![Example 4
Assume a well 1 (W1) as discussed in example 3
has been tested at a rate of 202 STB/D during a
three-day period. Stabilized wellbore flowing
pressure measured 3243 psia. Another wells say W2
and W3 were previously tested with a multirate
sequence, which indicated the exponent in the IPR
equation (Fetkovich] ranges from 0. 77 to 0.81. if a
value of 0.8 is assumed to apply to W1 well. Average
reservoir pressure is 4000 psia.
Determine the rate of natural flow, assuming the
tubing performance calculations in example 3
apply (i.e., = 200psia, GLR = 600scf/STB, and
𝑃𝑤h
8000ft of tubing having a 3.5-in. nominal diameter).](https://image.slidesharecdn.com/lecture08-250530100711-79ffca0f/85/Lecture08-pptx-for-oil-and-gas-engineering-students-in-universities-46-320.jpg)
Lecture08.pptx for oil and gas engineering students in universities
- 2. Wellbore Flow Performance The pressure drop experienced in lifting reservoir fluids to the surface is one of the main factors affecting well deliverability. As much as 80% of the total pressure loss in a flowing well may occur in lifting the reservoir fluid to the surface Wellbore flow performance relates to estimating the pressure-rate relationship in the wellbore as the reservoir fluids move to the surface through the tubulars This flow path may include flow through perforations, a screen and liner, and packers before entering the tubing for flow to the surface. The tubing may contain completion equipment that acts as flow restrictions such as profile nipples, sliding
- 3. Wellbore Flow Performance Relationships to estimate this pressure drop in the wellbore are based on the mechanical energy equation for flow between two points in a system as Where, α is the kinetic energy correction factor for the velocity distribution, W is the work done by the flowing fluid, and El is the irreversible energy losses in the system including the viscous or friction losses. For most practical applications, there is no work done by or on the fluid and the kinetic energy correction factor is assumed to be one.
- 4. Wellbore Flow Performance The total pressure drop is equal to the sum change in potential energy (elevation), the of the change in kinetic energy (acceleration), and the energy losses in the system. Considering the differential form for any fluid at any pipe inclination it becomes This fundamental for estimating the pressure drop in tubulars for single-phase liquid, single-phase vapor, and multiphase flow
- 5. Wellbore Flow Performance The pressure drop for a particular flow rate can be estimated and plotted as a function of rate. i.e. wellhead pressure is fixed and the bottomhole flowing pressure, pwf , is calculated by determining the pressure drop. This approach will yield a wellbore flow performance curve when the pressure is plotted as a function of rate as shown in figure below In the figure the wellhead pressure is held constant, and the flowing bottomhole pressure is calculated as a function of rate. This curve is often called a tubing-performance curve because it captures the required flowing bottomhole pressure needed for various rates.
- 6. WellboreFlow Performance Typical tubing performance curve for constant wellhead pressure
- 7. Wellbore Flow Performance Single-Phase Liquid Flow: Single-phase liquid is generally of minor interest to the petroleum engineer, except for the cases of water supply injection wells. flow or In these cases, above is applicable where the friction factor, f, is a function of the Reynolds number and pipe roughness. The friction factor the Moody friction The friction factor is most commonly estimated from factor diagram. is an empirically determined value that is subject to error because of its dependence on pipe roughness, which is affected by pipe erosion, corrosion, or deposition.
- 8. Wellbore Flow Performance Single-Phase Vapor Flow Several methods exists for estimating the pressure drop for single-phase gas flow under static and flowing conditions. These methods include the average temperature and compressibility method and the original and modified Cullendar and Smith methods. They require a trial-and-error or iterative approach to calculate the pressure drop for a given rate because of the compressible nature of the gas. A simplified method for calculating the pressure drop in gas wells assuming an average temperature was presented by Katz et al.
- 9. Wellbore Flow Performance 0.5 sd5 p 2 es p 2 q 200,000 in wh g es 1 TzL f g M Valid only for dry gas where 𝜀 is the absolute pipe roughness ≅ 0.0006in. for most commercial pipe. f𝑀 is the best-fit equation for the fully turbulent region of the Moody diagram and is sufficiently accurate for most engineering calculations.
- 10. Wellbore Flow Performance three components of pressure loss in a TPR curve for a single-phase liquid. a dry gas, and a two-phase gas/oil mixture.
- 11. Wellbore Flow Performance Thus for a given flow rate, wellhead pressure, and tubing size. there is a particular pressure distribution along the tubing. starting its traverse at the wellhead pressure and the The increasing tubing. downward toward the intake to pressure-depth profile is called a pressure traverse. as shown . below.
- 13. Wellbore Flow Performance Multiphase Flow. is much more complex than the single-phase flow problem because there is the simultaneous flow of both liquid (oil or condensate and water) and vapor (gas). The mechanical energy equation is the basis for methods to estimate the pressure drop under multiphase flow; however, the problem is in determining the appropriate velocity, friction factor, and density to be used for the multiphase mixture in the calculation. In addition, the problem is further complicated as the velocities, fluid properties, and the fraction of vapor toliquid change as the fluid flows to the surface
- 14. Wellbore Flow Performance Considering curve above, in multiphase mixtures there with is general trend of increasing pressure gradient depth and the procedures of calculating the pressure traverse of multiphase mixtures are complex Thus , numerous correlations based on field and experimental observations, which take the form of either generalized pressure versus distance curves, equation s called gradient curves or empirical pipe flow are used Multiphase pipeflow correlations can be classified as (i) gradient curves (ii) homogeneous mixture correlations (iii) flow regime correlations
- 15. Wellbore Flow Performance drawback of the correlations based on experimental data is that application to producing wells is limited to and ftuid the conditions of rate, geometry, gas/oil ratio, properties used in the experimental study Gradient curves Main parameters in vertical multiphase pipe flow are pipe diameter, oil rate, and gas/liquid ratio Other parameters that might have an effect on pressure gradient viscosity. densities include liquid surface tension. (oil, gas and water gravities), flowing cut. temperature, gas/liquid solubility, and water Note: gradient formed in the curves tubing do not apply if an emulsion
- 16. Wellbore Flow Performance Sample gradient curves
- 18. Example 1 A well is to be produced into a high-pressure, gas-gathering line requiring a minimum wellhead pressure of about 850 psia. Available tubing has 2.063in. nominal diameter and 1.751 in. inner diameter. Other relevant data for the well include: vertical length of tubing 8280 . depth to mid perforations 8500ft 0.75 (air 150°F 0.78 gas gravity =1) average average tubing temperature gas Z-factor pipe roughness 0.0006in.
- 19. Solution
- 20. Example 2 A certain well is under production at a depth of about 5000 ft. The oil is relatively heavy and contains little solution gas, thereby requiring gas lift to produce. The tubing is 3.5-in. nominal diameter and preliminary calculations indicate that 1000scf/ STB gas can be injected at an economical cost. Added to the 200scf/STB solution gas, this gives a total of 1200scf/STB total GOR. Consider production at an oil rate of 200STB/D. Assuming that the gas is injected at the bottom of the tubing. (i) Determine the required tubing intake pressure if the wellhead is fixed at 500psia (ii) Determine the available wellhead pressure when tubing intake pressure (located near the wellbore) is 2000 psia.
- 21. Solution
- 22. Wellbore Flow Performance Note, from the gradient curve The vertical axis represents distance traveled 1) vertically from a given point where the pressure is known 𝑑𝑝 The gradient decreases with increasing 2) 𝑑 𝐻 gas/liquid ratio (GLR) until a minimum gradient 𝑑𝑝 is reached. Thereafter the trend reverses and 𝑑 𝐻 increases with increasing gas/liquid ratio For convenience, the high-Gl.R gradient curves avoid 3) are shifted down on the depth scale to intersection with lower-GLR curves
- 23. Wellbore Flow Performance 4) If production is water-free, then gas/liquid ratio, GLR equals gas/oil ratio (GOR), but if water/oil ratio, (WOR) is reported, then the relation between GLR and GOR is Construct the tubing performance of an oil well producing through tubing with a given diameter and length at a specific gas/liquid ratio on Figure below and wellhead pressure is as shown
- 24. WellboreFlow Performance Construct TPR by gradient curve
- 25. Example 3 Given a well which produces from the Bromide sand at a depth of 8000 ft. Solution gas/oil ratio is 600scf/STB. Use of 3.5-in. nominal tubing is suggested by the production engineer, who claims there will be a need for gas life after only one to two years of production. Construct the present tubing performance curve, assuming a wellhead pressure of 200 psia.
- 29. NATURAL FLOW Based on only a few pieces of data, it is possible tubing to calculate and plot both inflow and performance relations For the typical case when the tubing shoe (inlet) reaches pressur e the perforation depth, wellbore flowing and tubing intake pressure are considered at the same depth When at a specific rate these two pressures are flo w equal. the is stable flow system is in equilibrium and The intersection of the IPR and TPR curves determines the rate of stable flow that can be expected from the particular well
- 30. NATURAL FLOW The intersection of the IPR and TPR curves determines the rate of stable flow that can well. be expected from the particular
- 31. NATURAL FLOW At points where IPR flow equals to TPR , the equilibrium rate flow and pressure constitute what is called the natural point and the equilibrium rate is called the natural flow rate There may be two points of intersection for multiphase mixtures., one represents a stable flow condition and the other an unstable one. The stable point of natural flow is to the right Mathematically, the stable point of natural flow exists when the two performance relations intersect with slopes (i.e., derivatives) of opposite sign. If the two curves have slopes of similar sign at the in rate point of intersection, then only a small change will cause the system to change its state of equilibrium, either point killing the well or moving it toward the stable of natural flow
- 32. NATURAL FLOW Natural flow rate and pressure usually change with reservoir depletion, depending on the variation in IPR and TPR resulting from changes in reservoir pressure and flow characteristics. The change of natural flow is usually toward a lower rate if all well parameters remain unchanged. To offset the natural decline in rate, it is possible to change equipment or operating criteria to maintain the desired rate of production. Lowering the wellhead pressure by choke manipulation or lowering of separator pressure are simplest and most common of the adjustments made by the operator. Artificial lift or treating wells by stimulation are other alternatives for maintaining a desired rate of production (these are more complicated and costly).
- 33. NATURAL FLOW Changing Wellhead Pressure Decreasing wellhead pressure by increasing choke opening will usually shift the TPR curve downward to a lower intake pressure (increasing the rate of natural flow) If = atmospheric condition, the well will P𝑤ℎ produce at Increasing its maximum flow rate. pressure will shift the wellhead the TPR curve upward (decreasing flow rate) If the wellhead pressure is increased beyond a certain point, then the well will stop producing because the required available pressure pressure exceeds the
- 34. NATURAL FLOW Effect of wellhead pressure on natural flow
- 35. NATURAL FLOW Changing Gas/Liquid Ratio The effect of a changing gas/liquid ratio is not as straightforward as for the case of changing wellhead pressure. It has different effects on the two components of pressure loss in Increasing GLR tubing-friction and hydrostatic. lightens the mixture density and therefore reduces the pressure loss due to hydrostatic forces. On other hand, larger quantities of gas usually increases pressure losses due to friction.
- 36. NATURAL FLOW Effect of gas/liquid ratio on natural flow
- 37. NATURAL FLOW Note, increase GLR pays only to a certain point, higher GLRs does not offset the additional costs of increasing the injected gas compared with incremental of oil produced Changing Tubing Diameter. The effect of tubing diameter on natural flow is similar to the effect of gas/liquid ratio Increasing diameter increases the rate of natural flow until a critical diameter is reached, after which rate will decrease Thus Natural flow is the primary criterion used to choose tubing size. include Other criteria price, availability, mechanical considerations, and future production characteristics
- 38. NATURAL FLOW Effect of tubing diameter on natural
- 39. NATURAL FLOW Changing Inflow Performance Deteriorating inflow performance is the natural result of reservoir depletion average absence reservoir pressure decreases in the of artificial pressure maintenance drive. or a strong natural water Gas and water injection can be used to arrest the decline in IPR caused by depletion. Additional reductions result from in inflow performance may (i) damage near the wellbore related to drilling and completion operations (ii) reduced drainage area due to infill drilling
- 40. NATURAL FLOW (iii) reduced permeability due to two-phase flow, compaction or fines migration, (iv) increased viscosity due to gas liberation from reservoir oil, or (v) transient effects usually associated with low- permeability formations. Note: For most flowing wells the actual difference in elevation between mid perforations and the tubing shoe is only about 30 feet, or the length of one joint of tubing. In other situations, the tubing shoe is substantially above the perforations and wellbore flowing pressure does not equal tubing intake pressure.
- 41. NATURAL FLOW Effect of changing inflow performance on natural flow
- 42. NATURAL FLOW Effect of a pump on well performance.
- 43. NATURAL FLOW (i) Now, to correct for the distance between the tubing intake and mid perforations, the separation extension interval should be considered as an of the tubing And an additional pressure drop along the interval is added to the pressure drop in the tubing and the composite is used to develop the tubing performance relation, the pressure drops is given as
- 44. NATURAL FLOW (ii) An alternative to adjusting the TPR curve for depth level separation is to transfer the IPR up to the of the tubing shoe. The resulting performance curve will be called the pseudo-IPR (or shifted IPR) However, the use of this method is generally not recommended except for special applications such as solving downhole pump
- 45. NATURAL FLOW Depth adjustment by (a) adjusting the tubing performance curve and (b) shifting the inflow performance curve.
- 46. Example 4 Assume a well 1 (W1) as discussed in example 3 has been tested at a rate of 202 STB/D during a three-day period. Stabilized wellbore flowing pressure measured 3243 psia. Another wells say W2 and W3 were previously tested with a multirate sequence, which indicated the exponent in the IPR equation (Fetkovich] ranges from 0. 77 to 0.81. if a value of 0.8 is assumed to apply to W1 well. Average reservoir pressure is 4000 psia. Determine the rate of natural flow, assuming the tubing performance calculations in example 3 apply (i.e., = 200psia, GLR = 600scf/STB, and 𝑃𝑤h 8000ft of tubing having a 3.5-in. nominal diameter).
- 47. Example Table (a) and (b) shows production and tubing performance data respectively, 1) Plot gas rate versus the difference of average reservoir pressure squared and intake 5 Multirate Data flowing pressure squared on the log-log plot and determine the point of natural flow for this well. 2) Plot the gas IPR and the tubing performance curves on Cartesian coordinates. Once again determine point of natural flow. Tubing Perfonnance Relation the 3) Discuss the advantages of a log-log plot of the well performance curves over a Cartesian plot.
- 48. Examples 6 Production from the Davis No. 5 (Examples 3 and 4) suddenly dropped after five years of production. By running a special tubing gauge tool, it was determined that the tubing had collapsed at 6537 ft. During a workover job to replace the tubing. it was discovered that the casing had also collapsed at the same depth. The collapsed casing interval has been reamed out to full bore and has been milled out 1 throughout the the pay zone. A 2-in. liner 6000 has been 5 set inside damaged casing from to 8000 ft. The well has been completed with 3.5-in. tubing which was run only to 5950 as shown in Fig. below. A 7 changeover to 2 8-in. to run the tubing inside the liner up to the perforations depth was considered too costly and unnecessary.
- 49. following A test the workover indicated an average reservoir pressure of 2000 psi a and a gas/oil ratio of 2500 scf/STB. In addition, a flowing pressure gradient in the 5.5-in. liner was measured as 𝐺f = 0.26psi/ft. During the test a rate of 320 STB/D was recorded, with a stabilized flowing bottomhole pressure of 842 psia. Assuming exponent n equals equation. 0.8 in the backpressure predict the natural flow of the well with 200psia wellhead pressure.