Enhancing formation breakdown pressure using optimized drilling fluid additives with preventive wellbore strengthening approach

Abstract

Accurate evaluation of formation fracture pressure is essential to prevent induced fracturing and mitigate drilling fluid losses, representing one of the major challenges in oil and gas well drilling operations. Conventionally, formation breakdown pressure (FBP) is regarded as an intrinsic rock property and is assumed to be independent of drilling fluid properties. However, the results of this study demonstrate that improving the sealing performance of the drilling fluid can significantly influence both the formation breakdown pressure and the fracture reopening pressure (FRP). Specifically, the purposeful application of drilling fluid additives, particularly lost circulation materials (LCMs), enhances the formation’s pressure-bearing capacity and effectively prevents lost circulation, consistent with the preventive wellbore strengthening approach. To investigate this effect, twenty-five drilling fluid formulations containing various combinations of LCM were prepared, and their fluid loss behavior and mud cake quality were evaluated using an API filter press apparatus. Based on these initial results, five drilling fluids exhibiting the most favorable performance were selected for further evaluation using a wellbore strengthening evaluation device. The results show that the drilling fluid formulated with the best LCM combination forms a thin, low-permeability mud cake and exhibits better sealing properties. As a result, increases of up to 42% in FBP and 95% in FRP were observed. These improvements highlight the important role of well-designed drilling fluids in preventing lost circulation. Furthermore, a qualitative agreement in experimental trends between API filter press data and wellbore strengthening test results indicates that API filter press measurements can serve as a rapid and cost‑effective preliminary screening method, helping to optimizing the experimental workflow.

Introduction

Lost circulation and its challenges

Lost circulation of drilling fluid is considered one of the most severe and costly problems that can occur during oil and gas well drilling operations. This phenomenon occurs when, under the action of a pressure differential between the wellbore and the formation, whole or part of the drilling fluid invades fractures, cracks, or voids within the geological strata and fails to return to the surface^1–3. It is estimated that nearly 20–25% of drilled wells worldwide experience lost circulation, with more than half of these cases resulting in complete losses^3–5. The economic and operational costs involved with the loss of drilling fluid are remarkably high. The waste of drilling fluid and the non-productive time required to control this issue increase the overall cost of well drilling by about 10–25%^6–8. Apart from direct costs, severe fluid losses could cause pressure-related instabilities, resulting in wellbore collapse, well blowouts, and other serious hazards⁹. Moreover, it has been estimated that almost 1.8 million barrels of drilling fluid invade the formation every year due to lost circulation. This quantity of fluid corresponds to the volume required for drilling approximately 600 wells; therefore, this figure clearly illustrates the resources wasted and highlights the need for preventive methods¹⁰. In the Middle East, more than 30% of wells drilled in fractured carbonate reservoirs experience significant fluid losses, and it is estimated that the time lost due to these losses accounts for roughly 50% of the total drilling time^3,11.

These statistics indicate that drilling fluid loss has become an imperative and unavoidable issue in the drilling industry, requiring the development of effective and accurate methods for its identification, prevention, and control^12–14. Lost circulation is generally classified into four categories based on the rate of fluid loss: seepage loss, with a rate of about 10–20 barrels per hour (bbl/h); partial loss, between 20 and 50 bbl/h; severe loss, from 50 to 150 bbl/h; and total loss, which occurs when the loss rate exceeds approximately 600 bbl/h. It should be noted that different references propose slightly different ranges for these categories; however, the classifications typically fall within these limits^15–18.

These complications also might be enhanced by the presence of high porosity and high permeability intervals, such as cavernous zones and dissolution channels, and by natural or induced fractures, which provide the required pathways for drilling fluid escape, hence making lost circulation a complex phenomenon that is strongly linked to the geological and operational features of each field. The processes of tectonic activity and dissolution generate natural fractures, which are open conduits within networks that drilling fluid can invade. Induced fractures, on the other hand, are created under excessive drilling fluid pressure or operational stresses, such as unwanted hydraulic fracturing, which enhances crack propagation and increases the intensity of fluid losses^19–21. In this regard, during drilling operations, accurate estimation of the allowable mud pressure window for preventing wellbore failure is of primary importance.

Wellbore breakdown pressure

The formation integrity test (FIT) is a useful tool for engineers to determine the maximum pressure the formation can withstand without damage or fracture initiation. In this test, hydraulic fractures are initiated by gradually increasing the pressure through fluid pumping^22–24, and often complemented by performing a “leak-off test (LOT)”. The procedure consists of a well shut-in, followed by a gradual, continuous increase in pressure by pumping drilling fluid, so that the formation’s mechanical response to the controlled loading can be monitored. The fracture initiation pressure (FIP), defined as the threshold for fracture onset, is identified at the point where the first evidence of fluid entering the rock matrix coincides with the onset of fracture initiation^25,26. In fact, FIP is the required pressure to create a small crack in the wellbore wall. It equals the necessary pressure to overcome the wellbore tangential stress and formation tensile strength²⁷.

When the applied pressure exceeds the formation strength limit, known as the formation breakdown pressure (FBP), fractures propagate and the formation is fully broken down. Once pumping operations are stopped, the pressure in the fracture gradually decreases until the fracture is completely closed. If, after this process, the pressure is increased again and the instant of fracture reopening is recorded, the corresponding pressure is defined as the fracture reopening pressure (FRP). Conversely, when injection is halted, the internal pressure within the fracture progressively decays, and the fracture path closes. This moment, which represents complete fracture closure, is characterized by the fracture closure pressure (FCP)^27,28. These parameters are directly influenced by the intrinsic rock properties and the geological conditions of the formation. A comprehensive and accurate analysis of data obtained from FBP, LOT, FRP, FCP, and FIT not only provides a tool for optimizing the mud weight program but also establishes a reliable framework for preventing unintended formation breakdown, minimizing fluid losses, and enhancing wellbore stability. Informed utilization of these indicators ensures the success and safety of drilling operations under the most complex geological conditions^29,30. The pressure behavior observed during this process, particularly in the Extended Leak Off Test (XLOT), provides a detailed picture of the formation’s mechanical strength.

As mentioned earlier, when the wellbore stresses exceed the hoop stress and the rock’s tensile strength, the crack will initiate. Since the formation tensile strength is negligible, FIP is a function of in-situ stresses that are effective on hoop stresses. Common theories for calculating FIP are generally developed for an intact wellbore with no cracks, leading to both overestimation and underestimation of FIP ^30–32. Based on the principles of continuum mechanics and Kirsch’s equations, Hubbert and Willis calculated FIP for a perfectly cylindrical vertical wellbore with an impermeable mud cake (Equ.1)³³.

1

where is fracture initiation pressure, is pore pressure, σ_h and σ_H are the minimum and maximum horizontal stresses, respectively. This equation is derived for a permeable formation by Haimson-Faihurst (Equ.2)³⁴.

2

where η is the poro-elastic parameter that indicates the magnitude of induced stress by fluid penetration. This parameter varies in the range of [0,1] for the non-penetrating mode to not-limited penetration.

It should be noted that the wellbore is rarely free of cracks, and microfractures occur due to drilling operations or tectonic conditions. Therefore, these equations will not be sufficiently accurate. Due to induced and natural micro-cracks, the continuum mechanics-based Kirsch’s equations are not valid, and FIP (or FPP for micro-cracks) will be obtained using fracture mechanics. Lee et al. (2004) studied the fracture propagation pressure for a well with microfractures (Equ. 3)³⁵. In this case, the FIP is a function of in-situ stresses, fracture toughness (K_Ic), and microfracture length (L).

3

Lee showed that FIP decreases with increasing horizontal stress anisotropy. On the other hand, it will improve with K_Ic increase.

Wellbore strengthening approach

Various methods and technologies have been proposed to improve wellbore integrity and increase the lost circulation pressure. Conventional bridging materials (LCMs) have been widely used to control fluid loss and strengthen the near‑wellbore region. In addition, several advanced approaches have been investigated, including gel‑based or resin‑based systems^4,8,9, novel elastomeric plugging materials³⁶, expandable profile liner technologies³⁷, and optimized cement‑based plugging formulations¹¹. These methods fall within the broader framework of wellbore strengthening (WBS), whose primary objective is to improve the formation’s pressure‑bearing capacity, thereby widening the safe drilling mud window^38,39.

In wellbore strengthening applications, it is important to distinguish between two related but operationally different mechanisms: “mud cake formation” during normal drilling operations and “fracture sealing associated with LCM particles”. In the context of wellbore strengthening, the former calls “preventive approach”, while the latter aligns with “remedial action”^28,40–43. In fact, mud cake deposition occurs as a natural consequence of filtration when drilling fluids circulate in the wellbore, leading to the accumulation of solid particles on the borehole wall and partial isolation of the formation from wellbore pressure^44,45. In contrast, fracture sealing typically refers to the intentional placement of LCMs to bridge and pack existing fractures to cure lost circulation^46–49.

However, these two mechanisms may act in a complementary manner rather than representing strictly separate operational scenarios^50–54. When drilling fluids containing LCM particles are circulated, filtration at the wellbore wall promotes mud cake formation, while some particles may simultaneously invade nearby microfractures or newly initiated fractures. These particles create a low permeability layer on the wellbore wall and inhibit the initiation of new fractures or the extension of microcracks by enhancing the mud cake’s plastering effect before formation breakdown in the drilling fluid, serving as a preventive approach^44,55. Consequently, both the improved sealing capacity of the mud cake and the partial bridging within fractures contribute to increasing the effective pressure‑bearing capacity of the near‑wellbore region.

Despite extensive research on WBS and the use of LCMs in drilling fluids, several aspects of the underlying strengthening mechanisms remain insufficiently quantified^38,56. In particular, limited experimental work has systematically linked filtration performance and mud cake characteristics to measurable improvements in FBP and FRP. Moreover, although API filtration tests are widely used to evaluate drilling fluid filtration properties, their potential as a preliminary indicator of wellbore strengthening performance has not been thoroughly investigated.

Therefore, the objective of the present study is to experimentally evaluate the effects of different LCM types, particle-size distributions, and concentrations on mud cake formation and wellbore strengthening performance. The experimental program and analysis are structured into two main parts: (a) assessing mud cake quality and filtrate volume reduction using an API filter press, and (b) evaluating the enhancement of formation breakdown and fracture reopening pressures using a wellbore strengthening apparatus, to investigate the relationship between filtration characteristics, mud cake quality, and the resulting enhancement in pressure-bearing capacity. By comparing filtration results with measured FBP and FRP values, this study aims to provide a clearer experimental understanding of the mechanisms through which optimized drilling fluid additives contribute to preventive wellbore strengthening and to assess the feasibility of using API filtration tests as a practical screening tool for designing effective drilling fluid formulations.

Materials

Base fluid

To evaluate the effects of different LCMs on laboratory results and to eliminate the influence of other variables, a single base fluid was used and held constant across all tests. Based on data from drilled wells in Iran, a water-based polymer mud with the lowest reported lost circulation in oil and gas wells was selected as the base drilling fluid for the experiments. The rheological properties of this fluid, measured using a FANN 35 viscometer, together with its composition, are presented in Table 1.

Table 1.

Formulation and rheological properties of the base fluid used.

Base Drilling Fluid
Formulation		Rheological/ Filtration properties
Tap water	350 mL	Apparent Viscosity	17.5 cP
Caustic soda (NaOH)	0.5 g	Plastic Viscosity	8 cP
Soda ash (Na₂CO₃)	0.5 g	Yield Point	19 lb/100 ft2
Starch	10 g	Gel Strength (10 min)	7.9 lb/100 ft2
PAC-LV	4 g	Mud Weight	64 PCF
Xanthan gum	0.5 g	API Filter Press Fluid Loss	8.75 ml
Calcium carbonate	5 g	API Filter cake thickness	1 (1/32’’)

Core samples

As will be discussed later in the Methods section, one of the devices used in this study to evaluate the performance of LCM particles is the Wellbore Strengthening Evaluation Apparatus. Hence, the procedure for preparing these cores is described in this section. In rock mechanics experimental studies, the recommended specimen height is twice the diameter to avoid stress concentration in cylindrical samples^57–59. Therefore, the cylindrical core samples used in this paper have a diameter of 4 inches and a height of 8 inches. To eliminate the effects of heterogeneity and anisotropy in core properties, man-made concrete specimens were used as core samples, which is a common practice in such studies. Since the fracture pressures of these homogeneous samples are the same, the effects of different LCM types on fracture pressure can be compared^60–62. Synthetic concrete cores have also been used to simulate the behavior of impermeable or very low-permeable formations (such as shales)¹⁵. In addition, preparing a large number of real samples, each 8 inches long, under homogeneous conditions is almost impossible.

To prepare concrete cores with physical and mechanical properties similar to those of the real rock, the final mixing design was obtained after several attempts at fabrication and measurement of the properties of different samples (with trial and error). For preparing the concrete samples, approximately 60 L of cement slurry were mixed and used to cast 27 cylindrical molds with a diameter of 101 mm (4 inches) and a height of 202 mm (8 inches). About 44.164 kg of sand passing through sieve No. 8 was used. The use of fine-grained sand in these samples improves the rock’s permeability and porosity and, hence, the final samples will be as similar as possible to the real rock⁶³. After initially moistening the sand with one-third of the mixing water, the remaining water and cement were added to the container and thoroughly mixed. To improve workability and avoid casting problems, 27 g of a polycarboxylate ether-based superplasticizer was used, which enhances the dispersion of cement particles and promotes better hydration.

The concrete was poured into the molds in three layers, and each layer was compacted using a vibrating table to remove entrapped air. The top surface of the specimens was then leveled with a trowel, and the samples were kept under moist burlap at ambient temperature for 24 h. After this period, the molds were removed and, as shown in Fig. 1, the specimens were placed in a lime-saturated water bath for 28 days of curing to ensure completion of the hydration process and development of the final concrete strength.

Fig. 1.

Specimens removed from the molds after 24 h (A), and placement of the specimens in a lime-saturated water bath for 28 days (B).

The physical and mechanical properties of concrete samples were measured using standard methods, as presented in Table 2. In this study, porosity and permeability of the concrete samples were measured in the R-CAL section of the Research Institute of Petroleum Industry (RIPI), and the mechanical properties were measured in the Geomechanics Laboratory of Amirkabir University of Technology. These values fall within the range reported for relatively low‑permeability reservoir formations, including both consolidated sandstones and some tight or low‑permeability carbonate rocks.

Table 2.

The physical and mechanical properties of concrete samples.

Parameter	Value	Test Method (Apparatus)
Porosity	20.06%	Helium porosity apparatus
Permeability	0.1 mD	Automated gas permeameter
Young’s modulus	316,000 psi (2.18 GPa)	The CSIRO autonomous Triaxial cell
Poisson’s ratio	0.07	The CSIRO autonomous Triaxial cell
UCS	5380 psi (37 MPa)	The CSIRO autonomous Triaxial cell
Tensile strength	700 psi (4.8 MPa)	Brazilian test
Toughness	125 psi m1/2 (0.87 MPa. m1/2)	Semi-circular bend test

For the final preparation of the artificial concrete cores before testing, it was necessary to ensure that the end faces were completely flat and free of irregularities to avoid stress concentration. To this end, the top and bottom surfaces of the cylindrical specimens were cut and ground to a smooth finish.

After leveling the specimen ends, a 0.5-inch-diameter hole was drilled through the center of each core to simulate a drilled wellbore. The borehole was made using a VINCI coring machine equipped with a 0.5-inch-diameter, 8-inch-long bit. The final prepared specimen is shown in Fig. 2.

Fig. 2.

Concrete specimen after preparation.

Types of LCMs

To investigate the role of LCMs in wellbore strengthening, four common LCM types used in drilling operations in Iran were supplied by the Research Institute of Petroleum Industry (RIPI) and employed in this study. These materials included RIPI LCM, granular calcium carbonate, sized oyster shell, and sized Quick Seal, each prepared in three particle size ranges: fine, medium, and coarse, as shown in Fig. 3. To determine the proper particle size distribution (PSD), a sieve shaker equipped with a set of standard sieves was used. In this procedure, 50 g of each sample was sieved for 10 min. For fine RIPI LCM samples, sieve mesh sizes corresponding to 354–1000 μm were used; for medium samples, 1410–2830 μm; and for coarse samples, 2830–5660 μm. For granular calcium carbonate, the mesh sizes were 250–707 μm for fine, 1000–1680 μm for medium, and 1000–2000 μm for coarse grades. For oyster shell, sieves corresponding to 4000–9510 μm were used, and for Quick Seal, sieves corresponding to 1000–2830 μm were used. Finally, the mass of particles retained on each sieve was carefully measured and recorded.

Fig. 3.

Types of LCMs used in this study.

Figure 4(A) shows the PSD curve of fine granular calcium carbonate, Fig. 4(B) shows the distribution of medium granular calcium carbonate, and Fig. 4(C) shows the distribution of coarse granular calcium carbonate. Figure 5(A) presents the PSD of fine RIPI LCM, Fig. 5(B) that of medium RIPI LCM, and Fig. 5(C) that of coarse RIPI LCM. Figure 6(A) illustrates the PSD of Quick Seal, and Fig. 6(B) shows the PSD of oyster shell.

Fig. 4.

Particle size distribution of calcium carbonate: (A) fine grade, (B) medium grade, (C) coarse grade.

Fig. 5.

Particle size distribution of RIPI LCM: (A) fine grade, (B) medium grade, (C) coarse grade.

Fig. 6.

Particle size distribution of (A) Quick Seal and (B) oyster shell.

One of the key requirements for an effective LCM is that it should minimize any alteration of the drilling fluid’s rheological properties. Therefore, the rheological properties of the fluids after adding the different LCM types were evaluated and confirmed to be acceptable.

As mentioned before, in our experimental setup the drilled borehole diameter is 0.5 inches, corresponding to approximately 12,700 μm. Even the coarsest particles present in the studied LCMs—such as those shown in Figs. 4, 5 and 6—fall far below this dimensional threshold. The largest particles observed in the PSD plots are on the order of a few thousand micrometers (from 1400 μm to 4700 μm), which remain at least one order of magnitude smaller than the borehole diameter. Therefore, they are physically incapable of forming a bridge at the borehole entrance.

Methods and experimental apparatus

In this study, a series of experiments was designed and conducted to evaluate the performance of LCM particles in improving the wall-building properties of the drilling fluid and increasing the formation breakdown pressure. The following subsections describe these tests in detail.

• Low-pressure, low-temperature drilling fluid filtration apparatus (API Filter Press)

In the filtration test, in accordance with API standard procedure, after inserting the filter paper and applying a pressure of 100 psi, the fluid passes through the filter medium and is collected in a graduated cylinder (Fig. 7). After 30 min, the volume of filtrate is measured, and the quality of the filter cake is examined. The higher the filtrate volume, the thicker the mud cake becomes, leading to more severe drilling problems and greater formation damage. A drilling fluid that provides good wall-building properties and forms a mud cake with low thickness and permeability is considered desirable⁶¹.

Fig. 7.

API filter press apparatus.

• Wellbore strengthening evaluation apparatus

The wellbore strengthening evaluation apparatus (Fig. 8) is a triaxial loading system that simulates in-situ stresses. Using separate pumps, the device independently applies confining stress, pore pressure, and axial stress to the specimen. After the core is placed inside the dedicated cell, it is sealed with a rubber sleeve and two polyethylene rings at the top and bottom to prevent any fluid leakage. The apparatus is equipped with a high-pressure core holder fabricated from 316 L stainless steel. The specimens are cylindrical with a 0.5-inch central bore, representing the wellbore within the formation. The relatively large sample dimensions (4-inch diameter and 8-inch height) were selected to minimize boundary effects. With proper flowline design, it is possible to inject various drilling fluids and their additives. After preparation, the drilling fluid is pumped through the central bore and circulated to form a mud cake layer on the borehole wall. The outlet line is then closed, and the internal “wellbore” pressure is gradually increased until the specimen fails. After a shut-in period, a second injection cycle is performed to investigate fracture reopening behavior under the applied conditions. This system enables the determination of the rock’s ultimate strength and breakdown pressure. The apparatus is equipped with two pressure transducers that simultaneously record the inlet and outlet fluid pressures, while the axial pressure is measured using an analog gauge. Test data are captured by a data acquisition system and presented both numerically and as graphical plots. This capability allows real-time monitoring of the process and precise identification of pressure variations and the exact moment of specimen breakdown⁶⁴.

Fig. 8.

View of the formation strengthening evaluation apparatus⁶⁴.

In this study, with an axial stress of 1958 psi (13.5 MPa) and a confining (lateral) stress of 580 psi (4 MPa) applied, the rock breakdown process is first examined in the presence of water. Subsequently, to evaluate the effect of solid particles in the drilling fluid, a polymer-based mud is employed. In the following stages, the role of lost-circulation control materials, such as calcium carbonate and RIPI LCM, in controlling and improving the loss process is carefully investigated. Furthermore, the influence of PSD and different concentrations of these materials on the course of formation strengthening and reinforcement is comprehensively evaluated.

Results and discussion

Filter press test results: evaluation of mud cake quality

The API filter press measures the filtrate volume expelled from the drilling fluid, thereby enabling investigation of fluid loss and the characteristics of the filter cake formed in the presence of different LCM particles. The results of this test showed that LCMs act as pore-plugging agents within the filter cake and, by improving the wall-building properties of the mud cake, lead to a thinner, less permeable filter cake, ultimately reducing fluid loss.

Figure 9 presents a mechanistic interpretation linking fluid-loss behavior to the structure and properties of the mud cake and explaining how LCMs act as pore-plugging agents within the filter cake. As shown in this figure, increasing the concentration of RIPI LCM enhances the drilling fluid’s wall-building properties and promotes the formation of a less permeable mud cake, ultimately reducing fluid loss. However, the percentage of performance improvement varies across concentrations and particle size distributions. According to the results, the medium-size fraction of this LCM at a concentration of 15 pounds per barrel (ppb) has a greater effect on filtrate volume (14.3% reduction) than the other two size ranges. Therefore, selecting the optimal particle size and concentration is crucial to the LCM’s performance in improving mud cake wall-building properties and reducing the likelihood of fluid invasion into the wellbore wall.

Fig. 9.

Variation of filtrate volume as a function of concentration and particle size of RIPI LCM.

As shown in Fig. 10, the addition of calcium carbonate LCM to the drilling fluid reduces fluid invasion and filtrate volume, indicating its influence on mud cake quality. However, its effectiveness is lower than that of RIPI LCM. This plot demonstrates that LCM type also affects LCM preventive performance in lost circulation control. This point is clearly illustrated in Fig. 11 as well. According to this figure, although adding both Oyster shell and Quick Seal LCMs reduces filtrate volume, their performance is inferior to that of the RIPI LCM.

Fig. 10.

Variation of filtrate volume as a function of concentration and particle size of calcium carbonate.

Fig. 11.

Variation of filtrate volume as a function of concentration for oyster shell and Quick Seal.

By comparing results from adding different types of lost circulation control materials, it is observed that, among the evaluated options, the RIPI additive with a medium particle size at a concentration of 15 lb/bbl yields the greatest reduction in filtrate volume. This favorable performance in filtrate reduction, which is more effective than that of other samples such as calcium carbonate and Quick Seal, indicates the high efficiency of this material in forming an effective mud cake, enhancing wall-building, and controlling the drilling fluid’s filtrate volume.

These findings become more meaningful when interpreted alongside the results shown in Fig. 12. As illustrated, adding LCM particles to the drilling fluid increases mud cake thickness, thereby improving its wall-building properties. This reflects the concept of wellbore strengthening through a preventive approach: before fracture initiation and in the presence of a permeable formation, it is possible to form a lower-permeability mud cake with LCM particles, thereby preventing lost circulation. It should be noted, however, that excessive mud cake thickness can itself cause operational problems, such as tight hole conditions and differential sticking. Therefore, based on the results shown in this figure, RIPI LCMs in fine and medium grades—which significantly increase mud cake thickness relative to the base fluid—are not ideal options. By contrast, coarse RIPI LCM demonstrates better performance, as it provides an acceptable reduction in filtrate volume at different concentrations while forming a mud cake that is considerably thinner than that produced by the medium-grade RIPI LCM. Since one of the key indicators of mud cake quality is the combination of low thickness and adequate impermeability, it can be stated that coarse RIPI LCM simultaneously satisfies both requirements. It is also worth noting that the simultaneous use of blended LCM systems may be a promising research topic for our future studies.

Fig. 12.

Mud cake thickness in filter press tests in the presence of different LCMs.

Results of wellbore strengthening evaluation apparatus tests

As discussed in the previous section, in the first stage of this study, 25 drilling fluid samples containing various combinations of LCM were formulated, and their fluid loss behavior and mud cake quality were evaluated using an API filter press apparatus. In the second stage, five drilling fluids exhibiting the most favorable performance were selected for a more detailed investigation using a wellbore strengthening evaluation device under downhole conditions.

The experiments were designed and selected to evaluate the influence of LCM type and LCM particle size on the wellbore strengthening process and to address whether there is a meaningful correlation between the results of the API filter press tests and those of the WBS evaluation apparatus. Accordingly, the breakdown pressure of the core samples was investigated under six different conditions:

• Evaluation of core breakdown pressure with water.

• Evaluation of core breakdown pressure with the base drilling fluid.

• Evaluation of core breakdown pressure with base fluid containing 15 ppb CaCO₃ Fine.

• Evaluation of core breakdown pressure with base fluid containing 15 ppb CaCO₃ Coarse.

• Evaluation of core breakdown pressure with base fluid containing 15 ppb Quick Seal.

• Evaluation of core breakdown pressure with base fluid containing 15 ppb RIPI LCM Coarse.

First test: tap water

In the first stage of testing, tap water was used as the drilling fluid. A 700 cc volume of this fluid was transferred into the fluid chamber, and after applying axial and lateral stresses of 1957 psi and 652.7 psi, respectively, the test was conducted. Based on the results obtained, the rock sample’s formation breakdown pressure was calculated to be 1562 psi, which is consistent with previous studies⁶⁴. At the moment the FBP was observed, the fr7acture immediately propagated to the specimen boundaries, causing a sudden increase in the confining pressure response on the plot (highlighted zone in Fig. 13). Immediately after completion of the first cycle, the second injection cycle was initiated. Due to the fracture created in the previous stage, once the fluid pressure reached the lateral (confining) pressure, the fracture reopening pressure could not be clearly recorded. In fact, in the absence of solid particles in the fluid, the fracture reopening pressure is considered to be equal to the confining pressure.

Fig. 13.

Pressure–time plot for Test No. 1: concrete specimen fractured with tap water.

Second test: base drilling mud

In the second test, a polymer-based drilling fluid without any LCM was used to evaluate the drilling mud’s ability to form a filter cake and to improve the specimen’s breakdown pressure. A 700 cc volume of this fluid, prepared according to the procedure described in the previous sections, was injected into the cell. Based on the results, the FBP was 2560 psi, representing a 63% increase over the water test. This experiment clearly demonstrates the effect of the drilling fluid in forming a layer on the wellbore wall and enhancing preventive WBS. The second injection cycle was initiated after a 10-minute shut-in period to allow sufficient time for fracture healing and activation of the drilling fluid’s self healing properties^10,65. In the second cycle, the fracture reopening pressure was measured as 1590 psi. Due to the dominance of axial stress over lateral stress (normal faulting stress regime), the induced fracture propagated vertically within the specimen. The variation in wellbore fluid pressure over time is shown in Fig. 14, and the resulting vertical fracture induced by the polymer mud is illustrated in Fig. 15.

Fig. 14.

Pressure–time plot for Test No. 2: concrete specimen fractured with polymer-based drilling fluid.

Fig. 15.

Images of the vertical fracture created in the concrete specimen (A) and Mud cake on the wellbore (B).

Third test: polymer drilling mud with fine calcium carbonate

Based on the results of the first two tests, the importance of the drilling fluid in improving wellbore wall building was confirmed. To answer whether an LCM can further increase the rock breakdown pressure relative to the base fluid and enhance wellbore strengthening, Tests 3 to 7 were designed and conducted. In the third test, the base drilling fluid contained 15 g (equivalent to 15 lb/bbl) of fine-grade calcium carbonate. As shown in Fig. 16, the breakdown pressure of the rock in the presence of fine calcium carbonate at a concentration of 15 ppb was 2680 psi, and the fracture reopening pressure was 1987 psi, corresponding to increases of 5% and 25%, respectively, compared with the base mud. These results clearly indicate that the presence of LCM particles in the drilling fluid leads to the formation of a mud cake layer that is less permeable and more resistant than that formed by the base fluid alone. Consequently, the rock’s pressure-bearing capacity is enhanced, and the FBP is improved. In addition, the invasion of LCM particles into the fracture and the formation of an immobile mass within the fracture contribute to the observed increase in FRP.

Fig. 16.

Pressure–time plot for Test No. 3: concrete specimen fractured with fine calcium carbonate.

Fourth test: polymer drilling mud with coarse calcium carbonate

In the fourth test, to more accurately and comprehensively assess the impact of LCM particles on the formation breakdown gradient, the previous experiment was repeated under the same conditions, except that coarse-grained calcium carbonate was used instead of the fine grade. Coarse calcium carbonate is one of the most widely used lost circulation materials and, due to its acid solubility, is particularly applicable in Iranian reservoirs. The amount used was again 15 g (15 lb/bbl).

The results showed that the FBP increased to 3310 psi, and the fracture reopening pressure reached 2628 psi, corresponding to improvements of 29% and 65%, respectively, compared with the base mud (Fig. 17). The superior performance of coarse calcium carbonate over fine calcium carbonate in this test is consistent with the filtration test results presented in the previous section, further confirming the reliability of the findings.

Fig. 17.

Pressure–time plot for Test No. 4: concrete specimen fractured with coarse calcium carbonate.

Fifth test: base drilling mud with Quick Seal

In the filtration experiments (API Filter Press) presented in the previous section, it was observed that Quick Seal at 15 ppb exhibited better wall-building and sealing performance than coarse calcium carbonate at the same concentration, since the reduction in filtrate volume in the presence of Quick Seal (8.6%) was greater than that with calcium carbonate (7.4%).

Accordingly, Test No. 5 was designed to evaluate the degree of agreement between the API filter press results and those obtained from the WBS apparatus, using Quick Seal at a concentration of 15 g (equivalent to 15 lb/bbl). As shown in Fig. 18, the FBP was recorded as 3420 psi, and the fracture reopening pressure was 2773 psi. These results indicate that, compared with coarse calcium carbonate, FBP and FRP have improved by approximately 4% and 5%, respectively.

Fig. 18.

Pressure–time plot for Test No. 5: concrete specimen fractured with Quick Seal.

Sixth test: base drilling mud containing coarse RIPI LCM at 15 g

In the sixth test, the polymer-based drilling fluid was again prepared in a volume of 700 cc as in the previous stages, and 15 g of coarse-size RIPI particles were added. Based on the filter press results, it was initially expected that this test would exhibit the greatest improvement in core breakdown pressure, and the results confirmed this expectation.

According to the plots in Fig. 19, using RIPI LCM Coarse at 15 ppb, the FBP was 3644 psi and the fracture reopening pressure was 3100 psi. These values correspond to a 42% increase in rock breakdown pressure and a 95% increase in fracture reopening pressure relative to the base mud. This clearly demonstrates the impact of LCM presence on wellbore strengthening in both preventive and corrective approaches.

Fig. 19.

Pressure–time plot for Test No. 6: core breakdown with coarse RIPI LCM.

Figure 20 presents the results of the tests conducted with the WBS evaluation apparatus in the presence of different LCM types. As can be seen, LCMs can modify the formation breakdown pressure and effectively act as LPMs, thereby preventing lost circulation. These results show that mud cake formation on the wellbore wall effectively prevents fracture initiation, consistent with the widely accepted wellbore strengthening mechanism reported in the literature^64–66.

Fig. 20.

Comparison of measured FBP and FRP in the presence of different LCMs.

It is important to state that the intrinsic fracture pressure of a formation is fundamentally governed by the mechanical properties of the rock and the in-situ stress condition. Therefore, the addition of LCMs does not change the inherent fracture pressure of the formation rock. Instead, the observed increases in formation breakdown pressure and fracture reopening pressure reflect an enhanced effective pressure-bearing capacity of the near-wellbore region, resulting from improved fracture sealing, strengthened mud cake, and reduced fluid penetration into the fracture tips. As mentioned earlier, Eq. 1 indicates that fluid influx into the formation increases pore pressure, thereby reducing effective tangential stress. As a result, FIP decreases. In other words, according to the results of Fig. 20, forming a low-permeability mud cake effectively inhibits drilling fluid invasion into the wellbore wall, thereby constraining pore pressure elevation in the near-wellbore region. Consequently, the formation fracture pressure increases. These results highlight the importance of LCM particle characteristics and filtration performance in governing the efficiency of preventive and remedial wellbore-strengthening mechanisms.

The experimental results indicate a clear experimental trend between filtration performance and wellbore strengthening behavior. Drilling fluid formulations that exhibited lower filtration volumes in the API filter press tests generally resulted in improved wellbore-strengthening performance, as reflected by higher formation breakdown and fracture reopening pressures. Accordingly, the combined interpretation of the API filter press results and the wellbore strengthening experiments suggests that reducing fluid invasion into the formation, and consequently preventing pore pressure buildup, is the primary mechanism responsible for the observed increase in the apparent formation breakdown pressure. This qualitative agreement suggests that filtration characteristics and the resulting mud cake properties play an important role in improving fracture sealing efficiency. Therefore, API filtration tests may serve as a practical preliminary screening tool for evaluating drilling fluid formulations with enhanced wellbore strengthening potential.

Conclusions

Lost circulation is a key problem in drilling operation, leading to significant NPT and increases in operational costs. One of the most effective techniques for addressing the problem involves strengthening the formation prior to the loss process. The purpose of this research is not to present a novel LCM technology, but rather to experimentally evaluate how an optimized LCM composition influences FBP and FRP quantitatively. In addition, the study explores the potential relationship between drilling fluid filtration behavior and the effectiveness of wellbore strengthening (WBS).

To achieve the project’s objectives, a multi-stage experimental program was employed. Initially, API filter press tests were performed on drilling fluid formulations containing different LCM types, particle size distributions (PSD), and concentrations in order to evaluate their effects on filtration volume and mud cake characteristics. Having identified optimal LCM compositions from this set, WBS tests were conducted using the WBS Evaluation Apparatus under near-wellbore stress conditions. Main findings are summarized below:

• The experimental results demonstrate that a significant reduction in filtration volume is associated with the formation of a thinner, lower-permeability, and mechanically more stable mud cake. Such mud cakes contribute directly to improved wellbore strengthening performance.

• The type, PSD, and concentration of LCMs strongly influence mud cake quality and fracture sealing efficiency. Properly designed LCM blends were shown to act effectively as lost prevention materials (LPMs), improving both breakdown resistance and fracture sealing behavior.

• The WBS experiments revealed that optimized LCM formulations can substantially increase the pressure-bearing capacity of the formation. In this study, the formation breakdown pressure (FBP) increased by up to 42%, while the fracture reopening pressure (FRP) increased by up to 95%, highlighting the effectiveness of preventive wellbore strengthening.

• The simultaneous increase in FBP and FRP, together with the considerable reduction in filtration volume, provides macroscopic experimental evidence supporting the proposed plastering and sealing mechanisms. These findings suggest that improved mud cake integrity, rather than mineralogical effects, is the dominant factor controlling wellbore strengthening in the tested system.

• A qualitative agreement was observed between the results of API filter press tests and those obtained from the WBS Evaluation Apparatus. This agreement indicates that filtration characteristics and mud cake properties play an important role in fracture sealing efficiency, and suggests that API filtration tests can serve as a practical and cost-effective preliminary screening tool for identifying drilling fluid formulations with enhanced WBS potential.

Overall, the results of this study show the importance of improving drilling fluid properties and designing the PSD of LCMs to create an effective sealing barrier in the near-wellbore area. This improvement reduces near-fracture permeability, limits fluid invasion, and greatly boosts formation pressure tolerance. The findings provide a clear experimental basis for integrating API filtration testing and WBS evaluation into the structured design of preventive wellbore strengthening strategies.

Limitations and future works

• Cement-based cores were used for conducting the tests in this study. The choice of such cores was primarily intended to achieve high repeatability and consistency in the physical and mechanical characteristics of all test specimens. However, it must be kept in mind that such cement-based cores do not resemble most natural rocks. It is suggested that, in future studies, the performance of different materials across different types of natural cores should be evaluated to validate their performance under more complex geological conditions.

• In this study, only water-based drilling fluids were used in the experiments. It is recommended that future studies also evaluate oil-based and synthetic-based drilling fluids to investigate their potential effects on wellbore strengthening and breakdown pressure.

• Although the plastering effect inferred in this study is supported by the observed reductions in filtration volume and the corresponding increases in FBP and FRP, detailed microstructural characterization of the mud cake (e.g., SEM imaging or permeability measurements) could provide additional insight into the pore-scale sealing mechanisms. Such analyses are recommended for future investigations to further elucidate the microstructural evolution of mud cakes formed by optimized LCM systems.

• Future work could evaluate the combinations of different particle size of LCMs (fine, medium, and coarse) to better understand their role in enhancing the apparent breakdown pressure.

Abbreviations

FBP

Formation Breakdown Pressure

FCP

Fracture Closure Pressure

FIP

Fracture Initiation Pressure

FIT

Formation Integrity Test

FRP

Fracture Reopening Pressure

LCM

Lost Circulation Material

LOT

Leak Of Test

LPM

Lost Prevention Material

ppb

Pounds per barrel (lb/bbl)

PSD

Particle Size Distribution

WBS

Wellbore Strengthening

XLOT

Extended Leak Off Test

Author contributions

Ahmadreza Abdsahi wrote the main manuscript text and designed graphical results, tables, and outputs. Amir Farnia Shalmani prepared the core samples, performed the main laboratory tests, evaluated the results and wrote the manuscript text. Dr. Mohammad Javad Ameri defined the main idea, supervised the whole project, and validated experimental data as the corresponding author. Dr. Seyed Morteza Mirabbasi revised the manuscript technically, validated experimental data and evaluated the results and discussion as the corresponding author. Dr. Alireza Nasiri provided support for the experimental materials, apparatus, and guidelines.

Funding

This research did not receive funding.

Data availability

The datasets used and analyzed during the current study are available from the corresponding author on reasonable request.

Declarations

Competing interests

The authors declare no competing interests.