Open Hole Gravel Pack (OHGP) completions have been the primary completion type for production wells in the Azeri-Chirag-Gunashli (ACG) field in Azerbaijan for 20 years. In recent years, it has been required to use well bore strengthening mud systems to allow drilling the more depleted parts of the field. This paper describes the major engineering effort that was undertaken to develop systems and techniques that would allow the successful installation of OHGP completions in this environment. OHGP completions have evolved over the last 3 decades, significantly increasing the window of suitable installation environments such that if a well could be drilled it could, in most cases, be completed as an OHGP if desired. Drilling fluids technology has also advanced to allow the drilling of highly depleted reservoirs with the development of well bore strengthening mud systems which use oversized solids in the mud system to prevent fracture propagation. This paper describes laboratory testing and development of well construction procedures to allow OHGPs to be successfully installed in wells drilled with well bore strengthening mud systems. Laboratory testing results showed that low levels of formation damage could be achieved in OHGPs using well bore strengthening mud systems that are comparable to those drilled with conventional mud systems. These drilling fluid formulations along with the rigorous mud conditioning and well clean-up practices that were developed were first implemented in mid-2019 and have now been used in 6 OHGP wells. All 6 wells showed that suitable levels of drilling mud cleanliness could be achieved with limited additional time added to the well construction process and operations and all of them have robust sand control reliability and technical limit skins. Historically it was thought that productive, reliable OHGP completions could not be delivered when using well bore strengthening mud systems due to the inability to effectively produce back filter cakes with large solids through the gravel pack and the ability to condition the mud system to allow sand screen deployment without plugging occurring. The engineering work and field results presented demonstrate that these hurdles can be overcome through appropriate fluid designs and well construction practices.

Ensuring wells’ cement mechanical integrity (CMI) is of paramount importance for the success of a thermal project. Failed cement sheaths can lead to loss of production, environmental pollutions, or even to well abandonment. Over time, CMI software applications have been developed to design wells that do not leak. However, their efficiency depends not only on if their equations are verified, but also on how the models are validated versus wells’ downhole conditions. Unfortunately, most CMI tool designers have focused on only verifying if the models are mathematically correct, checking what is the time required for a simulation, and improving how are the simulations reported to the user. Typically, little time is dedicated on validating that the correct model is used for the specific well. This foresight has led to non-predictive CMI tools, which do not allow optimizing well designs. The authors have been involved for more than 15 years in developing and validating CMI models. They have shown the importance of simulating the cement hydration to evaluate the state of stress in the cement after it has set. They also have highlighted how the plastic behavior of the cement design can lead to opening micro-annuli at the cement-sheath's interfaces. Recently the authors have started theoretical work in the area of the cement integrity of high and ultra-high temperature wells and how these temperatures, either naturally occurring or induced, could affect the cement's mechanical integrity. The work has focused on modeling the increase in pore pressures, the opening of micro-annuli at the cement sheath's boundaries, and the phase changes which take place in the cement when it is heated to high temperature values. To date this work showed that heating cement up to 250°C can result in pore pressures larger than 100 MPa unless if the pore pressures can be released. This work has also identified three mechanisms that can lead to such release of pore pressures: 1) During cement hydration, due to the water consumption by the chemical reactions, 2) When a micro-annulus opens due to the large pore pressures, therefore allowing venting the pressures to the surface or to a downhole reservoir, and 3) When a change of phase occurs in the cement when heated to more than 110°C, as this leads to the creation of additional porosity in the cement. All this means that the cement sheath should not be simulated as a closed system, but rather as an open thermo-hydro-chemo-mechanics. How these features impact CMI has never been studied before even if they can explain why some cement designs lead to tight cement sheath and other to leaking ones. This paper highlights the work that has been done and when these conditions should be considered, and if it is feasible to design cement sheaths that do not fail, even at very high temperatures.

An improved flow assurance solution based on a new additive with robust performance, low treat rate and versatile handling properties was developed successfully. It was applied in a waxy crude oil from West Africa with high pour point and a wax content of about 24%. Crucial for the project success was a close collaboration among all involved stakeholders from operator, service company and chemical supplier. In the initial lab screening by the chemical supplier, tests focused on pour point, viscosity and yield stress. This approach allowed to identify the most efficient type of additive chemistry for the specific crude oil and to meet target performance requirements. Crude oil viscosity and yield stress under pipeline operation conditions could be reduced by more than 95% while reducing the required amount of additive by more than 75% compared to the incumbent solution. This resulted in significant cost savings for the operator and in a reduction of the Health, Safety and Environmental (HSE) exposure.

Pressurized Mud Cap Drilling (PMCD) technique is typically applied for drilling formations with natural fractures and large vugs that result in severe or total losses. The density of the drilling fluid used in PMCD is slightly below reservoir pore pressure. In the case of very low reservoir pressures below base oil densities (~6.7 ppg), foam can be an option. This paper presents a methodology to develop an oil-based foam system for a PMCD application. The scope includes the descriptions of a foam PMCD application, functional requirements of foam, the development workflow, testing procedures, and modeling that are necessary to qualify a foam for PMCD application. The development methodology first involves identifying the constraints and well conditions of a given PMCD application; these include wellpath, hole and casing sections, reservoir pressure and temperature, surface pumping pressure limits (typically a rotating control device limit), foam stability requirements, etc. The above constraints drive the performance requirements for the foam. Next comes the design of the foam formulation and evaluating its performance against these requirements through various lab tests and modeling efforts, which can include ambient pressure half-life tests for initial screening, static and rotational stability tests at in-situ well conditions, rheology tests, solubility tests, pressure transmission estimates, gas migration estimates, and hydraulics modeling. Example results from the lab tests and modeling are shown to provide more insights into the development process. The proposed methodology may be used as a guide to design a foam drilling fluid for a PMCD application. The iterative nature of the development method is shown and is driven by the functional requirements that are coupled to each other. For example, a more viscous foam may be more stable but it may not be pumpable. Likewise, a less viscous foam may be pumpable but may not be sufficiently stable. Similarly, a highly compressible foam may not be good at pressure transmission to monitor downhole pressure variations as compared to a less compressible foam. In summary, the methodology described in this paper explains the development of an oil-based foam for a PMCD application that satisfies a set of operational constraints and functional requirements while highlighting the major factors that could impact foam performance. The application of foam to PMCD is a new concept and to our knowledge has not been applied in the field; in significantly depleted reservoirs this may become a viable option.

In certain regions of oil and gas operations, lost circulation is a common occurrence, especially when a majority of the openhole exposed during primary cementing is carbonate-based formations. This can lead to lost circulation risks in most applications. To overcome lost circulation risks during primary cementing, a new tailored spacer system shows to improve the cement placement success. The manuscript discusses the quality assurance and performance testing with field cases demonstrating the value contributions of the spacer for achieving zonal isolation requirements as well as the top of cement objectives. The work efforts presented shows a spacer meeting and sometimes showing incremental wellbore strengthening in comparison to the published literature for existing available spacers used to overcome similar lost circulation risks.

Lost circulation problems may result in a significant downtime, a considerable reduction of the rate of penetration, or even well control problems. Despite advances in manufacturing lost circulation materials (LCMs), some formations, like heavily fractured carbonates, have complete losses during drilling. We develop smart LCMs using shape memory polymers (SMPs), and program them thermo-mechanically to satisfy size limitations imposed by bottomhole assemblies (BHA). Elevated downhole temperatures act as an external trigger to recover the permanent shape of LCMs, which could expand ten times larger than the temporary (programmed) dimensions for deployment. Smart LCMs are a combination of various material categories such as granular, fibrous (one-dimensional or 1-D) and planar (two-dimensional or 2-D) configurations that resume to the original shape after exposure to high temperatures. The LCMs form different structures such as flatted pellet, disc-shaped, spider-shaped, and spindled, which, respectively, presents grains, 1-D fibers, 2-D stars, and 2-D lattices after recovery. A combination of the above categories attempt to build three-dimensional (3-D) plugging capabilities across various sized fractures.

Matrix acidizing with fluoroboric acid (HBF 4 ) has gained special attention as not only it provides deeper penetration of in – situ generated hydrofluoric acid, but also stabilizes formation fines by binding them to the pore surface. While numerous mathematical models exist in literature for design and evaluation of conventional mud acid treatments, fewer attempts have been made in developing a lab validated model that can do so for fluoroboric acid treatments. This paper presents a novel mathematical model that has been developed taking into account the chemical kinetics and equilibrium aspects of important reactions and fluid flow inside the reservoir rock. The solution to the governing equations has been obtained through tools of computational fluid dynamics (CFD). The model has been validated rigorously through use of state-of-the-art core flooding and ion chromatography setups. The resulting simulator can be used to design an optimum fluoroboric acid treatment by analysing the effects of all the important factors including reservoir temperature, formation mineralogy and job execution details like initial acid concentration, pumping rate, job volume and shut-in time post treatment. Simulation results with the developed model indicate that although penetration of fluoroboric acid is much larger compared to mud acid, its overall effect on skin factor is inferior for temperatures less than 90 °C. Stimulation in such wells should be preferred with mud acid which can be followed by fluoroboric acid for fines stabilization. For temperatures more than 120 °C, stimulation effects of fluoroboric acid become comparable to that of mud acid. Under these conditions, it can be used as an alternate fluid to mud acid to prevent issues of secondary and tertiary precipitation. It is found that major stimulation benefits with fluoroboric acid are realized during pumping and subsequent shutting of well, which is a common practice with fluoroboric acid, has relatively smaller effect on skin factor. Apart from design and evaluation of fluoroboric acid treatments, the simulator can also be used for analyzing mud acid and mud acid followed by fluoroboric acid treatments thus enabling the user to select and design the best suited treatment for a given well.

Successful coiled tubing (CT) descaling interventions require control of several key aspects, including fluid leakoff into the formation, proper surface solids handling, and controlled hydrogen sulfide (H 2 S) release at the surface. Successful treatment control is achieved by monitoring the surface and downhole parameters. The recently introduced pressure and fluid management system, crosslinked foam-based fluid, and a fluid mixing system for CT descaling treatments pose challenges that require enhancements to these elements for successful treatment. The pressure and fluid management system was enhanced to include a new high-rate mud/gas separator to 1) increase gas/fluid separation capacity and avoid foam flowing to flare, 2) rig up the flare line with inclination to allow all water to be drained and prevent formation gas flowing to flare lines, and 3) increase retention time for better foam breaking and material settling. A liquid flowmeter was also added to improve influx and leakoff control by monitoring the volume of liquid injected and matching the volume of liquid returned on surface in addition to the level gauges on the return tanks of the pressure and fluid management system. The foamed-based fluid breaking system and H 2 S presence in returns were mitigated by removing crosslinker and introducing an H 2 S scavenger on returns whereas foam breaking was enhanced by additional breaker injection points on returns. Fluid mixing capabilities were enhanced by the introduction of an on-the-fly continuous mixing system that sped up and simplified the mixing process. The mud/gas separator efficiently separated the gas from liquid, leading the gas to be burnt at flare and the liquid to be processed in the pressure and fluid management system. It further helped in preventing the liquid flowing to flare, which lessened the risk of flare shutdown and H 2 S ventilation. The on-the-fly continuous mixing system provided a faster and more-efficient mixing process as an alternate to batch mixing. These system-controlled metering, mixing, and monitoring capabilities significantly reduced the crew and equipment footprint, leading to minimizing the health, safety, and environment (HSE) concerns and cost savings. The fluid flowmeter allowed efficient choke and bottom-hole pressure control. Fluid flowmeter readings helped in choke and bottom-hole pressure reading adjustments based on amount of fluids pumped and matching the same amount of fluids returned at the surface. It prevented the fluid leakoff into the formation or influx of gas into the wellbore. Additionally, this new process created better control of downhole differential pressure during the scale cleanup and transportation. This project integrated different technologies and techniques that can be utilized for descaling treatment enhancements. The recent enhancements to the CT descaling operation resulted in greater efficiency, cost savings, reduced formation damage, and safe operations.

There are advantages to using high performance lightweight cement when encountering low bottomhole pressures. The most notable are maintaining wellbore stability during cement placement and the isolation of potential flow zones to achieve the wellbore construction objectives. Several complex wells sought these advantages for similar situations. A review of the deployment process for using high performance lightweight cement conventionally, including the quality assurance measures, initially deemed it as not a viable option. As the complex wells needed a technical solution, an unconventional deployment method for high performance lightweight cement enabled its use while simplifying and improving quality assurance; allowing achievement of the isolation requirements.

Carbonate reservoirs are challenging for chemical EOR, particularly in selecting fine-tuned chemical formulations which combine high performance, stable behavior, and trouble-free operations. The design of suitable formulations requires substantial laboratory work and a solid methodology. In this paper, a systematic all-inclusive laboratory workflow to design a surfactant-polymer (SP) formulation for a carbonate reservoir is presented. In this work, a complete process for development and evaluation of an SP formulation for high-salinity high-temperature conditions is proposed and adopted. For which, a high throughput robotic platform is used for efficient and robust formulation design. The process is illustrated on an actual case with harsh reservoir conditions (i.e. a high temperature of 100℃ and high connate salinity of 213,000 mg/L). The SP design methodology consisted of five steps: surfactant design, polymer selection, surfactant/polymer verification, topside assessment, and oil-displacement evaluation. The surfactant formulation design consisted of four substeps: solubility scans, phase-behavior scans (salinity scans), IFT measurements, and static adsorption tests. The sourced polymers were screened based on three key performance indicators: viscosity, filter ratio, and thermal stability. The selected surfactant formulations and polymers were then assessed as sloppy slugs in terms of compatibility and injectivity. Then, the unique topside assessment was conducted where it consisted of two components focusing on: separation kinetics and separated water quality. Finally, an oil displacement study was performed using a preserved composite plug, in which the SP formulation developed through the outlined process was used. The results demonstrate the potential of a mixture of Olefin Sulfonate (OS) and Alkyl Glyceryl Ether Sulfonate (AGES). The results also illustrate couple of polymers with stabilities suitable for high temperature conditions: an associative polymer, and an AM/AMPS copolymer. In addition, injectivity corefloods supported the SP slug transportability across the porous media. Corefloods also demonstrated the SP slug capacity to recover around 62% ROIC (remaining oil in core). Finally, SP in produced brines improved the separation kinetics but lead to a slight deterioration in separated water quality. A key novelty of the adopted workflow is the integration of topside assessment. In addition, the experimental steps were clearly delineated including the preparation of representative oils. Beside a clear layout of the methodology, the work demonstrates that a surfactant-polymer formulation can successfully be designed for high temperature carbonate reservoirs and provide encouraging guidelines with respect to SP impact on topside facilities.

Hole cleaning efficiency is one of the major factors that affects well drilling performance. Rate of penetration (ROP) is highly dependent on hole cleaning efficiency. Hole cleaning performance can be monitored in real-time in order to make sure drilled cuttings generated are efficiently transported to surface. The objective of this paper to present a real time automated model to obtain hole cleaning efficiency and thus effectively adjust parameters as required to improve drilling performance. The process adopts a modified real time carrying capacity indicator. There are many hole cleaning models, methodologies, chemicals and correlations, but majority of these models do not simulate drilling operations sequences and are not dependent on practicality of drilling operations. The developed real time hole cleaning indicator can ensure continuous monitoring and evaluation of hole cleaning performance during drilling operations. The methodology of real time model development is by selecting offset mechanical drilling parameters and drilling fluid parameters where collected, analyzed, tested and validated to model strong hole cleaning efficiency indicator that can extremely participate and facilitate a position in drilling automations and fourth industry revolution. The automated hole cleaning model is utilizing real time sensors of drilling and validate the strongest relationships among the variables. The study, analysis, test and validation of the relationships will reveal the significant parameters that will contribute massively for model development procedures. The model can be run as well by using the real time sensors readings and their inputs to be fed into the developed automated model. The developed model of real time carrying capacity indicator profile will be shown as function of depth, drilling fluid density, flow rate of mud pump or mud pump output, and other important factors will be illustrated by details. The model has been developed and validated in the field of drilling operations to empower the drilling teams for better and understandable monitoring and evaluation of hole cleaning efficiency while performing drilling operations. The real time model can provide a vision for better control of mud additives and that will contribute to mud cost effectiveness. The automated model of hole cleaning efficiency optimized the rate of penetration (ROP) by 50% in well drilling performance as a noticeable and valuable improvement. This optimum improvement saved cost and time of rig and drilling of wells and contributed to accelerate wells’ delivery. The innovative real time model was developed to optimize drilling and operations efficiency by using the surface rig sensors and interpret the downhole measurements and that can lead innovatively to other important hole cleaning indicators and other tactics for better development of downhole measurements models that can participate for optimized drilling efficiency.

Different applications of fracture bridging and diversion are used regularly in carbonate acid fracturing without an in-depth understanding of the physical phenomena that dominate the processes involved in the bridging and diversion process. The extension of modeling capabilities in conjunction with yard-scale and field-scale experiences will increase our understanding of these processes. A robust multimodal diversion pill and polylactic acid fiber-laden viscous acid were utilized for near-wellbore and far-field bridging, respectively. Numerous field treatments demonstrated the uncertainty of achieving effective diversion. An existing multiphysics model was extended to develop functionalities to model diversions at different scale. Extensive laboratory testing was conducted to understand the scale of bridging and diversion mechanisms. Finally, a bridging yard test was designed, and field case studies were used to integrate all the branches. Field cases showed a diversion pressure up to 4,000 psi depending on perforation strategy, pill volume, and pill seating rate. Correlations showed the interdependence of multiple parameters in diversion processes. The field studies motivated modeling capabilities to simulate the critical diversion processes at high resolution and quality. The model simulates diverting agents that reduce leakoff in the fracture area and their effects on fracture geometry. The approach considers the acid reaction kinetics coupled with geomechanics and fluid transport. Different diverting agent concentrations required for bridging can be modeled effectively. A yard test was designed to confirm the integrity of the pill material through completion valves (minimum inside diameter 9.5 mm) and analyzed with high-resolution imaging. All the theoretical, mathematical, and numerical findings from modeling were integrated with laboratory- and yard-scale experimentation results to develop and validate near-wellbore and far-field diversion modeling. Analytical correlations were formulated from injection rate, particulate material concentration, pill volumes, fracture width, etc., to incorporate and validate the model. This study enhances understanding of the different diversion mechanisms from high-fidelity theoretical modeling approach integrated with a practical experimental view at laboratory and field scale. Current comprehensive research has significant potential to make the modeling approach a reliable method to develop tight carbonate formations around the globe.

The estimation of the drilling window limits ensures that lost circulation and wellbore instability events are minimized. These limits are conventionally defined during the pre-drilling phase based on offset wells data. As drilling commences, mud weights are selected to fit within these limits and they can be adjusted to react to different drilling scenarios as long as they don't violate the defined limits. This process fails to consider the effect of the initial mud weight and its subsequent adjustments on the strength of the wellbore. The concept of stress hysteresis dictates that when a body is subjected to a certain load, such as the one exerted by the hydrostatic pressure of the mud, its state will be altered in a manner that can shift its strength limits. This work presents a model that quantifies the changes in the drilling window due to variations in mud weight. The objective is to ensure that any subsequent mud weight changes will fall within the updated drilling window limits. The analysis is carried out using a novel process of a 3D poro-elasto-plastic finite element model (FEM) that is integrated with a machine learning (ML) algorithm. The integrated FEM-ML model uses offset wells data along with the best fitting failure criterion to estimate the initial limits of the drilling window. The offset wells data used consist of wireline logs, drilling reports, and mechanical testing lab results belonging to the formation of interest. The integrated model uses this data to estimate the stress distribution and learn the failure patterns. The model is then used to run different scenarios of mud weight variations while drilling a specific hole section to quantify their effect on the drilling window. The end result of each scenario is an update of the drilling window, which reflects the effect of stress hysteresis. When examining the initial estimations of the drilling window against those reflecting the stress path effect, a significant discrepancy in the window size is quantified. This examination is carried out for an offset well, which experienced multiple mud weight changes as a response to various drilling events. Subsequently, the changes in the drilling window and the actual mud weights used are analyzed in view of the drilling difficulties experienced in that specific offset well for the purpose of providing a form of validation. The model results show that the drilling window had shrunk significantly enough for the mud weight to violate the wellbore stability limit. Failure to consider the stress hysteresis effect in this well led major wellbore instability, tight hole, and overpull. The modelling effort presented in this work allows for a new aspect of dynamic responses to drilling events as they occur.

With rising energy demand, operators in the Middle East are now focusing on developing unconventional resources. To optimize hydraulic fracture stimulation, most of these deep gas wells are required to be drilled laterally and in the direction of the minimum horizontal stress. However, this poses an increased risk of stuck pipe due to hole instability, differential sticking and skin damage due to high overbalance pressures, which makes drilling these wells challenging and costly. Another major challenge in the Middle East is lost circulation due to natural fractures in carbonate reservoirs. Lost circulation currently accounts for loss of approximately $850-900 million USD per year globally across the industry ( Marinescu 2014 ). This paper presents a case study where a holistic approach; combining geomechanics and drilling technologies were employed to address the drilling challenges specific to unconventional and naturally fractured reservoirs. Ultimately, this approach helped the client to mitigate stuck pipe issues, while proposing a physics/engineering-basedmethodology to reduce losses by sealing fractures, hence providing a roadmap to optimized drilling and mitigation of hazards with associated Non-Productive Time (NPT). The paper demonstrates a holistic approach, combining wellbore stability analysis, managed pressure drilling (MPD) and proposes a novel physics/engineering-based methodology for addressing lost circulation challenges. A 1-D wellbore stability model is initially developed to determine the safe operating downhole pressure limits and to effectively assess the drilling risks associated with the planned wellbore orientation. By accurately determining the required bottomhole pressure to prevent wellbore stability problems, managed pressure drilling technology can be implemented to provide improved drilling hazard mitigation by enabling reduced overbalance pressures, constant bottomhole pressure, and faster reaction time by instantaneously adjusting downhole pressures. A bi-particulate bio-degradable system is used as a lost circulation material (LCM). The bigger size cylindrical particles flowing at a pre-defined rate will form a bridge or a plug across the fracture aperture, providing mechanical stability and the smaller spherical particles will seal the gaps in the bridge there by providing an effective sealing of the fracture opening. From experience, implementing these methodologies and technologies in isolation has not provided satisfactory results. This indicates that a partnership which leverages the strengths of the individual disciplines from the early planning stages is necessary to effectively address the drilling challenges posed by unconventional and naturally fractured reservoirs. For the case study highlighted in this paper, the well was drilled to TD in a timely manner, while maintaining the integrity of the hole, hence confirming the viability of this approach. In addition, the physics and engineering design workflow for bi-particulate bio-degradable LCM demonstrates how it can be effectively deployed to mitigate lost circulation without skin damage to the formation

Managed pressure drilling (MPD) has a reputation for enhancing drilling performance. However, in this study, we use it as a technology for making undrillable wells drillable. In the deepwater of the Mediterranean of Egypt, a gas field has been producing for few years. Water broke through in one well, thus, we must drill a new well to compensate for the reduction in production. Years of production led to pressure depletion, which makes it difficult to drill this well conventionally. In this study, we will discuss the combination of MPD and wellbore strengthening (WS). In addition, we will discuss the challenges we met while drilling and how we tackled them, and the best practices and recommendations for similar applications. The 12¼" × 13½" hole section passed depleted sands, followed by a pressure ramp. First, we drilled the depleted sands and confirmed the pressure ramp top. To strengthen the sand, we spotted a stress-cage pill of 645 bbls with a total concentration of 29 ppb. In addition, we conducted a formation integrity test (FIT), but its value was lower than the required value to drill to the section target depth (TD). Then, we switched to MPD and increased the mud weight. MPD in annular pressure control mode (AP) enabled us to walk the edge as near as possible to the impossible. Drilling this section was challenging due to the narrow mud weight window (MWW). We faced kick-loss cycles, where we had high-gas levels (from 20% to 55%) while drilling with a loss rate from 60 to 255 bph, at the same time. The 8½″ × 9½″ hole section will cover a depleted reservoir. Therefore, we decided to use the MPD to drill this section. To widen the MWW, we decided to stress-caging the hole, as we drill. We loaded the active-mud system with stress-cage materials totaling 39 ppb. We drilled the hole section while keeping the bottom hole pressure (BHP) at 14.6 ppg. We drilled using MPD by maintaining 525-psi surface back pressure (SBP). We used the SBP mode (semi-auto mode) to add connections, resulting in minor background gases and minor losses. This study discusses the application of a novel combination of MPD and WS. It emphasizes how MPD can integrate with other technologies to offer a practical solution to future drilling challenges in deepwater-drilling environments.

Polyacrylamide-based friction reducers (FR's) - including viscosifying polyacrylamides, which are designed to decrease proppant settling by increasing molecular weight and/or active material in the FR - are used extensively in high-rate fracture stimulations. However, because polyacrylamides are difficult to break, there have been concerns about how these materials impact fracture conductivity and formation permeability. This study presents the effect of conventional and novel oxidative breakers over the viscosity and colloidal size distribution of the broken polymers. Breakers tested include conventional persulfates, perborates and patent pending peroxides, all of which generate free radicals to degrade partially hydrolyzed polyacrylamides (PHPAs). Breakers were tested at bottomhole temperatures encountered in the Permian, Bakken, Haynesville and Eagle Ford. Changes to PHPA viscosity were determined using vibrational viscometers. Size distributions and percentage of the broken colloidal PHPA were determined by dynamic light scattering. This method can measure sizes down to 0.6 nanometers, which is within the range of even the smallest pore-throat sizes in shales. Light scattering revealed surprising anomalies in breaker performance. When aged at temperatures typical of the Permian, each of the tested breakers at each of the varied concentrations caused similar levels of viscosity reduction but different size distributions. Some breakers had the unwanted effect of narrowing the colloidal size fractions to the lower end of the spectrum. At these small sizes, colloids are more likely to overlap with segments of the pore throat distribution in some shales, which could inhibit production. In addition, when the FR was aged at the higher temperatures encountered in the Bakken, Eagle Ford and Haynesville, some breakers were not able to uniformly break the PHPA. In these cases, FR's without breakers delivered superior performance. The results clearly demonstrate that breakers may not always have the desired effect of increasing the formation's permeability. In fact, depending on the type of breaker and the concentration, they can often have detrimental effects that ultimately hinder production.

The deepwater development field in the western Gulf of Mexico (GoM) presents an array of complex challenges for ultra-deepwater drilling operations. The four well campaign was particularly challenging due to extreme water depths, remote location, well trajectory and a narrow pressure environment, 350-100 kpa (50-150 psi), for extended reservoir laterals. The authors highlight the use of innovative technology employed to drill and complete wells in the western GoM deployment, coupled with the first-ever use of controlled mud level (CML), managed pressure drilling technology in the Gulf of Mexico. The approach of selecting the fluid systems to achieve the objectives and the use of hydraulics modeling software with CML modeling capability in the design, planning and execution phases of the project allowed for fluid design optimization. The results were a successful drilling and completion campaign managing multiple fluids systems and operations on an ultra-deepwater, dual-activity drill ship in water depths more than 8,500 ft (2,591 m). The authors discuss the initial use of a low equivalent circulating density (ECD), flat-rheology synthetic based fluid (SBF) designed for narrow margin drilling applications and the transition to the deployment of a newly developed high-performance water-based mud (HPWBM) optimizing the operations to drill the intermediate intervals for final two wells. The authors also will discuss use of the reservoir drill-in fluid (RDF) and solids-free screen running fluids (SF-SRF), designed specifically for use in these open holes, gravel pack completions at hole angles upwards of 90°. Operational efficiencies derived from use of these fluids include ECD management, hole cleaning, directional performance, reduction in downhole losses, and the elimination of non-productive time (NPT) in a narrow margin environment with no loss of rate of penetration (ROP). Additional efficiencies include the seamless transition from derived from use of water-based fluids for drilling and completion phases. Use of the CML technology allowed for precise control of the hydrostatic pressure on wells that previously would not have been technically feasible to drill or complete. The novel use of the newly developed HPWBM on this campaign enabled reduced health, safety and environmental (HSE) exposure impact, increased tank and rig cleaning efficiency, and the elimination of a wellbore cleanout run since the entire well was drilled with only water-based fluids. The fluids were successfully employed in the four wells drilled and completed in a managed pressure environment utilizing CML technology.

Aqueous fluids also refer as water-based drilling muds (WBMs) have considered as the most favorable WBMs, owing to their inherent advantages such as economically viability and environmentally benign characteristics. The major problems WBMs encountered is thinning of drilling fluids while drilling under high pressure high temperature. The detrimental rheological properties of WBMs under HPHT result into pipe sticking, low rate of penetration of the drill bit and requirement of high torque for drilling operations. The hydrophilic clays have been employed as viscosifiers in WBMs to maintain the rheological properties, albeit, their viscosifying characteristics have hindered in the presence of ionic species in the aqueous system at high temperature. These shortcomings can be tackled by developing an additive that can exhibit neutral surface changes and ability to undergo gelation at higher temperature. We have developed an additive functionalized with polar groups on anisotropic nano-platelets (LMS) through sol-gel technique. Spectroscopic and crystallographic characterization of LMS have proved the formation of layered structures with covalently linked polar functionalities. The viscoelastic studies were conducted on aqueous dispersion of these nano-platelets at different temperature, which revealed an unprecedented phenomenon -increase in gel strength at higher temperature, a key property required for ideal WBMs. LMS nano-platelet has shown formation of network structure in aqueous medium to boost storage modulus of the fluid. This additive can overcome the demerits associated with natural hydrophilic layered silicates and improve the rheological properties under challenging well conditions.

Recent studies highlight the significant role of drilling fluid elasticity in particle suspension and hole cleaning during drilling operations. Traditional methods to quantify fluid elasticity require the use of advanced rheometers not suitable for field application. The main objectives of the study were to develop a generalized model for determining viscoelasticity of a drilling fluid using standard field-testing equipment, investigate the factors influencing drilling fluid viscoelasticity in the field, and provide an understanding of the viscoelasticity concept. Over 80 fluid formulations used in this study included field samples of oil-based drilling fluids as well as laboratory samples formulated with bentonite and other polymers such as partially-hydrolyzed polyacrylamide, synthesized xanthan gum, and polyacrylic acid. Detailed rheological characterizations of these fluids used a funnel viscometer and a rotational viscometer. Elastic properties of the drilling fluids (quantified in terms of the energy required to cause an irreversible deformation in the fluid's structure) were obtained from oscillatory tests conducted using a cone-and-plate type rheometer. Using an empirical approach, a non-iterative model for quantifying elasticity correlated test results from a funnel viscometer and a rotational viscometer. The generalized model was able to predict the elasticity of drilling fluids with a mean absolute error of 5.75%. In addition, the model offers practical versatility by requiring only standard drilling fluid testing equipment to predict viscoelasticity. Experimental results showed that non-aqueous fluid (NAF) viscoelasticity is inversely proportional to the oil-water ratio and the presence of clay greatly debilitates the elasticity of the samples while enhancing their viscosity. The work efforts present a model for estimating drilling fluid elasticity using standard drilling fluid field-testing equipment. Furthermore, a revised approach helps to describe the viscoelastic property of a fluid that involves quantifying the amount of energy required to irreversibly deform a unit volume of viscoelastic fluid. The methodology, combined with the explanation of the viscoelasticity concept, provides a practical tool for optimizing drilling operations based on the viscoelasticity of drilling fluids.

When drilling from a deepwater semisubmersible rig, the operator encountered wells problems, including lost circulation, influxes, and ballooning, in the 14 3/4-in. hole section. Managed Pressure Drilling (MPD) equipment that helped to mitigate these issues specifically, when stripping in the hole with the bottom hole assembly through the Rotating Control Device (RCD) bearing assembly while managing surge and swab pressures, monitoring the well while displacing heavy mud into the open hole, conditioning the contaminated mud, removing gas from the well, and fingerprinting the flow back to verify ballooning against influxes, and finally stripping out of the hole. The operator experienced a total loss of circulation at the 16-in. liner shoe at 1,633m while drilling the 14 3/4-in. hole section. Several lost-circulation material (LCM) pills of different weights were pumped to cure the losses without success. Then the well was flow-checked, the gain was noted, and the well shut-in. Having the MPD chokes and the Coriolis flowmeter in place made it possible to adjust the surface back pressure (SBP) accordingly within a small operating window. As a result, the operator could achieve the key objectives of stripping the drillstring in the hole, stripping out of the hole, and rolling over to spot 1.88SG heavy mud on the bottom using the pump and pull method. After LCM was pumped and a hesitation squeeze performed, well operations were stabilized, and the casing was run to a 2,111m measured depth. Advanced flow monitoring enabled the MPD to determine the required SBP for balancing the well. MPD applied 60psi of SBP and noted a gain of 8.3bbl/hr from the flowmeter. Next, MPD applied 65psi SBP and the well was static. Then, MPD applied 70psi SBP, and the well took losses at a rate of 19bbl/hr. MPD allowed to successfully strip the BHA in the hole through the RCD bearing assembly to the shoe. Correct string displacement observed via the MPD Virtual Trip Tank, achieved by adjusting the SBP from 62psi to 125psi. The closed-loop circulating system enabled safely circulating and conditioning contaminated gas-cut mud in the hole back to homogeneous mud. MPD reduced SBP incrementally and fingerprinted flow back at every step to give assurance that well ballooning, and not influxes, caused the flow back. Dynamically adjusting SBP, coupled with advanced monitoring of the returns flow using the Coriolis flowmeter, enabled balancing the well despite the challenges of a mixed mud gradient in the annulus and a narrow operational window. The MPD riser consisted of an RCD below-tension-ring (BTR)-s, flow spool, and top and bottom crossovers. Rig modifications involved fabricating the fixed piping to allow integrating MPD equipment with the rig system.