The operational use of nanoparticles (NPs) in drilling and completion fluids is still limited at the present time, in part because of a lack of consistent evidence for and clarification of NP interactions with rock formations, formation fluid, and other fluid additives. For instance, previous fluids research emphasized that NPs bring about pore plugging, which reduces pressure transmission and, in turn, fluid inflow, into the shale pore matrix, which ultimately helps stabilize the borehole. However, it is difficult to understand how pore plugging might be accomplished in the absence of any substantial filtration in shales, considering that the minimal permeability of shales does not allow for any appreciable Darcy flow. This paper addresses the crucial question: “How, when, and why do NPs plug shale pore throats?”
Zeta-potential (ZP) measurements were carried out on aqueous NP dispersions and on intact thin shale sections exposed to nanofluids to determine the degree of interaction behavior between NPs and shale. The experimental data were then used to calculate Derjaguin-Landau-Verwey-Overbeek (DLVO) curves (describing the force between charged surfaces interacting through a liquid medium) to determine if the total potential energy was sufficient for NPs to diffuse through the repellent barrier and attach to the shale surface. Calculated DLVO curves were used to demonstrate the NPs ability to contribute to borehole stability, but did not directly correlate the effects the NPs had on shale stability. Experiments, including pore pressure-transmission tests (PTTs), which measure fluid pressure penetration in shale, and modified thick-walled-cylinder (TWC) collapse tests, which explore the influence of NPs on the collapse pressure of shale samples, were conducted to directly investigate the effects of NPs on borehole stability in shale.
Our investigation showed that NPs can reduce fluid pressure penetration and delay borehole collapse in shale, but only under certain conditions. Electrostatic/electrodynamic interaction between NPs and shale surfaces, governed by DLVO forces, is the main mechanism that leads to pore-throat plugging, reducing pressure transmission, which in turn benefits borehole stability by slowing down near-wellbore pore-pressure elevation and effective-stress reduction. For Mancos Shale, 20-nm anionic nanosilica particles were effective in partially plugging the pore-throat system, depending on the pH of the nanofluid, which affects the surface potential and ZP of both NPs and shale. Furthermore, cationic nanosilica showed better results for pore-plugging capabilities than the anionic nanosilica.
Our findings lead to interesting challenges for the practical field application of NP-based drilling fluids for borehole stability, given that efficacy depends on the specific type of shale; the specific type, size, and concentration of NP; the interaction between NPs and shale; and external factors, such as pH, salinity, and temperature. Therefore, NP use for practical shale stabilization requires a dedicated, thoroughly engineered solution for each particular field application, and is unlikely to be “one size fits all.”
Offshore wells drilled in the central and northern North Sea have historically suffered from borehole-instability problems when intersecting the Upper/Lower Lark and Horda Shale formations using either water-based mud (WBM) or oil-based mud (OBM). A wellbore-stability investigation was performed that focused primarily on improving shale/fluid compatibility. It was augmented by a look-back analysis of historical drilling operations to help identify practical solutions to the borehole-instability problems.
An experimental rock-mechanics and shale/fluid-compatibility investigation was performed featuring X-ray-diffraction (XRD) and cation-exchange-capacity (CEC) characterizations, shale accretion, cuttings dispersion, mud-pressure transmission, and a new type of borehole-collapse test for 10 different mud systems [WBM, OBM, and high-performance WBM (HP-WBM)]. The results of this investigation were then combined with the results of a well look-back study. The integrated study clearly identified the root cause(s) of historical well problems and highlighted practical solutions that were subsequently implemented in the field.
The borehole-instability problems in the Lark and Horda Shales have a characteristic time dependency, with wellbore cavings occurring after 3 to 5 days of openhole time. The problems were not related to mud-weight selection but were instead caused by mud-pressure invasion into the shales, which destabilizes them over time. An experimental testing program revealed that this effect occurs in both WBM and OBM to an equal extent, which explains why nonoptimal field performance has historically been obtained with both types of mud systems. New HP-WBM formulations were identified that improve upon the mud-pressure invasion and borehole-collapse behavior of conventional OBM and WBM systems, yielding extended openhole time that allows the hole sections in the Lark and Horda Shales to be drilled, cased, and cemented without triggering large-scale instability. Look-back analysis also indicated that secondary causes of wellbore instability, such as barite sag, backreaming, and associated drillstring vibrations, should be minimized for optimal drilling performance. A new HP-WBM system, together with improved operational guidelines, was successfully implemented in the field, and the results are reported here.
ABSTRACT: A geomechanical model is presented to characterize the flow of solid-laden fluids into pre-existing penny-shaped fractures. The model incorporates the impacts of the fluid leak-off, fracture deformability, fluid rheology, and the solid content of the fluid in a coupled manner. Mathematical derivations pertaining to the different elements of the model are presented. The model yields a coupled system of non-linear partial differential equations (PDEs), which is solved using an implicit finite difference scheme. The developed solution enables simulating the impact of the solid content of the fluid in plugging of fractures. It is shown that formation of a plugged zone can significantly affect the rate and depth of fluid invasion in fractures. In fact, it can be shown that for fluids which are heavily loaded with solids (e.g., drilling fluids), it is necessary to consider the impact of the fracture plugging effects on the fluid invasion problem. Sensitivity analyses were conducted to investigate the impact of the solid concentration, filtration rate, and borehole overpressure. The results show that a higher solid concentration will result in a faster plugging of the fractures, and thereby lower volume of fluid invasion in fractures. This study confirms that solid plugging of fractures requires a minimum level of leak-off volume, and no effective fracture plugging is expected in impermeable formations. From a practical standpoint, the developed model may be used in well construction applications to avoid severe lost circulation problems in fractured formations.
Solid plugging of fractures is a common phenomenon in the drilling engineering and reservoir stimulation applications. In the drilling industry, plugging of fractured boreholes is a common practice to prevent lost circulation problems. Fracture plugging is typically achieved by adding certain particulate solids to the drilling fluid in a process called wellbore strengthening (WBS) (van Oort and Razavi, 2014). In the drilling industry, these solids are commonly known as lost circulation materials (LCM). In reservoir stimulation treatments, solid plugging of fractures results in the screen-out phenomenon, which refers to a condition when the proppants create a bridge across the perforations, due to excessive leak-off or insufficient pad fluid volume (Barree, 1991). The formed bridge will then create a sudden restriction to the flow of fracturing fluid, and cause a rapid rise in the pump pressure which can complicate and even terminate the hydraulic fracturing operation. The screen-out phenomenon is sometimes employed deliberately to enhance the well conductivity in highly or moderately permeable formations (Economides and Nolte, 2000, and Economides et al., 2002). In these formation types, very high pressures and very high proppant loadings are applied near the end of a fracturing treatment to stop propagation of the tip of the fracture due to bridging of proppant across the fracture width.
ABSTRACT: In this study, pore-scale dynamic mud invasion in a radial system was investigated for different rock samples. The rocks were selected to generate the mud invasion patterns, filter cake permeability profiles, and change in stress profiles of the lithologies they represent. Each rock was cut into a thick-walled cylindrical shape to simulate drill pipe rotation inside the inner diameter. In the experimental design, lost circulation material (LCM) concentration and rotary speed were varied based on the results of preliminary experiments with ceramic filter tubes. Water based mud (WBM) was formulated with calcium carbonate, and the viscosity profile of the fluid with change in temperature was also determined. The results from the experiments revealed different dynamic mud invasion and filter cake permeability patterns for different rock samples. These patterns were controlled by the rock porosity, permeability, temperature, and rotary speed. Increasing the concentration of calcium carbonate beyond a certain threshold may not always reduce pore-scale dynamic mud invasion at elevated conditions. Analytical results showed that rock permeability and filter cake permeability profile largely control the changes in wellbore stress profile. This approach can be used in the planning and well design process for drilling similar lithologies.
Drilling fluid lost circulation and mud invasion still pose a wellbore stability challenge to drilling operations. Drilling through depleted reservoirs (low pore pressure and fracture gradient) or naturally fractured formations are typical scenarios where lost circulation events and mud invasion are almost inevitable. Deep invasion of fine mud particles (barite, polymers, and drill cuttings) and mud filtrate can alter the formation permeability in what is referred to as formation damage (Civan 2007). Current industry practice relies on either preventative or remedial lost circulation material (LCM) treatment in mitigating mud invasion. These have been described by several literatures as highlighted by Alsaba (2015) and Salehi (2012). Ezeakacha and Salehi (2018) also highlighted some of the previous experimental and field studies with successful reduction in mud invasion from filter cake evolution. Salehi and Kiran (2016) reported that a positive change in effective stress can occur when a permeable wellbore is exposed to a low-permeability filter cake. This can result to increase in the fracture gradient, and it is referred to as mud cake wellbore strengthening. However, the complexity in mud invasion, filtration, and filter cake evolution is contributed to by the interbedded nature of lithologies, rock minerology, and other operational control factors.
The influence imposed by drilling operations on the outcome of hydraulic fracturing has been well studied in terms of the post-frac stage productivity. Drilling induced formation damage caused by drilling fluids solids and filtration invasion is routinely linked to both the design and the results of stimulation operations in general. Nonetheless, hydraulic fracturing performed on deep and tight sandstone reservoirs presents a new challenge that requires a new perspective when it comes to analyzing the link between drilling and fracturing. The tightness, depth, and highly stressed nature of these formations mean that achieving formation breakdown for the hydraulic fracture initiation is a challenge. To gain a better understanding of this challenge, the role played by drilling in influencing formation breakdown is examined using different types of drilling data pertaining to stimulated intervals.
The proposed examination is carried out by uncovering the variations in different sets of drilling data and correlating those to the results of fracturing. The sets of drilling data considered describe the drilling fluids rheology, drilling fluids interaction with the formation, and the drilled wellbore quality. These observed variations are then investigated through lab experiments where applicable. Other than lab experiments, the links between drilling influences and formation breakdown is established through either data analytics or technical evidence provided by the published literature. Upon establishing the link between drilling influences and fracturing, detailed recommendations are produced to improve the success rate of hydraulic fracturing operations in terms of formation breakdown.
As anticipated, parameters indicating the damage-ability of the fluids used to drill the stimulated intervals showed a clear link to the outcome of formation breakdown attempts. These parameters are mostly measured by the Particle Plugging Apparatus on location prior to and while drilling the intervals of interest. Recommendations to mitigate the effect of these parameters is issued based on a redesigned formulation of the drilling fluid employed. Other influences include certain drilling events that limited the burst pressure rating of the downhole tubulars (casings and liners) to a value below what is necessary to initiate a fracture.
The work presented in this paper has the potential to significantly improve the success rate of stimulation operations in deep and tight sandstone reservoirs. This is proposed to be achieved by uncovering new links between different drilling influences and the formation breakdown. Complementing the outcome of this work with the rich body of literature investigating the relationship between the postfrac stage productivity and drilling can present a new pathway to access reserves in challenging environments.
Mud cake evolution and plastering have been identified as important wellbore strengthening mechanisms. They serve to reduce losses through pore throats and fractures, while impeding the growth of induced fractures. Recent experimental and analytical studies have also revealed the complexities in drilling fluids’ invasion profiles and mud cake buildup. These complexities arise from the changing wellbore conditions observed in an actual field scenario. It is important to investigate the effects of these conditions on drilling fluid invasion for near-wellbore strengthening application.
To achieve this goal, some dynamic wellbore conditions which are close-to-real field conditions were simulated in a controlled laboratory setup. The following conditions were investigated: rotary speed, temperature, type of lost circulation material (LCM), concentration of LCM, differential pressure, eccentricity, rock permeability, and fracture width. In the experimental setup, the geometry of the shaft that simulates drill pipe rotation allowed for mud cake evolution and plastering around the inner diameter of the thick-walled cylindrical porous media. Water-based mud (WBM) recipes were formulated for different porous media types. The rheological profile for each mud recipe was investigated for operating temperature limit. Dynamic drilling fluid invasion experiments were conducted with thick-walled cylindrical Buff Berea sandstone, Upper Grey sandstone, and fracture slots with varying widths.
The results indicate that temperature, rock permeability, fracture width, and LCM type and concentration are the most influential factors that control dynamic fluid invasion profiles. Increase in granular LCM concentration at elevated temperature is not completely effective in reducing pore-scale fluid invasion. Spurt invasion, rock porosity, permeability, and fracture width are important determinants of mud cake evolution. Increase in fiber LCM concentration showed effective mud cake evolution in the fracture slots. The results from testing mud cake stability revealed mud cake rupturing on three experiments out of the nine that were performed. The novelty in this approach is the use of thick-walled cylindrical cores and fracture slots to profile dynamic fluid invasion of different fluid recipes. Pressure, temperature, and pipe rotation were combined to simulate wellbore conditions under which fluid loss, cake growth, and plastering occur. This approach can be used in drilling fluid design for minimizing fluid loss, cost, and selection of operating conditions.
One of the main causes involved in reservoir formation damages is the excessive mud filtrate during drilling with an overbalanced mud weight. Results show reservoir pressure retreat due to geological structural failure can leads to a large disparity between MW and PP especially in HPHT environment.
This new approach focuses on the geological structural failure that causes the well bore trajectory to cut through different transgressive and regressive pressure envelops. If the mud program, based on the pre-drill pore pressure model, did not account for a pressure retreat, a sizeable lost circulation can take place. Mud fluid invasion to the open borehole wall can decrease permeability, impact logs measurements and potential production. Moreover, thick mud cake causes bore-hole tight spots, excessive torques and pulls. Incorporating the subsurface geological structure features to the seismic driven pre-drilling models can foresee the unexpected mud weight overbalance intervals.
In relative old sediments, such as Oligocene and Miocene in the offshore shelf areas, a substantial mud weight (MW) increase of 2-5 ponds is needed to penetrate the top of geopressure (TOG). The deeper geopressured compartments are usually drilled with MW that sometimes reaches 18 pounds per gallon. Moreover, temperature can range from 300 to 350 degrees Fahrenheit. Formation damages and serious challenges take place where the MW is overbalance juxtaposing a regressive permeable rock sequence. Study the relationship between geopressure compartmentalization and drilling challenges of multiple wells in East – West Cameron, offshore Louisiana sheds light on one of the important causes of formation damages, tight spots, high torque and pulls. Pay zones were partially masked due to deep mud filtrate invasion with frequent use of oil-base to reduce pulls in the tight spots. Sidetracks usually was the ultimate remedy for some of the wells that did not reach their objective TD. The case histories shown in this study illustrate that exploring the depth to the possible regression zones before drilling in conjunction with the pre-drill pore pressure model could have alerted drillers for MW amendment to avoid lost circulation.
The benefit of correlating the bore-hole trajectory to the seismic semblance associated with the geopressure profile is a resourceful method of foreseeing the troublesome intervals. In real time, calibrating the MW derived from the seismic pre-drill model is another deterrent process to avoid utilizing excessive overbalanced MW.
Lost circulation is a time-consuming and expensive challenge, costing the oil and gas industry billions of dollars each year in materials, nonproductive time, and minimized production (Catalin et al. 2003; Fidan et al. 2004; API 65-2 2010). To mitigate lost circulation during cementing operations, a better understanding of how wellbore-strengthening mechanisms apply to cement slurries is necessary. The ability to control cementing-fluid properties to strengthen the wellbore and minimize losses during cementing operations is imperative for achieving adequate zonal isolation.
A field analysis was performed to understand the start of lost circulation during different phases of drilling and primary cementing. Offshore wells from four different locations were studied: Gulf of Mexico (GOM), the UK, Angola, and Azerbaijan. In parallel, laboratory research was performed to understand the behavior of cement slurries in controlled lost-circulation scenarios using a block tester. Measurements of formation-breakdown pressure and fracture-propagation pressure were made with different cement-slurry compositions and compared with pressures obtained with drilling muds.
In an analysis of 40 well sections that reported losses before or during primary cementing operations, the rate and severity of lost circulation varied for the wells studied, but it was concluded that losses were commonly induced while running casing or during precement-job mud circulation, but rarely during cement placement.
The laboratory research confirmed the field observation: It would take much more pressure to open or reopen an existing fracture with cement slurry than with a synthetic-oil-based mud.
This paper will present findings from the field analysis and laboratory research. It will also discuss strategies to prepare the wellbore for preventing losses before the cementing operation and to optimize cement formulations if losses have been induced during drilling, casing running, or prejob mud circulation.
ABSTRACT: A proper wellbore stability analysis is necessary to avoid trespassing the limits of mud weight window especially in off-shore drilling. Wellbore strengthening is a mechanism to enable safe and cost-effective drilling operation by means of increasing the fracture pressure of the rock. This paper presents a model illustrating the relationship between wellbore strengthening and HPHT filtration for different permeabilities. Data were collected from previous experiments on shale and sandstone cores to increase fracture pressure by utilizing calcium-based, iron-based nanoparticles (NPs) and graphite in oil based mud. A differential evolution algorithm was used to find a poly-variate, polynomial model for breakdown pressure increase and HPHT fluid loss reductions for different permeable media. Sensitivity analysis were done to test the robustness of the results of the model and to reduce uncertainty. Based on the results, filtration reduction is dominant parameter on wellbore strengthening. The correlation shows permeability has a limited influence on increasing fracture pressure. By decreasing filtration using calcium-based and iron-based NPs in drilling fluid, fracture pressure increase in both high and low permeable formations.
Exceeding the formation fracture pressure during drilling operations can result in high fluid losses, lost circulation, loss in mud hydrostatic pressure potentially resulting in a kick which could lead to a blowout. As a well deepens, the mud safe window range narrows due to the convergence of the pore and formation fracture gradient. Therefore, it is crucial to choose a mud weight to stay in the safe mud weight window. The process of increasing the wellbore pressure containment using engineered drilling fluids is called wellbore strengthening (WS). WS can be achieved by avoiding drilling fluid penetrating the formation and limiting the local increase in formation pressure around the wellbore as a result of the drilling fluid entering the formation. WS has been studied by many researchers and different procedures and techniques have been suggested. WS is applied to prevent or treat lost circulation with the goal of decreasing or limit the drilling fluid from entering the formation. WS methods include use of different additives in drilling fluids, heating the wellbore to change in situ rock stresses around borehole, and use of pills for temporarily isolating troublesome zones.
Sathuvalli, Udaya (Blade Energy Partners) | Pilko, Robert M (Blade Energy Partners) | Gonzalez, Alexa (Blade Energy Partners) | Pai, Rahul (Blade Energy Partners) | Sachdeva, Parveen (Blade Energy Partners) | Suryanarayana, P. V. (Blade Energy Partners)
Subsea wells use annular-pressure-buildup (APB) mitigation devices to ensure well integrity. We define mitigation techniques that control APB by reducing lateral heat loss from the production tubing to the wellbore as Type I techniques. Mitigation techniques that control the stiffness (psi/F) of an annulus by modifying its contents and boundaries are defined as Type II techniques.
Although the physics of APB mitigation is well-understood, the reliability of a mitigation strategy or its interaction with other parts of the wellbore is not always quantifiable. This is partly because of the lack of a unified approach to analyze mitigation strategies, and partly because of the lack of downhole data after well completion. Simply stated, the engineer is hard-pressed to find computational-predictive methods to assess alternative scenarios and strategies within the framework of the design basis during the life of the well. In this light, our paper presents a quantitative approach to design the currently used APB mitigation strategies: rupture disks, syntactic foams, nitrified spacers, and vacuum-insulated tubing (VIT). In each case, the design is linked to the notion of “allowable APB” in an annulus, which in turn is tied to the design of the casing strings, and thus to wellbore integrity. We also review APB mitigation techniques that have been used less frequently or are awaiting proof of concept/field trial.