Pressure Measurements Plus Simulation Help Differentiate Between Downhole Events

World's energy demand is on upsurge and Oil & Gas industry has been directed towards the exploitation of deepwater oil and gas resources. To make this operation successful petroleum industry is continuously demanding new innovative drilling technology that can be easily implemented. One of the constraints that hinders the deepwater exploration is its continuously shrinking narrow window between pore pressure and fracture pressure that further limits the reliability of old conventional riser drilling technique.Dual gradient drilling (DGD) is a managed pressure drilling that involves use of two different annular fluids for drilling a prospect providing a favorable annular pressure profile and simpler, safer & economical well design.In any of the rotary drilling operation, drilling hydraulics is the most complicated and least understood drilling variable as it involves complex relationship between drilling fluid, drill bit and formation. Riserless drilling, one of the type of DGD, eliminates the use of marine riser (u-tube is imbalance) and involves use of an additional subsea mud pump at seabed which, supplements to the complication for hydraulics computation as compared to conventional drilling.In drilling HPHT deepwater wells, drilling fluid is constantly exposed to its own column pressure and formations geothermal gradient which subsequently affects the mud rheology and density. These altered rheological parameters leads to inadequate hole cleaning and lowers the drilling efficiency. High temperature in the wellbore cause's fluid expansion and high pressure causes fluid compression and these changes get extremely severe as water depth and drilling depth increases. Hence it becomes necessary to consider the HPHT effects on Equivalent Circulating Density (ECD) and to correct & optimize the hydraulic program to ensure the best utilization of the hydraulic energy for effective hole cleaning.This paper presents a detailed study of Well hydraulics for riserless drilling considering the HPHT effect on Equivalent Circulating Density and its optimization so as to ensure riserless drilling operation is conducted in safe and effective manner. Also the paper is concluded with some recommendations on operational and design strategies.

For the period different drilling campaigns took place at the Tapi and Auca Fields, Ecuador. A downhole monitoring pressure tool helped identify some important pressure behaviors and scenarios. The ECD monitoring led to better wellbore cleaning, drop of mud weight detection not detected on surface and improvement of drilling operation times by deciding whether it was necessary to make short trips or not, based on the acquired data. All the gathered data allowed the creation of a database that will become the baseline to improve future drilling projects in those fields. The tool uses a quartz crystal type transducer that grants high resolution and accurate readings in real time and memory of annular pressures and bore pressures. Additionally, ECD (Equivalent Circulating Density) and ESD (Equivalent Static Density) measurements are calculated and this last one also defines an inherent value of the EMW (Equivalent Mud Weight). The tracing of these values show the performance of the drilling fluid and an ECD working frame could be defined to ensure effective cleaning of the well. In order to understand ECD, external factors affecting its behavior need to be denoted such as flow patterns, ROP or drilling fluid properties. Additionally, the applications of pressure records when performing FIT, CIT or LOT are explained. Different scenarios of how the data was analyzed, interpreted and the decisions taken during the operations are shown in this paper.

The conventional drilling approach of employing a drillstring and bottomhole assembly with bit for drilling purposes and eventually running a casing string includes several tripping operations that leave the wellbore open for extended periods of time as an alternative to drilling-with-casing operations where the bottomhole assembly is attached to the casing. This eliminates additional drillstring tripping as drilling and running casing are performed simultaneously. This type of application reduces the number of string trips needed to complete a section, thus saving operational time and associated costs. As the diameter of a casing is larger than a drillstring, this method generally increases the Equivalent Circulating Density (ECD) as pressure losses increase owing to the reduction of the open hole and casing string annulus area. Casing directional drilling operations provide a much narrower drilling window with regards to restrictions in the annulus thus increasing the chances of reaching fracture pressure compared with conventional drillstring operations. To negate the resultant increase in ECD, the rheological profile of the drilling fluid must be designed appropriately. This paper discusses a unique oil-based drilling fluid system weighted with treated micronized barite slurry (TMBS) that has more recently been developed and used successfully in the Eldfisk field of the Greater Ekofisk area, Norway. The drilling fluid system provides low viscosity and a relatively low flat rheology, reduced torque values, and superior sag stability, thus delivering a fluid of low ECD contribution, low-pressure peaks, very effective hydraulics performance and static stability. These exceptional fluid characteristics make the system an excellent solution for drilling sections where the difference between pore pressure and fracture pressure is narrow. This was particularly so in this case where the stability of the fluid from sag potential was crucial for the improved success of the drilling-with-casing operation. Any solids sag onto the latching tools or bottomhole assembly (BHA) with the casing could have caused interference. The system had been used before for differing hole conditions including managed-pressure drilling and extended-reach wells, in high-temperature, high-pressure (HTHP) wells, and now with competence in a casing directional drilling operation.

Summary 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, which are not suitable for field applications. The main objectives of this study were to investigate the factors influencing drilling fluid viscoelasticity in the field and develop generalized models for determining the viscoelasticity of a drilling fluid using standard field testing equipment. Ninety-three fluid formulations used in this study included field samples of oil-based drilling fluids as well as laboratory samples of water-based, invert emulsion and other oil-based fluids. Basic rheological characterizations of these fluids were done by using 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 by using a research-grade rheometer with double gap concentric cylinder geometry. Using an empirical approach, two noniterative models for quantifying drilling fluid elasticity were developed (one for unweighted and the other for weighted drilling fluids) by correlating test results from a funnel viscometer and a rotational viscometer to energy required to cause an irreversible deformation of the fluid’s elastic structure. The generalized models for the unweighted and weighted viscoelastic drilling fluids were able to predict the elasticity of drilling fluids with a mean absolute error of 4.67 and 5.28%, respectively. In addition, the models offer practical versatility by requiring only standard drilling fluid testing equipment to predict viscoelasticity. Experimental results showed that nonaqueous fluid viscoelasticity is inversely proportional to the oil-water ratio (OWR), and the presence of clay greatly debilitates the elasticity of the drilling fluids while enhancing their viscosity. In this paper, we present models for estimating unweighted and weighted drilling fluid elasticity using standard drilling fluid field testing equipment. Furthermore, we proposed a prudent approach for quantifying the viscoelastic property of a drilling fluid by measuring the amount of energy required to irreversibly deform a unit volume of viscoelastic fluid. The new models, combined with the recommended use of the energy dissipation (ED) concept, provide practical tools that can be used for developing optimum drilling fluid formulations and hydraulic programs for effective hole cleaning operations, improved equivalent circulating density (ECD) management, and mitigating barite sag problems.

Technology Focus The oil industry has always been innovative, even under adverse and challenging conditions imposed by the nature of upstream projects. In the past, drilling and completion activities have faced the complexity of the wells and tougher operational and environmental regulations with ingenuity and efficiency. Some prospects considered not feasible 5 years ago are delivering an attractive rate of return to shareholders after the implementation of new techniques. On a day-by- day basis, deepwater, extended-reach, slimhole, and environmentally sensitive drilling projects are reaching the limit of industry capability and pushing for faster evolution in terms of technology, equipment, and procedures. It is not rare anymore to deal with prospects that require pressure ratings of 20,000 psi, temperatures greater than 350°F, and measured depths to 40,000 ft. These challenging project characteristics are leading to a review of conventional techniques and the use of innovative technology for wellbore positioning in a thin oil column, long horizontal drilling and completion legs, extremely low fracture margin in deepwater wells, and downhole tool telemetry. In the case of extended-reach wells (ERWs), the extension of horizontal legs aligned with low gradient fracture in deepwater projects requires an appropriate pressure-management system to mitigate the effect of friction losses at bottomhole conditions. The horizontal legs of multilaterals and ERWs are reaching lengths of 11,000 to 12,000 ft, with corresponding high friction losses that preclude the setting of casing shoes at planned depth in conventional drilling methods because of the equivalent circulating density (ECD). This challenge becomes even more critical when dealing with deepwater environments. Techniques such as the Reelwell drilling method (RDM) and managed-pressure drilling (MPD) have advanced considerably in recent years and are now feasible alternatives to mitigate the ECD and, consequently, are helping the execution of ERWs onshore and offshore. For example, RDM has a unique flow architecture that uses a conventional drillstring combined with an inner string to form a dual-conduit drillstring. This arrangement allows the return fluid containing cuttings to be transported back through the inside of the drillstring, thus eliminating the ECD. RDM also has the advantage of increasing the drilling envelope for ERWs because of torque and drag reduction and optional hydraulic weight on bit caused by a piston-type arrangement at the drillstring. It is difficult to comment about all the new available technologies in this summary, but the following papers address other advancements that are making possible the continuity of drilling and completion activities in a responsible, safe, and feasible way. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 166143 Multilateral Wells in the Urucu Field of Western Brazil: Reducing Environmental Impact in the Amazon by Sandro Mendes, Petrobras, et al. OTC 23985 Combining Contemporary and Tested Technologies To Achieve Successful Deepwater Extended-Reach Completions by Ray Brister, Chevron, et al. SPE/IADC 168049 New Rotary- Shouldered Connection Expands the Capability of World-Record ERD Operation by S.R. Sanford, ExxonMobil, et al.

Replicating downhole conditions using real-time software helps reduce nonproductive time. Hydraulic outputs trend against sensor outputs, enabling event detection. Using real-time fluid properties with fluid tracking hydraulic software helps improve predictions for comparison, enabling faster and more reliable detection of downhole conditions. Two instances of real-time hydraulics simulators capable of tracking property changes of fluid and the positions of discrete fluid volumes within the wellbore were used. One simulator was used with a real-time fluid properties apparatus that provided full six-speed rheology and fluid density in real time. The second simulator used fluid updates provided by the mud engineer on location. The calculated equivalent circulating density (ECD) and predicted standpipe pressure (SPP) from the hydraulics software was compared to actual pressure while drilling (PWD) and measured SPP sensor outputs. The real-time fluid apparatus provided real-time rheology and density values consistently while drilling the section, and data was provided directly to the hydraulics simulator. Comparing ECD predictions with and without the real-time fluid properties made it possible to identify any improvements achieved using such equipment. Although both sets of data showed that the hydraulics simulator was highly accurate, using real-time fluid inputs enabled ECD predictions to trend considerably closer to the PWD measurements. The capability of tracking the predicted ECD against actual sensor outputs enables users to quickly determine deviations in sensor outputs associated with downhole conditions and to observe deviations occurring as a result of inconsistencies within the fluid system. Data presented in this paper are taken from some of the first global deployments of real-time fluid properties measurement equipment used in conjunction with real-time hydraulics software.

1. Abstract As exploring for oil and gas traps becomes more extreme in term of depths, the companies start to search for modern technologies and equipment for drilling under HPHT conditions. One of the challenges of HPHT deep water well is narrow margin between the fracture pressure gradient and pore pressure gradient, therefore prediction and control of well hydraulics is indeed vital. The solution for the HPHT deep water challenges is a technology of Managed Pressure Drilling (MPD). Riser less drilling is one of the types of MPD. It uses two different annular pressure gradients for maintaining required bottom hole pressure to drill a well This study presents a new approach for accurate determination and optimization of well hydraulics for MPD (Riser less drilling) under HPHT conditions. This approach depends on accurate prediction and determination of borehole temperature, mud density and pressure, mud rheology and hydraulics profiles inside wellbore under HPHT conditions. This work shows the comparison between well hydraulics that calculated by constant fluid properties (i.e independent on pressure and temperature conditions) and well hydraulics that calculated by taking into account the effect of pressure and temperature on fluid properties. This paper also shows the effect of drill pipe tool-joint, drilled cutting, annular eccentricity and drill string rotation pressure losses on well hydraulics for MPD. The objectives were achieved by designing computer simulator called ‘’HPHT MAT’’. A case study by using ‘’HPHT MAT’’ simulator to show the correct procedure for optimization the well hydraulics of MPD is introduced. The results show that accurate prediction and determination of temperature and mud rheology modelling is highly required for accurate planning and designing of MPD hydraulics. The pressure difference between the drill pipe and annulus in Riser less drilling must be taken into consideration during the calculation of the density, plastic viscosity, yield point and ECD profiles inside wellbore. Neglecting the effect of pressure and temperature on mud properties in the well hydraulics calculation will lead to erroneous results which may lead to a kick or a loss of circulation. Pressure losses due to drill pipe tool-joint, drilled cutting, annular eccentricity and drill string rotation have significant effect on well hydraulics of MPD. New technique for calculating the well hydraulics of MPD by using finite difference calculation is developed. 2. Keywords: <span style=font-size: 10.0pt;font-family: times= new= roman,serif=>Dual Gradient Drilling; High Pressure and High Temperature Condition; Managed Pressure Drilling; Riser Less Drilling

Increased global energy demand has forced the oil and gas industry to search for hydrocarbons in increasingly challenging locations such as high temperature, high pressure (HTHP) reservoirs. This paper presents the field performance of a new fit-for-purpose synthetic-based mud (SBM) used to drill an ultra-HTHP deep gas exploration well offshore Malaysia. The well was drilled to a total depth (TD) of 14, 380 ft (4, 383 m) and reached the highest recorded bottomhole temperature (BHT) of 488°F (253°C) in Southeast Asia. To overcome the anticipated drilling challenges in the extreme environments, the operator and service company collaborated to identify a thermally stable, high-density drilling fluid that met the operator's needs. The drilling fluid was formulated for a maximum density of 18 lb per gallon (ppg), but reached the Southeast Asia record of 19.1 ppg mud weight at TD. The use of dual weighting materials (barite and manganese tetraoxide) yielded lower plastic viscosity (PV) for the high-density mud, leading to improved hydraulics and lower equivalent circulating density (ECD). The drilling fluid encompassed excellent temperature stability with no weighting agent sag and no high-temperature gelation observed after remaining static for five days at BHT during wireline logging. In this respect, it eliminated the rig time spent for additional circulating or conditioning of drilling muds and fluid treatment cost. Moreover, the fluid also provided good wellbore stability with no non-productive time (NPT) from drilling fluid performance. Comparison of field data and laboratory results highlighted the benefits of competent drilling fluid design and testing. As a result of thorough planning and comprehensive laboratory testing, desirable drilling fluid properties were maintained despite extreme HTHP conditions, minimizing trips and operational costs.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 194536, “Managed Pressure Cementing (MPC) Within a Narrow Pressure Window, Deepwater Gulf of Mexico Application,” by Michael Teoh, Sharief Moghazy, SPE, Keith Smelker, and Roger Van Noort, SPE, Shell, and Juan C. Valecillos, Julian Hernandez, and Maurizio Arnone, Weatherford, prepared for the 2019 IADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, Amsterdam, 9–10 April. The paper has not been peer reviewed. Managed-pressure cementing (MPC) is an important technique for primary cementing operations in wells with narrow pressure margins between the pore and fracture gradients. This paper presents the design considerations, methodology, and results of two deepwater MPC operations conducted to cement production casing strings within a target operating window of approximately three-tenths of a pound.•Modern transient hydraulic modeling software permits the calculation of adequate surface pressure levels to control the annular pressure profile during the different stages of a cementing operation. On the basis of a•predetermined annular pressure target, different variables can•be designed to produce surface and•downhole pressures within existing limits of a particular operation. This capability, combined with modern managed-pressure-drilling (MPD) systems, enables accurate control of the annular pressure profile during cementing and makes it possible to obtain near-constant bottomhole pressure (BHP) throughout the cement•placement operation while using statically underbalanced mud columns. Introduction Preventing fluid losses during slurry placement generally is necessary in achieving the goals of a cementing operation. Effective zonal isolation behind the casing or liner wall is related intimately to preventing losses toward, and flow from, the formation during and after the cement circulation. When cementing a casing or liner string within limited openhole pressure margins, maintaining the bottomhole circulating pressure below the fracture gradient is not feasible in most cases when using conventional methods. Cementing fluid dynamics are generally more complex than the fluid dynamics observed during the drilling phase. Additionally, multiple fluids with diverse properties and with generally higher viscosities are pumped at different rates. All of these factors, combined with high cement-slurry densities, contribute to equivalent circulating density (ECD) levels at the well bottom during cementing that are not observed while drilling. In many cases, these ECD levels lead to losses or even fracturing of the formation. The inability to measure downhole pressures during the operation adds to the complexity of the cementing job. In recent years, MPD systems, with their ability to control precisely the well pressure profile, have emerged as an alternative solution to the problem of cementing efficiently within tight margins in deepwater wells. Used together with advanced hydraulic modeling software that can predict fluid properties accurately downhole under dynamic and static conditions, the latest MPD systems are enabling drilling engineers to manipulate variables that in the past were out of reach during the drilling and cementing-job planning. The two wells discussed in the complete paper were drilled in the Gulf of Mexico (GOM) in approximately 8,500 ft of water from rig kelly bushing to mudline. The paper provides definitions related to the MPC subject, an overview of the applications, a summary of the engineering approach and calculations, and the results obtained during these cementing operations.

Four wells were successfully drilled and completed, but high drilling fluid densities (1.95 to 1.98 SG) were necessary to maintain wellbore stability in the overburden section immediately above the depleted reservoir. The estimated hydrostatic overbalance from the drilling fluid was approximately 800 bar (11,603 psi) higher than reservoir pressure. A wellbore strengthening technique was selected to seal the calculated 1500 μm fractures induced by these high pressures. This paper highlights the engineering, logistical, and operational challenges encountered while successfully drilling and completing such wells. Geomechanical data was initially acquired, including Young's modulus, Poisson's ratio, and minimum in-situ horizontal stress; and, together with the operational parameters [hole diameter and equivalent circulating density (ECD)], these data were used to estimate fracture width (1500 μm). Subsequently, a drilling fluid system was engineered and customized to seal such fractures, thereby strengthening the wellbore to help minimize losses in the reservoir. The solution was validated at two separate laboratories. Large particulate materials with a D50 of 600 to 2300 μm were used. Improvement opportunities during execution were captured for the next cycle. A total drilling fluid loss of 512 m3 during a 16-hour period was experienced in one well after a drilling liner packoff occurred, and fractures greater than 1500 μm were initiated; however, the liner was successfully cemented in place. The coarse particulate materials (600 to 2300 μm) were mobilized in 500 and 1000 kg bags to minimize deck space requirements on the rig and help facilitate ease of mixing. Rig mixing and pit agitation capacity were important for effective mixing of the fluid system. The application also provided the opportunity to align testing procedures and equipment between the field and laboratory. With increasing reservoir depletion, the potential exists for fracture width increases that can impact the particle size of materials necessary to effectively design a solution. Engineered particulate solutions provided a pathway for sourcing and procuring the necessary wellbore strengthening materials.

A conventional oil-based drilling fluid was determined not to be applicable for drilling narrow hole annuli in a mature field offshore Norway. Drilling these wells with a very narrow hydraulic window required an oil-based drilling fluid with reduced viscosity and improved sag stability. A totally reformulated drilling fluid system was developed. The combination of base oil and selected products produced a fluid with a flatter rheological profile, resulting in reduced plastic viscosity (PV) and increased low shear rate viscosity (LSRV). This rheological profile reduced equivalent circulating density (ECD) and improved sag stability. This rheological profile also directly impacted pump pressure and hole cleaning capabilities, delivering lower pump pressure and allowing for higher pump rates and improved hole cleaning. This paper presents the experimental work performed when developing the system for this specific application. The authors also will present field data and compare the performance of the new drilling fluid system with that of conventional systems.

A number of oil fields in the Gulf of Thailand are characterized by severely depleted gas sands and unstable coal and shale. Operators drilling high angle and horizontal wells in those fields often have to contend with problems associated with high equivalent circulating density (ECD) and the narrow operating margin between fracture gradient and borehole stability. Reaching total depth in those fields without losing returns is possible but it requires careful management of the ECD, vigilant hole cleaning practices, and controlled drilling. Unfortunately, success comes at the expense of drill time which is unavoidably reduced by those same conventional practices. Automated Managed Pressure Drilling (MPD) was a solution used by one operator to improve drilling efficiency while still avoiding losses and maintaining wellbore stability. By taking advantage of the MPD system’s ability to manage the BHP when the mud pumps are off the operator was able to reduce the static mud weight below wellbore stability and the ECD below the fracture gradient. With the reduction in mud weight the operator was also able to change the mud rheology in other ways that contributed to improved hole cleaning. Managed Pressure Drilling was initially used in a three well program in 2007 and later in an extended six well program in 2009. For most of the wells the drilling plan was the same: conventionally drill out of the 9–5/8” casing with an 8–1/2” bit down to the top of the depleted zones, lighten the mud density and rheology, bring the MPD system on line and drill through the depleted zone to the next casing point. However, midway through the second program the well plans changed and MPD was used to drill the entire 8–1/2” section. For all nine wells, the MPD system remained the same: a dynamic pressure control system with an integrated real-time hydraulics model, an automated manifold and backpressure pump, and early kick detection equipment. Even though the trajectory changed from well to well, surface and downhole conditions remained relatively constant in terms of borehole and drill string geometry, stratigraphic sequence, mud rheology, drilling practices, MPD system, and rig type. Such relatively constant conditions created favorable circumstances for the comparison of conventional and MPD practices. Results show that MPD enabled the operator to avoid losses and achieve noticeable improvements in drilling efficiency and ECD management. In addition, there were noticeable improvements in MPD performance in terms of transition times and BHP control.

An improved prediction of frictional pressure drop using an accurate shear rate equation for high-yield stress drilling fluids at the surface and downhole conditions

Iso-propyl caprylate and iso-propyl linolenate synthetic fluids as novel alternatives in deep-water drilling operations: Critical fluid properties and aerobic biodegradability assessments

This paper describes the dynamic and static filtration characteristics of four different drilling fluids under downhole conditions. Filtration rates were measured over two-, four- or five-day periods in a simulated sandstone formation. The drilling fluids studied had a wide range of API fluid loss and rheological characteristics. The API fluid-loss for all drilling fluids tested were generally higher than the filtrate loss observed in the sandstone formation. The largest static and dynamic filtration rates were seen in drilling fluids having uncontrolled fluid-loss properties. A large spurt loss volume, varying in duration from 30 seconds to five minutes occurred upon initial contact of the drilling fluid with the formation. A steady state filtration rate was quickly reached following the initial spurt loss. Dynamic filtration rates and the percentage of circulatable hole varied as a function of the drilling fluid flow rate in the annulus. Increased annular flow rates produced higher dynamic filtration rates. The dynamic filtration rates decreased prior to day four of the tests, afterwhich no significant changes were observed. Removal of the external wellbore filter cake using mechanical scrapers did not significantly change the dynamic filtration rate. The results presented can be used to estimate the effect of flow rates, fluid loss, and rheology of the drilling fluid on the amount of drilling fluid filtrate lost to the formation and on the percentage of the annulus that is circulating.