Usual practice in drilling engineering is to determine drilling-fluid density at surface conditions assuming that drilling-fluid density does not change with changing downhole conditions. This assumption may result in inaccuracy while estimating static and dynamic pressures in the wellbore, especially when synthetic-based drilling fluids are used. Inaccurate estimation of the pressure profile in the annulus can lead to severe well problems such as kicks, drilling-fluid losses, and wellbore instability. In addition, inaccurate pressure-profile estimation can affect the success of managed-pressure-drilling (MPD) operations, which require real-time knowledge of wellbore pressures to keep wellbore pressure between formation pore and fracture pressures using a control choke placed on the return line of the annulus.Effects of pressure and temperature on volumetric behavior of two olefin-based synthetic oils are investigated in this study using a mercury-free pressure/volume/temperature (PVT) system. The olefin-based synthetic oils used in this study are C16C18 internal olefin (IO) and C12C14 linear alpha olefin (LAO). To simulate deep offshore situations, the temperature is ranged between 25 and 175°C, while the pressure is ranged between 0 and 14,000 psig.In addition, volumetric performances of olefin-based syntheticoil systems under investigation are compared with those of water, brine solution, mineral oil, diesel oil, and n-paraffin-based oil under similar conditions.The study shows that the volumetric properties of syntheticbased oils are more sensitive to pressure and temperature conditions compared to water, brine solutions, mineral oil, and diesel oil. Once emulsion systems containing synthetic-based oils are used, density change with respect to downhole conditions should be modeled to increase the reliability of pressure-profile calculations.
Precise estimation of annular pressure losses is essential in drilling and well completion operations to control formation pressures and optimize drilling and completion fluids' hydraulic programs. Without accurate estimation of annular pressure losses it is possible to face serious problems that would yield interruption in drilling operation and sometimes lead to abandonment of the well. While annular pressure loss estimations are critical, determination of pressure losses associated with flow of Non-Newtonian fluids is challenging. Many investigators proposed different equivalent diameter concepts to provide a similarity between pipe and annular flow. In this study we have investigated the coupling effects of rheological model and equivalent diameter definition on pressure losses using three rheological models (Bingham Plastic, Power Law and Yield Power Law) together with four different equivalent diameter definitions. Effects of inner/outer radius ratios and flow rate on pressure losses determined using different rheological model and equivalent diameter pairs are analyzed using an onshore well and an offshore well. The differences in pressure losses using different pairs for the cases of onshore and offshore wells are shown. The study provides detailed analysis on how severely the annular pressure losses varies once rheological model and equivalent diameter definitions are changed for different operating conditions. Introduction Annular pressure loss determination is a critical part of a hydraulic program since annular pressure losses during drilling fluid circulation causes an increase in equivalent circulating density (ECD) which should be kept below fracture gradient and higher than formation pressure during conventional over balance drilling. In cases where pore pressure and fracture gradients are close to each other (for example in deep/ultra deep offshore drilling and on depleted reservoir drilling), accurate ECD estimation becomes even more important. Hence, it is very critical to determine annular pressure losses with high precision. Pressure loss estimation in annulus is harder compared to pipe flow since the geometry of the area open to flow is more complex. Flow regime might be laminar or turbulent depending on the clearance between wellbore/casing inner diameter-pipe outer diameter and the flow rate being used. While many investigators studied the flow of Non-Newtonian fluids in annulus and introduced either empirical or analytical solutions, disagreement between theoretical and measured pressure losses still exists. Previous Studies Fredrickson and Bird 1 are the pioneers among investigators who studied non-Newtonian fluid flow in concentric annulus. They derived an analytical expression to determine frictional pressure losses in annulus for Power Law rheological model. Their approach gives reasonable results when inner to outer radius ratio is more than 0.5. Kozicki, Chou and Tiu 2 determined a relation between maximum velocity and pressure loss for Power Law fluids flowing in ducts of arbitrary cross sections under laminar flow conditions. They have introduced two geometric constants that are function of inner radius to outer radius ratio. Zamora and Lord 3 proposed a new numerical and graphical technique to determine pressure losses of Non-Newtonian fluids in pipes and annuli. The proposed model can be used for Bingham Plastic, Power Law and Yield Power Law rheological models. They have modified the Reynolds number for annular flow by incorporating geometry factor defined by Fredrickson and Bird 1 and nominal viscosity defined by Annis 4. In the case of turbulent flow, they have used the approximation given by Schuh 5 to determine transition from laminar to turbulent flow regime. Langlinais, Bourgoyne and Holden 6 compared actual annular pressure losses obtained from 2 wells with theoretical ones determined by three widely used (Hydraulic diameter, Crittendon 7 criteria and Laminar Flow Slot) equivalent diameter concepts together with Power Law and Bingham Plastic flow equations. They have observed that pressure losses are more sensitive to the definition of annular gap compared to rheological model. They have also stated that, Bingham Plastic model coupled with Crittendon 7 criteria agrees best with the experimental data.
Managed Pressure Drilling (MPD) is an alternative to overbalanced and underbalanced drilling in conditions where pore pressures and fracture gradients are so close to each other (depleted reservoirs, deep and ultra-deep offshore reservoirs) that it is not possible to drill significant depths without setting a casing. While MPD enables an operator to drill longer footages without setting a casing, it requires precise estimation of equivalent circulating density (ECD) during drilling and static bottomhole pressure (SBHP) during non-drilling times. General practice in the drilling industry is to use rheological and volumetric properties of drilling fluids measured at surface to estimate ECD and SBHP. Consequently, ECD and SBHP measured using MWD and LWD tools in the field do not match the theoretical calculations. This study shows the importance of introducing the effect of downhole conditions to hydraulic equations in order to estimate ECD's and SBHP's accurately. Paraffin-based synthetic drilling fluid is used for this purpose. The effect of pressure and temperature on density of fluid is determined using PVT cell experiments. An equation relating the density of the fluid to pressure and temperature is determined using linear and non-linear regression techniques. Rheological characterization of the fluid was obtained on a Fann 75 HPHT rotational viscometer. A Bingham plastic model was used to define shear stress - shear rate relation of the fluid in all pressures and temperatures. The effect of pressure and temperature on plastic viscosity and yield point are determined using linear and non-linear regression techniques, similar to the ones used in PVT analysis. Both onshore and offshore cases are investigated and the effect of incorporating downhole effects to density and rheological parameters on ECD are analyzed. Introduction As a result of the depletion of most of the known reservoirs around the globe, companies are searching for oil and gas in more challenging areas such as deep and ultra-deep offshore locations. In addition, high oil prices motivate the industry to produce the last measure of oil from mature oil fields where the pressure is depleted. The conventional overbalanced drilling technique creates a major drawback to drilling in ultra-deep and depleted reservoirs. In ultra-deep offshore locations, pore pressure and fracture pressure gradients are very close to each other, and with conventional drilling, it is hard (sometimes impossible) to drill a hole up to the target depth(1). In the case of depleted reservoirs, pore pressure is so low that it is not possible to drill without damaging the formation. These challenges create the need for a new technology to drill in such hostile environments. Managed Pressure Drilling allows drilling of longer intervals by drilling overbalanced while maintaining near constant bottomhole pressure, using a combination of drilling fluid density, equivalent circulating density (ECD) and casing back pressure in a closed system(2, 3). While MPD will enable operators to drill longer sections and use light drilling fluids, it does require better wellbore pressure management. Only by managing the wellbore pressure, will it be possible to decide on which type of drilling fluid to use and how deep it can be used.
High rate injection or production of fluids with sand particles places wellhead components and downhole assemblies at risk of erosion damage. Depending on the severity and location of the material loss, this may pose a significant well loss or blowout hazard. For this reason, assessment and mitigation of erosion can be critical for such applications.In this work, Computational Fluid Dynamics (CFD) was used in conjunction with erosion models to assess the erosion damage characteristics associated with the operating conditions and equipment for a high-rate, shale gas reservoir fracturing application. The work was based on the severe erosion damage experienced by EnCana as a result of high rate hydraulic fracturing operations performed in horizontal shale gas wells at their Horn River, BC field development. Material losses were observed within the wellhead equipment as well as in the LTC couplings of the production casing string near surface in several wells. CFD models were developed for the existing wellhead and wellbore geometries and used to simulate a range of hydraulic fracture operating conditions in an effort to predict the locations and degree of material loss in the components in each case. The models were calibrated with caliper log data and measurements taken from casing samples retrieved from several wells. The analyses suggested that well head system modifications, such as tubing head spool changes and use of spacer spools, could be effective in substantially reducing material losses in the tubular connections. In addition, sensitivity analyses were performed for different wellhead configurations and variations in the hydraulic fracturing parameters to determine the factors that likely had the most influence on the connection material losses. The results served to demonstrate that it is possible to use CFD with erosion models as predictive tools to identify locations of severe erosion in completion systems, and, when calibration data is available, to quantify the amount of material loss in wellhead and downhole components. This information can aid in designing optimum completions systems, and in defining operating conditions which can reduce the risk of equipment failure, potential blow-outs, and associated safety and environmental hazards.
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