Nanoparticles (NPs) are currently being studied as a drilling fluid additives especially for application in very low-permeability formations such as shales. Application for conventional permeable rocks is still a subject of discussion. In this work, successful application of in-house prepared iron-based nanoparticles (NP1) and calcium-based nanoparticles (NP2) to reduce filtration loss in conventional permeable media has been experimentally quantified for oil-based mud (OBM) utilizing the high-pressure high-temperature (HPHT) filter press at 500 psi and 250°F. Ceramic discs were used as the filtration medium in this application to test the performance of the NPs and glide graphite as a conventional lost circulation material (LCM) for porous media. These experiments were carried out in the presence of graphite at low and high concentrations. Filtration reduction trends were observed and a reduction up to 76% was achieved. API filter press was also used to investigate the behavior of NPs and graphite under low pressure and temperature conditions (LPLT). NP1 and NP2 at the two graphite concentrations showed a reduction up to 100%. NP1 gave higher reduction especially at low concentrations under HPHT conditions, while NP2 yielded significant reduction at high concentration under HPHT. These trends were reversed under LPLT, giving a new insight on NPs performance under different pressure and temperature conditions. At HPHT and LPLT, the effect of graphite as a filtrate reduction agent is less significant as the NPs concentration increases. High graphite level had a positive effect on filtration reduction in combination with NP1 at HPHT and LPLT. This was not the case for the blends containing NP2 at HPHT. The effect of NPs and graphite was tested individually showing a different performance compared to the combination of them. Impact of NPs and graphite on rheology was also quantified allowing identification of the more sensitive parameters in the blends. It is concluded from this study that blends containing NPs and graphite can be successfully implemented in OBM to minimize formation damage in porous media.

Lost circulation prevention or mitigation is a major challenge while drilling. Conventional lost circulation materials (LCM) are often implemented to prevent/cure seepage or partial losses. When it comes to severe losses, often caused by larger fracture sizes, special treatments are being applied. Curing severe losses with specialized treatments requires more time because some treatments can't be applied in the presence of downhole tools, where special equipment and procedures are required. In addition, polymer and cement treatments require time to be activated or cured after being pumped. Evaluating the performance of LCM and their effectiveness in sealing wide fractures is required in conjunction with an optimized LCM combination to ensure their ability in curing losses. This paper presents investigations about the possibility of sealing relatively large fracture using conventional LCM instead of the other approaches such as cement or hydratable LCM pills. Two specifically developed apparatuses were used to optimize LCM combination and investigate their ability in sealing wide fractures at different pressures. A set of tapered slots that simulate sealable fracture widths with different fracture aperture (2.5 – 5 mm) and tip sizes (1-2 mm) were used in this study. A total of 160 tests were conducted to optimize LCM combinations and concentrations in addition to 30 tests to evaluate the integrity of the seal formed under elevated pressures with apparatus capability of up to 10,000 psi (69 MPa) fracture differential pressure. The effects of varying LCM's type, concentration, particle size distribution and fracture width were studied with respect to differential pressure and fluid loss. The results showed that LCM's that have irregularity in particles shapes and a degree of deformability such as nut shells are capable of sealing wide fractures when used individually or in combination with other LCM's. In addition, a strong relationship between fluid loss values and the seal integrity was observed, i.e. lower fluid loss, gave higher sealing efficiency. There is a good potential for conventional LCM's to be reconsidered as a corrective approach for partial or severe losses when the proper LCM's size, type and concentration are selected for a wider range of fracture widths. Curing losses using conventional LCM's for a wider range of fractures widths is advantageous since it can cut time and cost compared to current practices.

Lost circulation caused by low fracture gradients is the cause of many drilling related problems. Typically the operational practice when lost circulation occurs is to add loss circulation materials (LCM) to stop mud from flowing into the formations. To improve the treatment for lost circulation caused by low fracture gradients, especially designed materials in mud system are used to seal the induced fractures around the wellbore. This operation is in the literature referred to as wellbore strengthening that has been found to be a very effective in cutting Non-Productive Time (NPT) when drilling deep offshore wells. Size, type and geometry of sealing materials are debating issues when different techniques are applied. Also the phenomenon is not truly understood when these techniques applied in different sedimentary basins. This paper presents development and simulation results of a three-dimensional Finite-Element Model (FEM) for investigating wellbore strengthening mechanism. This study also describes a procedure for designing Particle Size Distribution (PSD) in field applications. To better understand the numerical results, the paper also reviews the connection between Leak of Tests (LOTs) and wellbore hoop stress and how these LOTs can mislead in fracture gradient determination. A comprehensive field database was collected from different sedimentary basins for this study. Results demonstrate that the maximum attainable wellbore pressure achieved by wellbore strengthening is strongly controlled by stress anisotropy. Results also show that Particle Size Distribution (PSD) of wellbore strengthening should be designed in order to seal the fractures close to the mouth and at fracture tip. This will result both in maximizing hoop stress restoration and tip-screening effects. In addition this model is able to show the exact fracture geometry formed around the wellbore that will help to optimize the sealing materials design in wellbore strengthening pills. To support numerical modeling results, near wellbore fracture lab experiments on Sandstone and Dolomite samples were also presented. Laboratory experiments results reveal importance of rock permeability, tensile strength and fluid leak-off in wellbore strengthening applications.

Drilling operations of both conventional and unconventional oil and gas accumulations are becoming more challenging especially in deep-water operations. Due to the narrow mud weight window in offshore wells, a proper wellbore stability analysis is required for a cost-effective execution. Wellbore strengthening is an approach used to increase the fracture pressure of the rock, widen the mud window and consequently enhance the well integrity and mitigate mud losses. This paper demonstrates the feasibility of wellbore strengthening in permeable formations using oil-based mud (OBM) containing in-house prepared nanoparticles (NPs) combined with graphite. A significant increase in the fracture pressure was achieved and the predominant wellbore strengthening mechanism was identified. Fracture pressure increase was quantified by carrying out hydraulic fracturing tests on 5 3/4″×9″ Roubidoux sandstone cores. A 9/16″ wellbore was drilled, cased and cemented to simulate well conditions. Overburden and confining pressure were applied on the cores while testing to simulate a normal-faulting regime. Two injection cycles were applied allowing 10 minutes of fracture healing between the cycles. The fracture pressure was increased by 65% when calcium-based NPs (NP2) blends were used, whereas it increased by 39% in the presence of iron-based NPs (NP1). Optimum NPs concentrations were established after a comprehensive experimental screening. A strong relationship between wellbore strengthening and mud filtration at high-pressure high-temperature (HPHT) using a filter press on ceramic discs was found. Optical microscopy, scanning electron microscope (SEM) and energy dispersive X-ray spectroscopy (EDX) analyses were conducted on the hydraulically fractured cores. The fractures were seen to be completely sealed from tip to wellbore. Therefore, tip isolation by the development of an immobile mass was identified as the predominant wellbore strengthening mechanism. A 40 micron-seal containing homogeneously dispersed NPs and graphite was observed. In addition, a 300 micron-filter cake was developed around the wellbore also containing homogeneously dispersed NPs.

Wellbore strengthening (WS) is the mechanism of increasing the fracture pressure of the rock at depth. Applications of WS in the drilling industry enable safe drilling by preventing mud losses, drilling in narrow mud windows, accessing reserves in depleted reservoirs, and also have the potential to reduce the number of casing strings. Most of WS applications have been done for sandstones. In fact, a common industry thought is that a permeable formation is the only medium that allows WS occurrence. WS in shale formations is a controversial topic in the drilling industry due to the poor understanding of the mechanism and limited field success on strengthening of low permeability formations. This paper presents an experimental research work where a significant fracture pressure increase was achieved in shale and the predominant WS mechanism was identified. The main implication of this work is that WS can occur in shale formations using oil based mud (OBM) with the addition of nanoparticles (NPs) and graphite. Fracture pressure increase was quantified by conducting hydraulic fracturing tests on 5 3/4”x9” Catoosa shale cores. A 9/16” wellbore was drilled, cased and cemented. Overburden and confining pressures were applied on the cores to simulate a normal-faulting regime. Two injection cycles were applied allowing 10 min for fracture healing after the first cycle. The fracturing pressure was increased by 30% when calcium-based NPs (NP2) were used, whereas iron-based NPs (NP1) resulted in 20% increase. The optimum NPs concentrations were experimentally identified. A strong relationship between WS and HPHT filtration values was observed. Optical microscopy, scanning electron microscope (SEM) and energy dispersive X-ray spectroscopy (EDX) analyses were conducted on the cores post-testing. The fractures were found to be completely sealed from wellbore to tip. The seal was developed due to the carrier fluid penetration through the induced fractures and NPs attachment on the fracture faces. This was corroborated by the estimation of the pore throat aperture of the shale at the testing pressure. Tip isolation by the development of an immobile mass was identified as the predominant WS mechanism. A 20 micron-seal containing homogenously distributed NPs and graphite was formed. According to the post-testing analysis of cores and injection pressure, WS initially occurred in a certain wellbore direction and a second injection cycle forced the fluid to follow a different direction creating a second vertical fracture. An average angle of 30° was observed between the hydraulic fractures. Introduction WS in shale cores is a debate in the drilling literature. Skeptics believe that this phenomenon cannot occur in shale cores due to its “impermeable” nature based on the hypothesis that WS requires a porous media to occur. Another school of thought (Aston et al. 2007) believes that WS is feasible in shale formations if a fluid that acts as “cement” can travel along the fracture created and adhere to the surface. Tests on concrete cores (Nwaoji 2012) suggested that WS can be achieved in impermeable formations. A recent experimental study (Guo et al. 2014) showed evidence of WS in Runswick Bay shale blocks. Some fractures appeared sealed following testing using graphitic lost circulation material (LCM). A very rough and tortuous primary fracture was obtained. Nonetheless, several aspects from Guo et al. (2014) experimental work are still inconclusive. For instance, following the hydraulic fracturing tests some vertical fractures were obtained along the wellbore. Also, multiple peaks simulating formation breakdown pressures were reported while injecting the fluid into the wellbore.

Preventing or mitigating fluid losses caused by the presence of natural fractures is a major challenge faced by operators when drilling exploratory wells in the Barents Sea. Natural fractures widths vary significantly which makes it difficult to design treatments using conventional lost circulation materials (LCM's). Different solutions have been used to overcome this problem, such as chemical sealants, hydratable LCM's pills, rigid-plugs and cement. This study intends to expand the usage of conventional LCM's in sealing wide fractures. Experimental evaluation of LCM's is a crucial step prior to field application. Currently, particle plugging apparatus is often used to evaluate LCM's performance using straight slots or tapered slots by applying a constant pressure and measuring the fluid loss. However, fluid loss values are not a good measure of the formed seal integrity. Therefore, another means of evaluating LCM's performances is required. In this work LCM sealing efficiency was defined as the seal/bridge maximum breakdown pressure. The tests were conducted on a fit-for-purpose apparatus designed to evaluate the performance of LCM's by measuring the sealing efficiency under high pressures (10,000 psi) and temperatures. This paper presents an extensive laboratory evaluation to investigate the feasibility of sealing wide fractures using conventional LCM's. The ability of different LCM's in sealing fractures was evaluated using a set of tapered slot sizes up to 2000 microns fracture width. Four different types of conventional LCM with 13 different particle sizes (D50) and one new foam wedge based LCM were investigated. A total of 200 tests were run to investigate the effect of different parameters on the overall performance of both conventional and unconventional LCM. These parameters include LCM's type, concentration, tapered slot size, particle size distribution (PSD), temperature, and injection rate. Ground walnut shell showed a superior performance in sealing large fractures (sealing pressure up to 2200 psi) when used as a concentrated pill. Microscopic studies revealed that this performance is due to the ability of these materials to deform and plug fractures under elevated pressure. However, selecting the right LCM concentration is critical to avoid screen out at the fracture openings. Unconventional LCM used in this study was able to seal fractures up to 5 mm where conventional LCM failed to seal. Laboratory procedures to evaluate high fluid loss squeezes by means of hesitation squeeze were developed and recommended injection rates were determined. This research highlights the different factors affecting LCM sealing efficiency and seal integrity. A full understanding of the factors contributing to successful treatments for sealing fractures is very important. Appropriate laboratory evaluation of LCM treatments is an important step prior to field application. The authors believe that a better understanding of these factors will improve the way LCM treatments are designed.