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Krishna, Shwetank (Petroleum Engineering Department, Universiti Teknologi PETRONAS, Malaysia) | Ridha, Syahrir (Institute of Hydrocarbon Recovery and Petroleum Engineering Department, Universiti Teknologi PETRONAS, Malaysia) | Vasant, Pandian (Fundamental and Applied Sciences Department, Universiti Teknologi PETRONAS 32610 Seri Iskandar, Malaysia) | Ilyas, Suhaib Umer (Institute of Hydrocarbon Recovery, Universiti Teknologi PETRONAS, Malaysia)

Surge and swab pressure generated during pipe tripping operations tends to result in various wellbore stability and integrity problems. To monitor these problems, prediction of these differential pressure is required for the smooth functioning of drilling operations. An analytical predictive model is presented in this research for surge and swab pressure. This model is developed under steady-state condition for Yield Power Law fluid. A fluid filled wellbore with drill-pipe/casing is considered as two concentric cylindrical pipes for developing this model. In this concentrical cylinder inner pipe is moving at certain velocity and the outer pipe is stationary. Due to movement of inner pipe, drilling fluid will start displacing in annulus and results in pressure surges. A predictive model is developed by analytically combining the frictional pressure loss and mud clinging effect to forecast this pressure surge due to couette fluid flow phenomena in wellbore. The newly developed model (NDM) is validated with two existing analytical models and reported experimental data that are available in the published literature. A parametric analysis is carried out to identify the effect of various parameters on pressure differential. This research suggests that with the increase in pipe tripping velocity, surge pressure also tends to increase because of high viscous drag of fluid. It is also found that the increase in diameter ratio surge pressure also tends to increase due to large shearing effect between pipe wall and fluid. In conclusion this model is predicting the suitable range of tripping speed and diameter ratio under tolerable wellbore pore and fracture pressure to assure downhole wellbeing. Unlike most of the existing model, NDM requires less numerical analysis which make it easier to understand and apply in real case situation. The model considers mud clinging effect for precise prediction of surge/swab pressure gradient.

annular pressure drilling, diameter ratio, drilling fluid chemistry, drilling fluid formulation, drilling fluid property, drilling fluid selection and formulation, drilling fluids and materials, drilling operation, equation, ettehadi & altun, experimental data, fluid loss control, frictional pressure loss, gradient, Modeling & Simulation, pipe, power law fluid, prediction, pressure gradient, pressure surge, surge pressure gradient, surge swab pressure gradient, swab pressure, Upstream Oil & Gas, well control, Wellbore Design, wellbore integrity

Oilfield Places:

- Oceania > Australia > Victoria > Otway Basin (0.99)
- Oceania > Australia > South Australia > Otway Basin (0.99)

SPE Disciplines:

Summary.

This paper presents calculation methods for predicting the behavior of drilled-gas contamination of oil-based drilling fluids. The methods are verified by experiments conducted in a 6,000-ft [ 1828.8-m] test well. This paper also presents field-handling procedures developed with the calculation methods.

Introduction

During drilling, operations, the bit routinely drills through gasbearing formations. Although proper drilling-fluid density selection will prevent gas from flowing from these formations into the borehole, the gas contained in the pore space of the rock destroyed by the bit will always become mixed with the drilling fluid. This gas is often called "drilled gas." If an oil-based drilling fluid is used, drilled gas will normally dissolve completely in the drilling fluid at bottomhole conditions because the volume of gas is small compared with the volume of drilling fluid in which it is mixed (Fig. 1). When this gas/drilling-fluid mixture is pumped near the surface, however, gas will come out of solution and expand rapidly because of the greatly reduced pressure. This gas evolution will often begin when the gas/drilling-fluid mixture is within a few hundred feet of the surface, providing little time for the rig crew to react before gas reaches the surface. Hazardous situations have been reported where significant amounts of gas have been released on the rig floor and drilling fluid has been spewed over the crown block while the annular blowout preventers (BOP's) are being closed.

These problems occur because the equipment and procedures sometimes used are not adequate for some of the well conditions experienced. To design a system properly for safe handling of drilled gas in oil-based drilling fluids, a calculation procedure is needed for predicting well behavior under various field conditions. This type of calculation procedure would also permit evaluation of existing rig equipment for the purpose of imposing operational limitations, such as a maximum safe penetration rate (ROP).

This paper presents techniques for estimating the amount of drilled gas entering an oil-based drilling fluid and for predicting the behavior of the gas/drilling-fluid mixture in the annulus as it is circulated to the surface. With the methods presented, the gas-drilling-fluid bubblepoint depth, the maximum loss in bottomhole pressure (BHP), and an approximate annular pressure profile can be calculated. The volume of drilling fluid that would be expelled from the well and the associated gas rate can also be estimated. The calculation procedures presented were verified by experiments conducted in a 6,000-ft [ 1828.8-m] test well.

Several alternative methods for handling drilled gas in oil-based drilling fluids were explored with the calculation procedure. Special considerations for deepwater floating drilling operations are also discussed.

Calculation Procedure

The calculation procedure developed requires completion of three steps: (1) determination of the concentration and total volume of drilled gas entering the drilling fluid at the bits (2) determination of the drilled-gas-concentration profile as the drilled gas is circulated to the surface; and (3) calculation of the circulating BHP (BHCP) with and without gas.

The concentration of drilled gas entering the drilling fluid at the bit is calculated from the volume rate of rock removal by the bit and the circulation rate of the drilling fluid. If values for rock porosity and gas saturation cannot he estimated from well log analysis of nearby wells, upper-limit values for the depth range of interest can be assumed. The total volume of drilled gas entering the drilling fluid depends on the total borehole volume removed from the gas formation of interest. Thus, the thicker the gas-bearing formation, the larger the volume of drilled gas entering the well. Equations needed for the calculation of the initial drilled-gas concentration and total gas volume are given in Appendix A.or thin sands, the initial length of the gas-contaminated region is generally much less than the total depth of the well, and considerable dilution can occur as the gas-contaminated region is circulated to the surface (Fig. 2). This dilution occurs primarily because the velocity profile for a non-Newtonian fluid in an eccentric annulus is very nonuniform, and the peak fluid velocity can be much greater than the average fluid velocity. Mixing with the drilling fluid occurs both at the leading and trailing edges of the gas-contaminated region and gradually shortens the region of maximum gas concentration. If the initial length of the gas-contaminated region is small, the maximum gas concentration observed when the gas reaches the surface can be much less than the initial gas concentration at the bottom of the hole. Equations needed for calculation of the gas-concentration profile are given in Appendix B. However, this step can be skipped by assuming that the gas concentration entering the well at the bit remains constant as the gas-cut drilling fluid is circulated to the surface. This represents a "worst-case" situation.

To estimate the maximum loss in BHCP resulting from drilled- gas evolution, the BHCP is first determined without gas. Next, the BHCP is calculated when the top of the gas-contaminated drilling fluid reaches the surface, which is when the BHCP is lowest. The difference between the two BHCP's will be the maximum BHCP reduction.

The BHCP without gas is determined by adding the hydrostatic BHCP caused by the drilling-fluid column, the power-law annular frictional pressure loss, and the annular surface pressure. An iterative method is used to calculate the BHCP when the top of the gas-contaminated drilling fluid reaches the surface. The method involves 11 steps.

1. Calculate the gas/drilling-fluid ratio as outlined in Appendix A.

2. Start at the surface where the pressure and temperature are known.

3. Move downhole one length-step. (The distance moved is equal to the length of step size selected.)

4. Assume a pressure and calculate the bottomhole circulating temperature (BHCT) (Fig. 3) at this depth.

5. Use an average pressure and temperature to calculate the free-gas rate and density and the density of the oil-based drilling fluid containing dissolved gas.

6. Calculate the hydrostatic and friction pressure gradients and add these values to get the total pressure gradient over the length-step.

7. Use the calculated pressure gradient to calculate the pressure, and compare it with the assumed pressure. If the two compare favorably, continue to the next step. If not, use the new pressure and repeat Steps 5 through 7.

8. Calculate the volumes of free and dissolved gas contained in the annular section associated with the selected length-step.

9. Repeat Steps 3 through 8 until the sum of the volumes of free and dissolved gas contained in the annular sections is equal to the volume of gas that entered the well as calculated in Appendix A. 10. Use the frictional pressure and the hydrostatic gradient calculated for gas-free drilling fluid to calculate the pressure resulting from a column of gas-free drilling fluid that may exist below the region of gas-contaminated drilling fluid.

annular pressure drilling, BHCP, calculation procedure, concentration, drilled-ga concentration, drilling fluid chemistry, drilling fluid formulation, drilling fluid property, drilling fluid selection and formulation, drilling fluids and materials, drilling-fluid ratio, evolution, fluid loss control, gas concentration, gas drilling-fluid mixture, gas drilling-fluid ratio, gas evolution, gradient, oil-based drilling fluid, pressure gradient, procedure, solubility, SPE Drilling Engineering, Upstream Oil & Gas, well control

SPE Disciplines:

Leak-off tests (LOTs) are routinely performed by the drilling industry after drilling a few feet below a new casing shoe. The recorded leak off pressure (LOP) primarily establishes the upper mud weight (MW) limit for the next hole section. ** **Field-wide LOP data usually show some spread at a given depth. Lower bound trend of LOP data is used as the base case for fracture pressure prediction and planning of future wells. For the field under study, LOPs obtained at the 9 5/8” casing shoe show a scatter of 800 psi (2 ppg MW equivalent). The average depth of the casing shoe is ~7900 ft and the LOPs are spread over a depth interval of only 260 ft. In such a situation, taking the lower bound of LOP data for fracture gradient estimation may lead to an overly conservative well design. From a drilling perspective, narrow margin drilling conditions would be invoked in what is really not a narrow drilling window situation. The study investigated the scatter in the LOPs to understand the cause in terms of rock mechanics, well trajectory and in-situ stresses. The study indicated that LOPs measured in inclined wells may need an ‘adjustment’ prior to use for predicting fracture pressures for future wells with a different inclination or azimuth.

The reported LOPs are from boreholes scattered over the field having an inclination of ~45º and varying azimuths. Attempts to understand the scatter in terms of subtle differences in lithology and pore pressures at the casing shoe failed. However, a careful analysis of the well trajectory with respect to the orientation of in-situ stresses successfully explained the differences in measured LOP values, assuming they represent initiation of new tensile fractures rather than leak-off into existing fractures.

The field is in normal faulting stress regime with anisotropic horizontal stresses. In such cases, the stress redistribution around a borehole is strongly influenced by the borehole geometry. To cause a leak-off in an unfractured intact formation, the bottom-hole pressure must overcome the tensile strength and the minimum principal stress around the borehole. Due to stress redistribution, inclined wells in the direction of Shmin yield higher LOPs compared to near-vertical wells or inclined wells in other orientations. For a given stress state and rock strength, different LOPs can be expected solely based on the trajectory of the inclined borehole w.r.t. in-situ stresses.

This study highlights the caution needed in interpreting LOP values in inclined wells drilled in different azimuths. Depending on horizontal stresses anisotropy, LOP measured in inclined wells may need a careful scrutiny of the trajectory vis-à-vis stress direction before consideration in well design for new wells. Understanding tolerance of well trajectory to losses can help us drill deeper and safer.

annular pressure drilling, drilling fluid chemistry, drilling fluid formulation, drilling fluid property, drilling fluid selection and formulation, drilling fluids and materials, fluid loss control, fracture gradient, leakoff test, lot data, nonvertical well, Pitfall, Reservoir Characterization, reservoir geomechanics, Upstream Oil & Gas, well control

Abstract 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.

doi: 10.2118/172304-MS

SPE-172304-MS

annular pressure drilling, column pressure, drilling fluid chemistry, drilling fluid formulation, drilling fluid management & disposal, drilling fluid property, drilling fluid selection and formulation, drilling fluids and materials, drilling operation, dual gradient drilling, flow rate, fluid loss control, geothermal gradient, hole cleaning, hydraulic, hydraulic parameter, riserless deepwater drilling operation, riserless drilling, riserless drilling operation, surface pump pressure, Upstream Oil & Gas, well control, well hydraulic

Country:

- North America > United States (1.00)
- Asia (1.00)

SPE Disciplines:

- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)

Abstract

There is considerable evidence that the flow of heavy oil in some reservoirs is non-Newtonian and that this behavior can be approximated by a Bingham type fluid. Investigations in the Laboratory and in a few field tests have shown a behavior that is characteristic of a Bingham fluid; the flow of the heavy oil takes place only after the applied pressure gradient exceeds a certain minimum value. Despite the research that has been carried out over the past 20 years on the flow of non-Newtonian fluids in porous media, very little work has been done on single- and multiple-phase flow of Bingham fluids. At present, there is no reliable method of analyzing pressure buildup data from well tests where the reservoir contains a Bingham oil.

This work presents a theoretical study of the flow and displacement of a Bingham type fluid in porous media. An integral method of analyzing the single phase flow of this type of fluid has been developed. An approximate analytical solution has been obtained for transient flow problems, and its accuracy is confirmed by comparison with numerical solutions. The flow behavior of a slightly-compressible Bingham fluid is discussed, and a new method of well test analysis has been developed by using the integral solution.

To obtain some understanding of the physics of immiscible displacement with Bingham fluids, a Buckley-Leverett type analytical solution with a practical graphic evaluation method has been developed and applied to the problem of displacing a Bingham-type fluid by water. The results reveal how the saturation profile and the displacement efficiency are controlled not only by the relative permeabilities, as in the case of Newtonian fluids, but also by the inherent complexities of Bingham non-Newtonian behavior. In particular, we find that in the displacement process with a Bingham fluid, there exists a limiting maximum saturation, beyond which no further displacement can be achieved.

Introduction

Flow of non-Newtonian fluids through porous media is encountered in many subsurface systems involving underground natural resource recovery or storage projects. In the past three decades, a tremendous effort has been expended in developing quantitative analysis of flow of non-Newtonian fluids through porous media. Considerable progress has been reported and much information is available in the chemical engineering, rheology and petroleum engineering literature regarding non-Newtonian fluid flow through porous media (Savins, 1969; Gogarty, 1967; van Poollen, 1969; Ikoku and Ramey, 1979; Odeh and Yang, 1979). The theoretical investigations carried out in this field have mainly concentrated on single-phase power-law non-Newtonian fluid flow, while the experimental studies have intended to provide rheological models for non-Newtonian fluids and porous materials of interest.

There is considerable evidence from laboratory experiments and field tests that certain fluids in porous media exhibit a Bingham-type non-Newtonian behavior (Bear 1972; Barenblatt et al., 1984). In these cases, flow takes place only after the applied pressure gradient exceeds a certain minimum value, referred to as the threshold pressure gradient. The flow of oil in many heavy oil reservoirs does not follow Darcy's law, but it may be approximated by a Bingham fluid (Mirzadjanzade et al., 1971).

For groundwater flow in certain clayey soils, or in strongly argillized rocks, the existence of a threshold hydraulic gradient has also been observed. When the applied hydraulic gradient is below a certain minimum gradient, there is very little flow. This phenomenon was attributed by some authors to clay-water interactions (Bear, 1972; Mitchell, 1976).

The flow of foam in porous media is a focus of current research in many fields.

P. 339^

apparent viscosity, bingham fluid, coefficient, displacement, drilling fluid chemistry, drilling fluid formulation, drilling fluid property, drilling fluid selection and formulation, drilling fluids and materials, Efficiency, equation, flow in porous media, Fluid Dynamics, fluid loss control, gradient, integral solution, Lawrence Berkeley Laboratory, minimum pressure gradient, Newtonian fluid, potential gradient, pressure gradient, saturation, SPE Reservoir Engineering, Upstream Oil & Gas, viscosity

Country:

- North America > United States (0.95)
- Europe (0.68)

SPE Disciplines:

Thank you!