This paper identifies wellbore stability concerns caused by transient surge and swab pressures during deepwater drilling tripping and reaming operations. Wellbore stability analysis is presented that couples transient surge and swab wellbore pressure oscillations and in-situ stress field oscillations in the near wellbore (NWB) zone in deepwater drilling. Deepwater drilling is usually subjected to narrow drilling windows and significant wellbore pressure oscillations during tripping/reaming because of well depth. However, integration of transient surge and swab pressure analysis, and its effects on in-situ stress analysis around the wellbore, is rarely industry studied. A transient surge and swab model is developed by considering drillstring components, wellbore structure, formation elasticity, pipe elasticity, fluid compressibility, fluid rheology, etc. Real-time pressure oscillations during tripping/reaming are obtained. Based on geomechanical principles, in-situ stress around the wellbore is calculated by coupling transient wellbore pressure with surge and swab pressure, pore pressure, and original formation stress status to perform wellbore stability analysis. By applying the breakout failure and wellbore fracture failure in the analysis, a workflow is proposed to obtain the safe operating window for tripping and reaming processes. Based on this study, it is determined that the safe drilling operation window for wellbore stability consists of more than just fluid density. The oscillation magnitude of transient wellbore pressure can be larger than the friction pressure loss during normal circulation process. With the effect of surge and swab pressure, the safe operating window can become narrower than expected. Although it is stable and not a concern during a normal penetration process, the wellbore stability can become problematic. By using the methodology described, unnecessary breakouts and borehole failures during tripping and reaming can be avoided. This work can also be used in the next generation of drilling automation. This study provides insight into the integration of wellbore stability analysis and transient surge and swab pressure analysis, which is rarely discussed in the literature. It indicates that, when surge and swab pressure analysis is not carefully performed, the actual safe operating window can become narrower than originally predicted.

During a drilling campaign in the southern North Sea involving installation of two additional conductors inside a mono-tower, significant challenges to the operator were encountered. The mono-tower is a hydrocarbon production platform with six slots. The slots are located inside the foundation pile, extending above sea level, and were driven into the seabed using an impact hammer. Structural integrity of this foundation pile over the platform operating lifetime is paramount. The basis of the well is its conductor, which is typically installed using the drill/drive method with an impact hammer followed by soil drillout. Offset installation challenges in the mono-tower deemed using the drill/drive method ineffective for this new well. An alternative method for installing conductors is the drill/grout method. However, drilling an open hole increases the possibility of massive washout or hydraulic fracture. The fluids provider designed a water-based mud (WBM) system customized for rapid fluid-loss prevention, thus strengthening the wellbore, maintaining hole integrity, and preventing hydraulic fracture. In subsea or conventional platform wells, fluids return at the seabed without additional hydrostatic pressure. Because of drilling inside the foundation pile, the lowest achievable elevation for fluid returns is at the top of the foundation pile. Fluid flow into the formation can lead to degradation of the soil-bearing strength around the single foundation pile and adjacent wells. This could potentially lead to subsidence of the mono-tower or buckling of the existing wells. In case of experiencing ever losses a contingency plan was in place with a decision tree used to determine the most appropriate formulation and sequence of lost circulation material (LCM) pills, with setting cement plugs as a last resort. Installing the two additional conductors with that rig could have impaired the structural integrity of the platform foundation pile. The drilling mud design played a vital role in managing this risk. The uniqueness of the fluid design helped deliver the section without wellbore instability issues, hence avoiding losses or hole collapse, requiring reactive measures. The results demonstrated that wellbore pressure containment and full hole integrity can be achieved when drilling unconsolidated sands. The novelty of the technical process and fluid design approach acted as a barrier to help prevent losses and proved the theory of wellbore stabilization and strengthening in unconsolidated sands through field applications. This paper focusses only on discussing the application of an engineered fluid solution through a rigorous technical approach, which contributed to the success during such critical operations.

Traditional water based fluids tend to penetrate into shale formations, and interact with clay minerals, which results in clay swelling and wellbore instability. The larger content of clay in some deep water shales compared to regular onshore shales generates more wellbore instability problems. To reduce shale-fluid interaction, we need to reduce water invasion by sealing the pores and micro-fractures in shales. Therefore, the objectives of this study are to conduct pore pressure transmission (PPT) tests with test fluids that contain two new families of nanoparticles and to evaluate the major factors that affect pore pressure transmission. For the first time, Mancos Shale and Eagle Ford Shale have been investigated with PPT tests using fluids that contain nanoparticles in different sizes (10 nm, 20 nm, 30 nm, 40 nm), types (aluminum oxide, magnesium oxide) and concentrations (3%, 10%). Results show that nanoparticles of 10 nm size can delay the time needed to reach the equilibrium state to 48.2 hours, compared to 27.8 hours needed for Eagle Ford Shale treated with suspensions that contain 40 nm nanoparticles. Based on the test matrix, the better combinations to decrease pore pressure at the equilibrium state are 10% 10 nm Al 2 O 3 for Eagle Ford Shale and 10% 30 nm Al 2 O 3 for Mancos Shale. This relatively new plugging technique using nanoparticles has great practical potential for successful application in deep water drilling. A decrease in pore pressure transmission and the delay of the time to reach the equilibrium state will reduce problems of hydration and swelling in shale formations. This study can also help to define water based drilling fluid properties for the purpose of improving wellbore stability in deep water drilling.

Cement plugs are used for various reasons in wellbores, including control of lost circulation zones, initiation of deviation or side tracking, wellbore abandonment, and more. Unfortunately, one of the most questionable processes during the drilling and completion stage of a wellbore is the quality of the cementing job. As in conventional cementing operations, cement plug setting requires an efficient fluid displacement process to be considered "successful." Due to the nature of the operation, i.e., displacing one fluid with another inside a tubular, mixing of the fluids during this process is inevitable, because the fluids are in contact via a contacting interface. The stability of this interface depends on many parameters, such as flow rate, pipe size, inclination, displacing and displaced fluid rheological properties, as well as densities, interfacial tension between the fluids, etc. Therefore, an optimization process is required to minimize the mixing and thus to maximize the quality of the cement plug to be set by controlling the physical properties of the displacing fluid. In this study, the displacement process of one fluid with another inside circular pipes is investigated analytically and experimentally. Analytical work includes a simplified mathematical model that can predict the structure of the interface between the displacing and displaced fluid. The model allows determination of the mixed volume during the flow. In addition, CFD (computational fluid dynamics) simulations of the mixed volume are conducted using a commercial software. During the experimental work, different combinations of fluids with specified rheological properties and densities are compared based on the extent of displacement and mixing in circular pipes at different flow rates using The University of Tulsa – Displacement and Mixing Facility. Analytical modeling, experimental tests, and CFD simulations all indicate that significant mixing takes place during a displacement process, and even in a "successful" case, 15% by volume of the cement plug is contaminated by the displacing fluid. If the physical properties of the displacing fluid are not optimized, this contaminated volume becomes more than 50% of the total volume of the cement plug. This level of mixing will result in failure of the set plug's function. The study also shows that rheological properties and density of the displacing fluid significantly influence the displacement efficiency, which can be used as an optimization tool for reducing / minimizing the mixed volume during the displacement process. The quality of the primary cementing and cement plug setting processes directly depends on minimization of the mixed volume. This is not only a safety issue, it can also result in serious environmental impacts, such as contamination of the water table. The information obtained from this study can be used as to establish guidelines for the optimization of displacing fluid properties that result in successful primary cementing and cement plug setting.

The first highly deviated Deep Water well with an inclination up to 80° was drilled in Mexico. A strategy developed in collaboration with the owner and Directional Drilling contractor allowed to safely drill the well within AFE and reach all planned objectives. In order to maximize production, avoid geological risks and optimize utilization of existing subsea infrastructure the Deep Water well (with water depth over 3000ft) was designed with inclination reaching 75°, demanding dog leg severity (2.5°/100ft) and several sections to be enlarged while drilling. Being the first well with such high angle in Mexican Deep Water, Lakach-52 did not have much of a reference. Many design and operational issues had to be solved for the first time. Besides problems typical for highly deviated wells, such as hole cleaning, wellbore stability, high ECD, etc., potential issues were anticipated with a kick off from vertical in very soft formation, perform directional work within interbedded formations and a zone of conglomerates, pass between faults and simultaneously enlarge the hole. Additionally, a number of factors were taken into account in order to design the well: existing subsea infrastructure, local practices, geological/geomechanical risks, operational risks (direction, S&V, stuck pipe, etc.) In order to ensure flawless performance and address all potential issues, the service company ran the project under integrated management roof. A special communication protocol/structure was designed in order to optimize the decision making process than response time. A specific project drilling strategy was developed for each stage of the well construction process. All BHAs as well as drilling parameters were designed using the following approach: fit to purpose BHA tendency, bending stresses below critical, minimum shocks and vibrations and optimized hydraulics. As a result, the well was successfully drilled within AFE curve, all given targets were successfully achieved. All sections were drilled with ROP faster than planned. The conductor was jetted and the following section was drilled ahead using a straight motor with a minimum deviation from verticality 0.26° The kick off successfully performed at very shallow depth and very soft formation with push the bit Rotary Steerable system. The 17 ½" × 20" section was drilled successfully in 1 run. Inclination was built to 30°. The 14 ½"x 17 ½" section was the most challenging section. 3 BHAs were used to drill the section. Optimization of the BHA allowed to eliminate shocks & vibrations and reach drilling objective within the given tolerance, despite the geological complications and demanding well profile. The 12 ¼" section was drilled successfully to TD and the required LWD logs were obtained in the reservoir at 75° of inclination.

Drilling through depleted zones in offshore deepwater prospects is becoming more common with ongoing production and field maturation, especially when deeper-lying, virgin-pressured reservoirs are explored and produced in later stages of field development. Some of the challenges associated with these depleted zones include severe mud loss and associated borehole problems, as well as troublesome cementing and poor zonal isolation. Artificially strengthening the wellbore is now becoming of crucial importance in order to successfully drill and cement deepwater wells in mature fields and any other wells with narrow drilling margins. In this paper, we introduce an innovative thermal wellbore strengthening (TWBS) technique to elevate the tangential stress (also known as the hoop stress) near the wellbore, and consequently increase the fracture gradient. A "thermal fluid," consisting of a carrier mud with heat-releasing ("exothermic") coated particles, has been designed to target depleted zones and release heat at exactly the right time to increase near-wellbore thermal stress, which directly elevates the near-wellbore tangential stress and in turn elevates the effective fracture gradient. Ultimately, this lowers the risk of lost circulation and improves the chance of successfully cementing and achieving zonal isolation. For instance, a TWBS treatment can be executed as an integral part of the cement job by using it in an extended spacer train for mud displacement, pumped directly prior to cement placement. The coated exothermic particles were designed such that they could release their "payload" via an extended time-release mechanism, to ensure that the heat release reaches the appropriate target location in the wellbore at the right time. The chemical systems, which are based on dissolving various hygroscopic salts in water, were tested and developed to heat up the wellbore and increase temperature up to 100°C. This will potentially elevate the fracture gradient by several hundred psi, depending on formation properties. Details regarding the formulation and testing of the non-coated, coated particles, and the carrier fluid are discussed; as well as considerations for TWBS field application. In addition, a new computational heat transfer model was developed to calculate the temperature distribution within the rock formation and within the drillstring/work string and wellbore annulus, for a formation contacted by a fluid with particles that react in exothermic fashion. The new model calculates the transient temperature distribution, increase in near-wellbore stress, and fracture gradient for a given amount of heat generation by the fluid and temperature increase in the rock. It can assist with well design aspects of the proposed thermal wellbore strengthening technique, and is particularly helpful in estimating the downhole temperature variations and assessing its implications prior to job execution. Details of the model and results of several typical simulations are given herein.

The electrical submersible pump’s (ESP) impact on wellbore temperatures and integrity is seldom discussed in literature. Most literature discusses ESP run life and failure. The ESP heat dissipation increases the wellbore temperatures. Therefore, direct and indirect thermal-induced stresses are applied to the casings and tubing. At the same time, the trapped annular pressure buildup (APB) also increases, thereby applying additional stress on the casings and tubing. This raises the question—is the safety factor still valid? This is crucial in high-temperature/high-pressure (HT/HP) and deepwater/ultra-deepwater wells that have narrow design margins. This paper presents studies on the prediction of wellbore temperature and pressure profiles, which account for the ESP heat dissipation effect on APB. The heat dissipation from the ESP electric motor, pump, and cable are considered. Then, the convective and conductive heat transfer through the wellbore are described in a transient wellbore temperature model. The updated temperature profile is then applied, and the APB and tubular stress analysis is revisited. The model is integrated into an advanced casing and tubing design software platform. Case study results show increasing temperatures along the wellbore. The increased temperatures induce the APB and the strings axial compressive stress increase. In the studied case, the APB increased up to 23.6%. The increased APB induced additional loads on the tubing and casings, which can result in collapse/burst failures. Both theoretical analysis and case studies show that if the original design did not consider the use of ESP, induced APB can cause casing/tubing failure and result in wellbore integrity issues. The findings indicate ESP heat dissipation does affect the wellbore integrity. Attention should be paid to the possible allocation of ESP in the future to achieve an accurate APB prediction during the modern wellbore completion design and planning phase. The findings are of particular interest in production monitoring and control, wellbore completion, ESP selection, casing/tubing design, and wellbore integrity, especially for mature-field and offshore wells.

Lost circulation is a major challenge in well construction operations, especially where drilling margins are narrow or in pressure-depleted reservoirs. Wellbore strengthening techniques (e.g., StressCage) have successfully been used to increase formation fracture resistance and reduce mud losses during drilling operations. The increase of fracture resistance in sands has been used to improve wellbore stability (through the use of higher mud weights), reduce casing requirements, and access resources that may have been undrillable using conventional drilling methods. The StressCage technique requires the estimation of the width of an induced fracture at a target fracture length for a given wellbore pressure. This estimation involves either a finite element calculation or a closed form line crack analytical solution. Populating and running the finite element solution requires specialized software and expertise, which has limited its use to larger operators and service companies that are staffed with geomechanics experts. The closed form line crack analytical solution is both simple to implement and easy to use, but it assumes transverse isotropic in-situ stress conditions relative to the borehole axis, which is almost never the case in the presence of a deviated well. This assumption results in either the underestimation of the calculation of the fracture width in the presence of deviation or abnormal in-situ stresses, which can result in a failed implementation of a StressCage formulation. We have developed a new semi-analytical line crack solution that accounts for stress anisotropy from either borehole inclination or abnormal in-situ stresses. This new solution is simple to implement. The calculation of the fracture width has been verified against finite element calculations through a range of stress anisotropies, borehole sizes, Young’s moduli, Poisson’s ratios, and target increases in wellbore strength.

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.

Because of the complex distribution of stress directions around a salt body, accurate prediction of the mud-weight window (MWW) for subsalt wells has presented a challenge within the industry for many years. This paper presents a method for the enhanced 1D prediction of the MWW for subsalt wells in the Viosca Knoll area in deepwater Gulf of Mexico (GOM). An initial stress solution is obtained using a 3D finite-element method (FEM). The stress solution is then used as input data to the 1D prediction tool. The field-scale model used in the calculation is a cubic block with a true vertical depth (TVD) of about 9000 m, a width of 7500 m, and a length of 7500 m. Along the wellbore trajectory, the salt body is 6000 m thick and 5500 m wide. Based on seismic sectional data, an anticlinal structure is constructed accordingly at its bottom surface. The 3D porous elastoplastic FEM calculation was performed first with the field-scale model. The effective stress ratio was provided for the 1D prediction of MWW along the given wellbore trajectory. The finite-element model simulates the geometry of the salt body in detail. Comparisons are made between the results obtained with the enhanced 1D method, the conventional 1D method, and a finite-element method. Solutions obtained with the conventional 1D method missed the abnormality of stress distribution at the salt base and have smaller MWW values, as compared to the other solutions. The solution for MWW obtained with the enhanced 1D method is near the value obtained with the finite-element method, but at only 10% of the time cost. The FEM enhanced 1D method proposed has proven to be the most cost efficient method for predicting MWW for subsalt wells. This work presents an example of a best practice.

Drilling in deepwater environments poses many challenges, due its narrow operational window. Very common problems at this scenario are low fracture strength and big losses of drilling fluid while drilling. In order to mitigate these problems, various resin systems such as epoxies, phenolics, and furans have been reported in the literature. However, hyperbranched epoxy resin is a new class of polymers that promises to be a good choice for application in narrow window drilling operations, due its particular properties. In fact, hyperbranched resins are attracting attention of scientific community because of their unique structure and properties, such as low solution and melt-viscosity, good reactivity and faster curing time compared to their linear counterparts. Barua et.al has synthetized a low viscosity hyperbranched epoxy resin from non-hazardous and environment friendly substrate, the glycerol. The hyperbranched epoxy resin was evaluated by use of several procedures at room temperature – e.g., compressive and viscosity tests. Also, equipment has been designed and built in order to evaluate wellbore strengthening properties of developed material under simulated downhole conditions. This paper presents results that illustrate the capacity of this new system to cure losses and improve mechanical properties of the formations.

Casing while Drilling (CwD) is a new drilling method where the well is drilled and cased simultaneously. Previous field operations of CwD have shown a decrease in drilling non-productive time as well as improvement in controlling lost circulation and wellbore stability. Although advantages of this technology are well noted in the literature, the mechanisms of improvements were not studied comprehensively. In order to study these mechanisms, one has to understand the formation properties, fluid hydraulics, casing dynamics, and how CwD helps in better hydraulic control and results in strengthening effects. In the previous research works, the factors that were widely discussed and results obtained were related to formation properties. However, while considering the stresses in the wellbore, mechanical factors such as the RPM and contact of casing at different positions in wellbore were usually neglected. In furtherance to this study, the importance of plastering mechanism cannot be ignored. This work includes a new insight towards the underlying mechanism of casing-wellbore contact and changes in the near wellbore stresses while casing rotation. The main objective of this study is to investigate the hypothesis of the increase in hoop stress when the casing contacts wellbore with regard to the formation stresses orientations. To accomplish this objective, finite-element analysis has been conducted to simulate several CwD scenarios. The classical equations used to obtain the wellbore stresses include parameters like the far-field stresses, pore pressure, and wellbore geometry. These equations do not consider the effect of casing pipe contact and eccentricity; therefore finite element simulations can be very helpful to investigate these effects. Casing-wellbore contact in both maximum and minimum in-situ stress directions are considered in this study as well as changing contact length. The study of different cases shows the variation of hoop stress, which can be beneficial if properly implemented in CwD operations.

Wellbore stability issues are continually plaguing the industry and it is important to understand the mud properties that contribute to these issues. The effects of mud cake build up and filtration with time aids the understanding of formation damage and wellbore stability. The increase of drilling in high temperature and pressure zones (HTHP) necessitates studies that can predict filtrate invasion, and particle bridging. The most common hydraulically challenged zones are: depleted sands or intervals with very low pore pressure and fracture pressure, wellbore ballooning zones encountered in deep water drilling where surge and swab pressures could be a serious challenge, and complete lost circulation/no return zones. Filtrate invasion and mud cake build up can be considered as primary factors controlling wellbore stability while drilling. Decreasing the near wellbore permeability by forming an ultra low permeability mud cake can strengthen the wellbore and mitigate further lost circulation problems. Very few studies have investigated filtration and filter cake build up under HPHT situations where the effect of different mud particles and bridging solids can be analyzed. This paper focuses on experimental methods to investigate the effects of particle bridging, filtrate invasion and permeability on some common water based muds used by the industry. The methodology in this paper is based on using high temperature and pressure (HTHP) filtration tests at different time steps on sandstone cores of 50 mD and 750 mD fitted into Particle Plugging Test (PPT) aparatus. The Scanning Electron Microscope (SEM) and elemental mapping was used to characterize filter cake and further investigating the particles invasion in the core samples. Finally, mud cake permeability of the samples was calculated using analytical models from litreture.

The constant bottom-hole pressure (CBHP) method of managed pressure drilling (MPD) maintains wellbore pressure above the wellbore stability or pore pressure and below the fracture pressure. It is common practice to perform frequent dynamic formation integrity/leakoff tests (FIT/LOT) to measure the fracture pressure. Several authors addressed the uncertainty in the measured value of the fracture pressure caused by mud compressibility and thixotropy. Moreover, field evidence indicates considerable variations in the effective fracture pressures resulting from varying wellbore temperatures. This paper presents a mathematical model, validated with field data, to estimate the effective fracture pressure (EFP) from the leakoff test data. The model accounts for the effect of mud compressibility and thixotropy, and considers the effect of transient wellbore temperatures on the geomechanical rock stresses. The study also presents application of quantitative risk assessment (QRA) to represent the probability density distribution of EFP associated with the uncertainties in the input paramaters. The method was demonstrated with two examples from the Gulf of Mexico. The study shows that the operational parameter–"pumps off" time, and two formation properties-Young's modulus of elasticity (E) and thermal expansion coefficient ( α T ) contribute most to the uncertainty in EFP. Moreover, a log-normal distribution of the EFP indicated a strong effect of temperature variation. It is also concluded that the uncertainty resulting from the temperature effect could be minimized by conducting the test after a characteristic 60-minutes pumps-off period.

Severe hole stability problems were encountered in a recent exploration well in the Norwegian North Sea. The problems occurred when drilling through Tertiary shale sections interbedded with permeable sand layers. Drilling was initially performed with water based drilling fluid. However, being unable to reach the section target after more than two weeks of operation, the section was plugged back and a sidetrack was drilled using an oil based drilling fluid without encountering major operational problems. On the basis of the post-drill analysis of drilling data, well logs, drill cuttings and borehole cavings sampled from the well, this paper describes how the complex combination of drilling fluid salt concentration and geological constraints may be utilized to ensure successful future drilling operations in this part of the North Sea. Cuttings and preserved cavings collected during the drilling operation were selected from several depth intervals identified as potentially troublesome from drilling experience and log data. Determination of cuttings mineralogy enabled better prediction of how the time dependency of the stable drilling fluid density window is influenced by interaction between the shale and the drilling fluid. Mechanical strength is a key input parameter when predicting borehole stability. Dedicated rock mechanical punch measurements on cavings were used to confirm the prediction of strength from log data alone. Examination of caving surfaces revealed the possible presence of in-situ fractured rock. Such fractures would require special measures while drilling to maintain stability. Subsequently a borehole stability sensitivity analysis was performed focusing on time dependent stability in the shale formations. The analysis used cuttings and cavings properties and logs as input. In particular, the modelling showed how the optimum KCl concentration in the drilling fluid changes with depth. The modelling further identified a relatively large sensitivity towards borehole inclination – even at fairly small inclinations. This paper thus illustrates the significance of properly accounting for rock mechanical aspects when planning new wells.

Geomechanics and hydraulics modeling are commonly used to optimize drilling performance and to reduce non-productive time (NPT). The geomechanics model indicates safe mud weight parameters, optimum casing points, and wellbore stability analyses. The hydraulics model simulates the wellbore and drilling fluid parameters to optimize the flow rate and rate of penetration (ROP) within equivalent circulating density (ECD) constraints. Real-time drilling data are used to update the models: the pore-pressure/shear-failure gradient and fracture gradient boundaries for geomechanics; and ECD, circulating system pressure drops, and annular cuttings load parameters for hydraulics. Each real-time model strives to ensure that operations are optimal, safe, and cost effective, as well as to provide updated models for future planning purposes. This paper focuses on collaboration between geomechanics and hydraulics analysts in the planning, drilling, and postdrilling phases of the well. A geomechanics model determines the safe mud weight operating window and casing points, whereas the hydraulics model simulates ECD for defined mud properties, drilling parameters, and wellbore geometry. A synthesis of the two models enables the previously mentioned information to be compared and merged before spudding the well. Real-time collaboration between models enables each model to be updated with pertinent information from the other, ensuring that drilling operations are performed within optimum mud weight and ECD constraints. The geomechanics model can use real-time ECD data from the hydraulics model when a pressure-while-drilling (PWD) tool is not being used. In turn, the hydraulics model requires updating when the safe mud weight limits are being exceeded. The two models can each use information from the other when performing the post-well analysis and planning for the next well. Both models are valuable tools when used individually, but they become powerful, superior companions when used in conjunction with one another.

Historically, extended reach offshore wells in Trinidad & Tobago were characterized by wellbore instability and hole cleaning challenges. These phenomena had become almost impossible to manage effectively in the highest angle wellbores, leading to levels of non-productive time (NPT) that threatened the economic viability of the latest development. Wellbore instability exacerbated the hole cleaning challenge, fueled by a new instability mechanism at highest wellbore inclinations. This led to pack-offs and stuck pipe incidents. Additionally, poorly understood and generally insufficient hole cleaning practices increased stuck pipe risk, and also caused the equivalent circulating density (ECD) to rise, resulting in mud losses due to the narrow window between mud density required for wellbore stability, and formation fracture gradient. The solution to these problems was found through advanced downhole measurements of borehole stability and hole cleaning, transmission of those data back to surface via a high frequency medium ("networked or wired" drill-pipe), deployment of subject matter experts into the rig team for critical phases of the operation, and introduction of unconventional drilling and decision-making practices to mitigate the problem phenomena. This paper describes the transformational efficiency improvement that was achieved by this combination of new technology, improved workflows, and multidisciplinary expertise deployed to the rigsite. The methodology was implemented on the third well, resulting in a reduction of NPT from 47% and 48% on the first two wells, to 10% on the third, clearly expressing the enhanced control of these drilling phenomena on the third well. Recommendations offered are relevant to many extended reach drilling campaigns, and may be critical to the success of ultra-ERD wells.

Lithologies under deepwater conditions usually show relatively reduced effective stress, due to the reduced lithostatic column. This translates into relatively narrow mud weight windows, driven mainly by shear failure or pore pressure in overpressured conditions, and by minimum horizontal stress gradients. Drilling operations should consider wellbore collapse, kick and losses as the primary geomechanics-related drilling hazards. These should be investigated and predicted during well planning, and should also be appropriately monitored during drilling, especially when an appraisal campaign will require highly deviated wells. Real-time geomechanics is defined as a workflow that takes into consideration mud weight window planning, identification of geomechanics-related drilling hazards and possible mitigation actions, and, while drilling, operations monitoring by real-time data acquisition and interpretation, drilling occurrences detection, drilling practices revision, and the real-time update of mud weight window for further drilling. The authors present the case study of a drilling campaign in Chevron operated Rosebank Lochnagar Discovery, deepwater West Shetland, in almost 3,700-ft water depth. This campaign had the goal of proving the development concept of drilling horizontally in a field where the previous maximum inclination was only 35 degrees. The planning phase consisted of mud window modeling using a mechanical earth model from offset wells. Potential drilling hazards were then identified and synthesised using a Drilling Roadmap as a drillling planning and management tool. The monitoring phase consisted of real-time detection, from analysis of logging-while-drilling and wireline data, of drilling hazards typical in the area, such as cavings, losses, and packoffs. Data interpretation required a multidisciplinary team of geologists, petrophysicists, geomechanics engineers, and drilling engineers. The application of real-time geomechanics allowed an improvement in operations, safe drilling practices, and refined calibration of the 1D geomechanical model for further drilling campaigns.

The benefits of formation pressure testing while drilling include improved formation evaluation, drilling hazard mitigation, drilling performance optimization and saving time. In deepwater wells offshore Angola, this is regularly used in 12 ¼-in. and smaller hole sections. The requirement extended to the 17 ½-in. hole sections which are typically directionally drilled with high buildup rates due to the reservoir being located at a relatively shallow depth below the seabed. The plan was to adapt the formation pressure testing equipment already used in 12 ¼-in. hole and establish a technique to use it in 17 ½-in. hole. This was complicated by the high buildup rates in the 17 ½-in. hole, as opposed to the high-angle tangents seen in the 12 ¼-in. hole sections. The unconsolidated nature of the formation further complicated the process as the low compressive strength of the rock can prove challenging for directional steering and the friability of the formation could affect both the seal of the formation pressure tester and its ability to sample pressure. This paper will discuss development of the techniques over the initial wells, issues that were encountered and solutions developed to simultaneously deliver the formation pressures and the directional profiles using standard equipment. In addition, the paper will discuss how the techniques developed for the 17 ½-in. hole were further adapted to sample formation pressures when these had to be measured in 13 ½-in. hole below 9 ⅝-in. casing in situations where conventional formation pressure testing techniques could not deliver data. As a result, the paper describes the successful deployment of real-time formation pressure testing in large hole sizes whatever the directional challenges.