozzles toward the borehole wall to offer an impact force which will act on the borehole wall. Because of the diffluence from the two lateral nozzles, these particles as additives in the drilling fluid can acquire a velocity which is perpendicular to the wall instead of a movement in a random manner and the occurrence of collision between the particles can be avoided. Particles and fluid can bypass cuttings and continue to propagate the fracture. More importantly, due to the impact force provided by the diffluence, more particles will enter into the fracture instead of accumulating on the wellbore wall and the carrying fluid can leak off more quickly, so the LCM volume that directly affects the result of plugging becomes bigger than traditional treatment. The immobile mass formed in the fracture will become more stable and have a better crush strength. In addition, under the impact force, a very thick filter-cake is allowed to deposit on the wellbore, which can be called “man-made borehole wall”. Once the borehole is fully filled with the hard filter cake, the wellbore is stronger than before the fracture was initiated.
Fig. 4.
Sectional view of the hydraulic tool and the small size sample. (a) Sectional view of the hydraulic (b) A small size sample.
Methodology
Experiment
Materials design
Since synthetic-based drilling fluids are widely used in oilfields due to their good lubricity, thermal stability, and environmental friendliness compared to other types of drilling fluids such as water-based drilling fluids and oil-based drilling fluids, this drilling fluid was chosen for this experiment.
Synthetic-based fluids (SBM): 3%bentonite muds+5％Na2CO3+0.3%Coating agent+0.3%Zwitterionic polymer viscosity reducer +0.9%Filter Loss Reducer+2%Blocking agent.
In order to avoid adverse effects upon the rheology of the drilling fluid and to reduce the impairment of the fracture hydraulic conductivity, with the existing hydraulic tool, we use chemical materials as little as possible. Then a test was conducted to study the rheology comparing individuals with and without LCM. The result shown in Table 1 indicates that the LCM added in the drilling fluid does not significantly change the mud properties.
Table 1.
Comparison of rheology with or without LCM.
| Mud type | γ g/cm3 |
AV mPa s |
PV mPa s |
YP Pa |
FLAPI mL |
|
|---|---|---|---|---|---|---|
| SBM | With LCM | 1.30 | 30 | 22 | 8 | 8.4 |
| Without LCM | 1.32 | 34 | 25 | 9 | 8.6 | |
Determination of particle size distribution and concentration
Based on the literature review of existing research, the ideal LCM blend should contain coarse bridging agents to form a seal in the fracture and finer particles to reduce the permeability. The primary characteristics of the material used in lost circulation are particle size, range of sizes, shape (spheroidicity), concentration and resiliency22,23. So we choose a certain number of ground marble, ground nutshells, and graphite as additives added into common drilling fluid. In order to get a better treatment design of the LCM combination, we must select the optimal size distribution and concentration of the LCM, so these particles have been graded according to their sizes and an experiment have been conducted using a modified DL plugging apparatus on which a steel plate with slots (width = 2 mm; depth = 4 cm; length = 30 cm) can be integrated, which has been shown in Fig. 5. As shown in Table 2, these particles of ground marble are graded according to their sizes (from A to F) as well as ground nutshells (from A to D) and graphite (from A to E). As experiment starts, introduce drilling fluid with LCM combinations into the mud container of the DL plugging tester and integrate the plate on the bottom side of the tester. The initial pressure applied was set as 1 MPa. Note the fluid loss. When there is no fluid loss, we can assume that a plug has been formed in the fractures. Then we increase the pressure in increments of 0.1 MPa and keep every pressure point constant for 5 min. If there is no fluid loss still, increase the pressure to the next pressure point. If there is an occurrence of fluid loss, i.e. the plug breaks, we can note the pressure which can be taken as the maximum plugging pressure/plug breaking pressure and the total loss before plug breaks.
Fig. 5.
Modified DL plugging apparatus and steel plate with slots.
Table 2.
Measurement of LCM.
| Measurement | A | B | C | D | E | F |
|---|---|---|---|---|---|---|
| Mesh number | 10–20 | 20–40 | 20–60 | 60–80 | 80–100 | 100–120 |
| Size(mm) | 2.0–0.9 | 0.9–0.45 | 0.45–0.3 | 0.3–0.2 | 0.2–0.15 | 0.15–0.125 |
In this test, a 1.30 g/cm3 SBM was used as the carrier fluid for the LCM. The total concentration of particles and different LCM combinations were showed as follows:
1#: SBM + 1.0%A ground marble + 0.5%B, C, D, E, F ground marble;
2#: SBM + 1.0%A ground marble + 0.5%B, C, D ground nutshells;
3#: SBM + 1.0%A ground marble + 0.5%B, C, D, E, Fground marble + 0.5%B, C, D ground nutshells;
4#: SBM + 1.0%A ground marble + 0.5%B, C, D, E, F ground marble + 0.5%B, C, D ground nutshells + 0.5%B, C, D, E graphite.
From Figs. 6 and 7; Table 3, the best LCM combinations that can withstand higher pressures have been determined. So we have chosen 4# as LCM. The particle size distribution is shown in Fig. 8.
Fig. 6.
Different plugging effect of different LCM combinations.
Fig. 7.
Plug breaking pressure and total loss of different LCM combinations.
Table 3.
Plug breaking pressure and total loss of different LCM combinations.
| LCM combinations | Plug breaking pressure (MPa) | Total loss before plug breaks (mL) |
|---|---|---|
| 1# | 2.5 | 230 |
| 2# | 2.5 | 180 |
| 3# | 3.7 | 110 |
| 4# | 4.5 | 50 |
Fig. 8.
Distribution of the 4# LCM.
Experiment using hydraulic tool
As shown in Fig. 9, an experiment using the physical method for loss-prevention and plugging while drilling is conducted. The device includes a rotary shaft with adjustable speed from 0 ~ 120 r/min controlled by DZB100 Variable-frequency Drive, and a three phase asynchronous motor to provide the power for the rotary shaft. The device is completely suited for this experiment with the capability of overburden pressure up to 15 MPa, so it was completely satisfied for this experiment. The test procedures were set as follows: A down hole drilling process can be simulated by the following procedures: (1) The drilling fluid blended with designed LCM was injected by high pressure nitrogen gas into a 5 L container; (2) The drilling fluid flowed into the pressure cell through the shaft which acted as drilling string; (3) The rotation of the drilling string was simulated by rotating the rotary shaft at designed rotation rate; (4) The drilling fluids pressure can be controlled by a hydraulic choke as shown as number 9; (5) The drilling fluid can be collected through the outlet of the hydraulic choke; (6) The core was enclosed in the pressure cell; (7) the hydraulic tool was installed at the bottom of the shaft. Some parameters, such as velocity of drilling fluid, could not be gathered because no gauges were installed due to the economic constraints, such as testing cost and material requirements. As a result, this experiment could only provide qualitative information. In this test, the pressure difference between the wellbore and the core was set to 10 MPa to mimic the approximate differential pressure between the drilling fluid and the pore pressure in reservoir24.The same drilling fluid blended with LCM had been used in the experiments and the duration for each experiment was 5 min.
Fig. 9.
Schematic diagram of plugging test apparatus. 1 drilling fluid container, 2 rotary shaft, 3 three phase asynchronous motor with variable-frequency & adjustable-speed, 4 three phase asynchronous motor, 5 pressure cell,
6 hydraulic tool, 7 core with fracture, 8 lab jack, 9 returning pipe with an hydraulic choke, 10 manual regulating device.
Because there were few actual cores and the length was difficult to meet the experimental simulation requirements and the analysis and evaluation of the leakage plugging effect, we made artificial cores and reprocessed the cores according to the two types of crack inclination (transverse and longitudinal). Two groups were produced, with several cores in each group. The two sets of core samples are shown in Fig. 10a. The height of the cores was 40 cm, the inner diameter was 7.3 cm, and the outer diameter was 10 cm; the width of the cracks in both the transverse and longitudinal directions was 2 mm, and the depth of the cracks was 2.7 cm. The rock samples after the experiment are shown in Fig. 10b.
Fig. 10.
Cylindrical rock samples with fracture.
Results.
As shown in Fig. 11, the difference between the plugging effect with or without hydraulic tool is observed. Using common method, the LCM enters into the fracture passively while the drilling fluid flows up through the annulus to the surface, which causes unsatisfactory result. In Fig. 11a, the plug in the fracture is loose and the fracture is not completely sealed. However, in Fig. 11b and c, more LCM enters into the fracture and the fracture is totally plugged by tight plug when using this tool. Under a Zoom—stereo microscope, as shown in Fig. 11d and e, this result can be illustrated as well. Evidently, a good plugging result is obtained by using this hydraulic tool.
Fig. 11.
Comparison of plugging effect.
Numerical simulation
Drilling hydraulics is considered as the most important factor in drilling performance, especially when using this hydraulic tool. In order to achieve the goal making the maximum usage of this tool and ensuring the bit to drill at maximum efficiency, the percentage of flow lost through the tool is a very important parameter which will affect not only the plugging but also the bit performance, so we have written a program using Visual Basic (VB) to calculate this parameter based on hydraulic optimization. The proposed hydraulic parameters using in open hole have been shown in Table 4.
Table 4.
The proposed parameters using in open hole.
| Open Hole Diameter(mm) | Lateral Nozzles | Bit Nozzles | Percentage of flow through the tool (%) | ||
|---|---|---|---|---|---|
| Number | Diameter(mm) | Number | Diameter(mm) | ||
| 215.9 | 2 | 7 | 3 | 8 | 9.5 |
| 311.1 | 2 | 8 | 3 | 20 | 11.5 |
On the other hand, we have carried out a numerical simulation to validate if the proposed parameters are reasonable. To perform the Computational Fluid Dynamics (CFD) analysis, a modelization of the flow occurring around this tool has been done, by using the fluid simulation software Fluent.
Physical modeling
In order to simplify the research problem, the following assumptions are made based on the characteristics of the side nozzle and drill nozzle jet.
-
①
The jet is a steady flow, incompressible, and the medium is clear water.
-
②
The drill bit nozzle jet is unidirectional flow in the annulus after leaving the bottom of the well for a certain distance.
-
③
The well wall and the outer wall of the lateral hydraulic tool are smooth cylindrical surfaces, and the side nozzle is perpendicular to the well wall.
-
④
The drilling column does not rotate.
Due to the symmetry of the flow field, in order to save calculation time and improve calculation accuracy, 1/4 of the annulus is taken as the research object along the symmetry axis, and the finite element model is shown in Fig. 12.
Fig. 12.
Generated mesh for a sectioned volume.
Mathematical model
Let the turbulent kinetic energy per unit mass of fluid be 
, the turbulent dissipation rate of 
be 
, 
be the velocity vector, 
be the fluid density, 
be the fluid viscosity, and 
be the turbulent viscosity. Using the standard 
turbulence model, the governing equations of the flow are:
 |
1 |
 |
2 |
The equations for turbulent kinetic energy 
and turbulent dissipation rate 
are:
 |
3 |
 |
4 |
Among them:
 |
5 |
The model constants 
, 
, 
, 
and 
take the values:
= 1.44, 
= 1.92, 
= 0.09, 
= 1.0, 
= 1.3.
Boundary conditions
Side nozzle outlet boundary conditions: 
, 
;
Well wall and tool wall surface boundary conditions: 
;
Two symmetric profiles (XZ-plane and YZ-plane) boundary conditions: 
, 
;
Annulus upward return boundary conditions: 
, 
;
Annular air exit boundary conditions: take the pressure 
relative to the external flow field.
The design nozzle velocity 
= 50 m/s and the annular velocity was set to 0 m/s, 1 m/s and 2 m/s.The distance between the lateral nozzle and the well wall was 13 mm.
As shown in Fig. 13, the side-nozzle jet has no effect on the vast majority of the annulus, and its effect is limited to a very small area near the side nozzle. This is due to the fact that the annular velocity is much smaller than the jet velocity, and the impact and interference of the upward returning fluid on the side nozzle jet is small enough to make its axis deviate, so the annular velocity does not affect the impact force acting on the well wall. As shown in Fig. 14, the small change in the annular velocity has a small effect on the axial velocity of the side nozzle jet, and there is almost no difference between the three if the calculation error is not taken into account. After coming out of the side nozzle, the jet velocity has a small drop, and then gradually rise to half of the distance from the well wall to reach the maximum value, and then gradually decline, and finally decay rapidly to zero.
Fig. 13.
Flow pathlines and distribution.
Fig. 14.
Jet velocity attenuation.
Field test
In the Tahe Oilfield, the Permian basalt formation in this area has low pressure-bearing capacity, and the chance of leakage in drilling is high, even more than 60% in some blocks, which seriously affects the safe operation of wells. As shown in Fig. 15, the fractured formation has been encountered in drilling, which is about 5,500 m deep. Existing plugging techniques (e.g., chemical plugging) are time-consuming and prone to re-leakage in subsequent operations. We developed a new hydraulic tool for drilling 215.9 mm (8½in) boreholes and conducted field tests in several wells.
Fig. 15.
Core samples with fractures.
Test well 1
Test well section: 5651 ~ 5728 m; Test formation: Permian;
Drilling parameters: drilling pressure 120 ~ 140KN, displacement 30 L/s, pump pressure 20 ~ 22 MPa, speed 60 rpm.
Plugging formula: SBM+1.0%A ground marble+0.5%B, C, D, E, F ground marble+0.5%B, C, D ground nutshells+0.5%B, C, D, E graphite.
Application effect: (1) The tool is in the well for 38 h, pure drilling time is 20 h, and the overall structure of the tool is observed to be intact and no damage is seen after the well is discharged; (2) The maximum temperature inside the test well section is 115℃, and the new hydraulic tool is working normally; (3) No leakage occurs in this well, and compared with Comparison Well 1, the pressure-bearing capacity of the stratum in the test well is increased by 6.5 MPa, the specific comparison group is shown in Table 5.
Table 5.
Oilfield application comparison 1.
| Category | Depth (m) | Horizon | Fluid density (g/cm3) | Pressure-bearing capacity (MPa) |
|---|---|---|---|---|
| Test well 1 | 5651–5728 | Permian | 1.18 | 11 |
| Comparison Well 1 | 5650–5735 | Permian | 1.02 | 4.5 |
Test well 2
Test well section: 5095 ~ 5546 m; Test formation: Permian;
Drilling parameters: drilling pressure 120 ~ 140KN, displacement 32 L/s, pump pressure 24.5 ~ 27 MPa, speed 80 rpm.
Plugging formula: SBM + 1.0%A ground marble + 0.5%B, C, D, E, F ground marble + 0.5%B, C, D ground nutshells + 0.5%B, C, D, E graphite.
Application effect: (1) The tool is in the well for 129 h, pure drilling time is 110 h, and the overall structure of the tool is observed to be intact and no damage is seen after the well is discharged; (2) The maximum temperature inside the test well section is 109℃, and the new hydraulic tool is working normally; (3) No leakage occurs in this well, and compared with Comparison Well 2, the pressure-bearing capacity of the stratum in the test well is increased by 6.3 MPa, the specific comparison group is shown in Table 6.
Table 6.
Oilfield application comparison 2.
| Category | Depth (m) | Horizon | Fluid density(g/cm3) | Pressure-bearing capacity (MPa) |
|---|---|---|---|---|
| Test well 2 | 5095–5546 | Permian | 1.18 | 12.8 |
| Comparison Well 2 | 5101–5553 | Permian | 1.02 | 6.5 |
According to the field test effect, the new drilling hydraulic tool has reasonable structure, safe and reliable work, good plugging effect, and can significantly improve the pressure-bearing capacity of the well wall, which is suitable for extensive promotion and use.
Conclusion
This paper proposes a new method of plugging while drilling in the oilfield field, called physical method of plugging while drilling. It shoots drilling fluid containing plugging material to the well wall through a lateral nozzle installed on the side of the drill pipe to form a dense mud cake with near-zero permeability on the well wall that can withstand a certain pressure difference. Fluent numerical simulation shows that the upward return of fluid from the annulus has almost no effect on the nozzle jet. In practical application, using this new tool, the plugging effect is good, and at the same time can greatly improve the formation Pressure-bearing capacity. The physical method of plugging while drilling has its unique advantages in plugging leaks in permeable and fractured formations, and it is of great practical significance as it can improve the drilling speed and reduce the drilling cost in pore-permeable and fractured leakage formations.
Acknowledgements
This work was supported by the National Natural Science Foundation of China (90610013) and the Basic Subject Fund of Southwest Petroleum University, Chengdu.
Author contributions
The main manuscript was written by G.W and H.J, and reviewed by G.W and W.L.
Data availability
The date that support the findings of this study are available from the corresponding author upon reasonable request.
Declarations
Competing interests
The authors declare no competing interests.
Footnotes
Publisher’s note
Springer Nature remains neutral with regard to jurisdictional claims in published maps and institutional affiliations.
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Associated Data
This section collects any data citations, data availability statements, or supplementary materials included in this article.
Data Availability Statement
The date that support the findings of this study are available from the corresponding author upon reasonable request.