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Downhole Gas Separator Performance In Sucker Rod Pumping System

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Presentation on theme: "Downhole Gas Separator Performance In Sucker Rod Pumping System"— Presentation transcript:

1 Downhole Gas Separator Performance In Sucker Rod Pumping System
Beam Pumping Workshop Houston, Texas October 4 - 7, 2005 Downhole Gas Separator Performance In Sucker Rod Pumping System Good afternoon, my name is Manuel Guzman and today I’ll present you the downhole gas separator performance in sucker rod pumping system. During these 20 minutes I’ll show you what happens with our reservoir fluids inside the well. Manuel Guzman Augusto Podio

2 Overview Description of the problem System schematic
Bubble flow forecast Gas separation testing facilities Pump volumetric efficiency for actual wells Conclusions I will start this presentation giving you an idea of the addressed problem, with this in mind I’ll show you a schematic of a downhole gas separator and discuss the objective for the mathematical model developed to forecast the bubble flow path. Using our gas separation testing facilities at The University of Texas at Austin we studied continuous flow downhole gas separation, and we combined this information with the actual well dynamic data to calculate pump volumetric efficiency for several combinations of downhole gas separators and pumping equipment. At the end I’ll summarize some conclusions that were observed.

3 What Is The Problem? Design and selection of downhole gas separators are usually made using heuristics. Generally the performance is much below than expected. As petroleum engineers we know that the majority of pumping wells have a low volumetric pump efficiency, mainly because in many cases the pump cannot be located below the perforations to allow any gas to vent in the annulus above the pump. Locating the pump below the perforations would be the best method of achieving high volumetric efficiency, but unfortunately it is not done very often. Then the production engineer decides to use a downhole gas separator, that is also called a gas anchor, to reduce the impact of the gas entering into the pump. The most commonly used downhole gas separator is known as a Poorboy separator, which is represented here. It consists of a perforated tubing nipple and a mud anchor 30 ft long and a dip tube inside. Although this is an excellent idea, the problem is that design and selection of downhole gas separators are usually made using heuristics, you know, rules of thumb, and this usually causes a performance that is much below than expected. Because of this, it was decided to study in detail the actual fluid dynamics inside such separators, with the objective of improving their design and performance.

4 Downhole Separator System
V plunger V slip Here we have a schematic of a downhole gas separator system. As a brief introduction we have 4 important variables to keep in mind while designing and choosing a gas anchor. Those are: the gas velocity inside the anchor, the liquid velocity inside the anchor, the slip velocity of the gas, also called terminal bubble velocity and the velocity of the plunger. In this animation we can see how the liquid flows into the separator until it reaches the pump. Meanwhile the majority of the gas flows thru the annulus and part of it is trapped by the liquid into the separator. The gas inside the separator partially is released at the top of the separator, but the rest continue flowing until it reaches the pump. V liquid in anchor V gas in anchor

5 Gas Velocity Inside the Anchor
V plunger Net gas velocity is difference between gas slip velocity (up) liquid velocity (down) Liquid velocity depends on: ID of anchor OD of dip tube Plunger diameter and velocity The net gas velocity inside the anchor can be expressed as the difference between the gas slip velocity that goes up mainly because of buoyancy forces, and the downwards liquid velocity that causes a drag force. The liquid velocity inside the separator depends on the internal diameter of the anchor, the external diameter of the dip tube and also the pump plunger diameter and velocity.

6 Instantaneous Liquid Flow Rate
Conventional Dplunger=1 in Ls=86 in 8.45 SPM 200 BPD All those equation look nice, but they should predict the gas behavior in real wells. For that reason we need a relationship between the plunger velocity and the instantaneous liquid flow rate. The plunger velocity data presented in the chart came from a real well using a conventional unit with 1.5 in plunger diameter a stroke length of 86 inches and operating at 8.45 strokes per minute. As is presented in the chart the red line represents the average liquid production, which is approximately 200 BPD, but if we calculate the instantaneous flow rate, it goes about 4 times greater than the average. Then if the average rate is used for design purposes we are underestimating the real liquid velocity inside the gas anchor and then we would select or design an inefficient separator. Upstroke Downstroke

7 Forecast for Different Bubble Sizes
Clift, Grace and Webber (1978) Stroke 1 Stroke 2 Stroke 3 Bubble motion inside a separator with rod pump. Diam. Dip tube=1.5 in Plung. Diam.=1.5 in Conventional Unit, Ls=86.3 in, 8.45 SPM. Flow rate=151 BPD As we could notice in the video, we don’t have a particular bubble size inside the separator. Instead we have a size distribution inside the separator. Clift, Grace and Webber worked in this subject in 1978 and determined a relationship between terminal velocity and the equivalent bubble diameter. For contaminated water the diameters for a 1 inch/sec, 3 inches per second and 6 inches per second would be 0.3 mm, 0.7 mm and 1.8 mm respectively. Using this information in the mathematical model we can see how the smaller bubbles are trapped but the 1.8 mm bubble is released.

8 Gas Separator Testing – Univ. of Texas
BHP Air purge Hydrostatic Column Flow Control to keep BHP constant Air Supply Air out Manifold Mix Pump L.C. 50 ft high/ 6 in. diam. For this project a gas separation testing facility was built to analyze the performance of different separator under the flow of water and air. In the sketch we can see how our separator is located at the bottom of the structure. The well counts with several intake positions for the fluid. The variable that are measured include the bottom hole pressure, the pressure at the ports, the pump intake pressure, the gas rate at the intake and after the surface separation and the intake liquid rate. In this video we can see in detail how the separator is placed inside the transparent casing, here we see some perforations, then the annular gas escapes thru the casing and the liquid with the trap air is recycled to the three phase field separator, where the produced air is measured and the liquid is then pump again to our mixer, which also works as a manifold where i can control which perforations are injecting fluid into the well.

9 Gas Separator Testing – Univ. of Texas
In this slide i present some details of the separator. The perforations, the separator inlet slots colored in yellow, the dip tube which can be 1 inch or 1.5 inches diameter, the separator tube that is 3 inches OD and the 6 inches OD casing Perforations Separator Inlet Slots Dip Tube Separator Tube Casing

10 Separator Performance (Continuous Flow)
SEPARATOR TYPE: Echometer 1 (2 x 4" slots) Air and water entering below 10 psi 2 The data obtained from the laboratory was plotted to evaluate the impact on the separator performance for continuous flow of the two variables mentioned before: the annular gas rate (Y axis) and the liquid rate of the pump( X axis).The vertical axis of the graph corresponds to the flow rate of gas flowing through the dip tube into the pump. The experiments started at the highest liquid rate and gas rate available, then the gas rate was reduced, after that the liquid rate was reduced by half, and the procedure was repeated until we reached a zero value of the gas flow through the dip tube. In the still images we can see how those value correlate with the bubble distribution inside the separator. 1 5 2 3 5 Gas Rate through Separator (MSCF/D) 4 6 7 8 8 Gas rate entering the well (MSCF/D) Liquid rate of the pump the well (BPD)

11 Downhole gas separator selection
With several options of separators it is difficult to select the right one. Two common situations: I have a well with specific conditions, which separator is my best choice? I have a separator, In which kind of well can I use it efficiently?

12 Separator Selector Spreadsheet
Designed for using with Excel© Determine separator performance for continuous flow Input: Average liquid rate Gas rate Casing diameter Output: Separator that offers the greatest liquid fillage for the given conditions

13 Example 200 BPD and 100MSCFD with a 7” casing
Patterson 1 using a 3 1/2” separator would offer the best performance Inputs (liq. rate, gas rate, csg. diam.) Outputs (separator, dimensions) Gas is entering the pump Boundary obtained with lab data Region of zero gas thru pump

14 What If This Were a Rod Pumped Well?
PATTERSON 1 (OD DIP TUBE = 1”; # OF SLOTS =8; DIMEN. OF THE SLOTS =8" x 1/8") Pc = 10 psi; POSITION OF THE SEP. = ABOVE THE PERFORATIONS Superficial Liquid Velocity varies during the stroke The laboratory separator performance presented so far is related to continuous flow ( as would be present in progressing cavity pumps), but what if this were a rod pumped well? Here is an animation for the case of the Patterson 1 separator using a reciprocating pump. First the well has a fixed annular gas rate, but the liquid rate changes as is shown through the animation, during the upstroke the superficial liquid velocity increases, reaches a maximum, reduces its speed and then it is zero for the last half of the stroke. 2 1 Gas Rate through Separator (MSCF/day) 3 4 5 6 Superficial Gas Velocity in casing annulus (in/sec) Superficial Liquid Velocity inside Separator (in/sec)

15 Sucker Rod Simulator A special butterfly valve was built and installed in the return line It will be automatically operated to obtain the desired on/off time Flow will be measured using a mass flow meter after the valve 2 in Pipe Motor Drive z x ½ in shaft 6 in

16 Intermittent Flow Behavior
Patterson 8 Flow rate = 275 BPD Gas rate = 55 MSCFD Pump speed =6 SPM (1 stroke = 10 sec) Gas enters the pump only during a fraction of the 5 sec. upstroke. Gas column moves uniformly during each stroke. Bubble size distribution changes with during stroke.

17 Calculated Pump Liquid Fraction (Fluid Entering Below Ports)
A reduction in pump liquid fraction was found when dip tube diameter was increased (Echometer 2 & Patterson 5) Up to 87% of liquid fillage can be achieved None of the evaluated separators reached the goal of 100% If we put together the laboratory data for continuous flow and the velocity profile from the actual well, and using the mathematical model we can predict the pump liquid fraction at the top of the stroke using different separator geometries. During the laboratory stage 10 separator were evaluated and the poorboy was used as the base case. Then from the chart we can observe that …

18 Conclusions The instantaneous flow rate during the pump stroke should be used for the separator design. The gas flow rate in the casing has a major effect on the gas separation efficiency. Separator efficiency depends on the stroke length (Ls), plunger speed and the dip tube diameter, for each given geometry in a rod pump well. Visual observation confirms that the best way to maximize the gas separation is to set the intake below the perforations, if possible. All this work gave us the following conclusions…

19 Future work: carry out additional intermittent flow tests to validate the mathematical predictions.
Special thanks to: Yates Petroleum Q&A Session Finally I would like to give special thanks to echometer and conoco-phillips for their support and Dr. Augusto Podio for his guidance. Thank you very much for your attention, right now we can start the Q&A section.

20 Downhole Gas Separator Performance In Sucker Rod Pumping System
Beam Pumping Workshop Houston, Texas October 4 - 7, 2005 Downhole Gas Separator Performance In Sucker Rod Pumping System Good afternoon, my name is Manuel Guzman and today I’ll present you the downhole gas separator performance in sucker rod pumping system. During these 20 minutes I’ll show you what happens with our reservoir fluids inside the well.

21 Effect of Geometry Poorboy Patterson 3 Number of holes: 12
Liquid rate entering the well (BPD) Gas rate entering the well (in/sec) Gas Rate through Separator (MSCF/day) Gas Rate through Separator (MSCF/day) But also, the performance of the downhole separator system is determined by the geometry of the entry ports. If we compare the performance of the poorboy with for example the patterson 3, the zero flow-through zone, in gray, is much smaller for the poorboy than for the patterson 3, which also presents lower gas rate thru the separator at highest liquid rates than the poorboy separator Gas rate entering the well (MSCF/D) Liquid rate entering the well (BPD) Poorboy Patterson 3 Number of holes: 12 Diameter: 3/8” Area 1.3 in2 Number of slots: 8 Dimension: 8" x 1/2“Area 32 in2

22 Background Research Understanding and Combating Gas Interference in Pumping Wells. Joe Clegg, 1963 Another Look at Gas Anchors. Joe Clegg, 1989 Characterization of Static Downhole Gas Separators. Jorge Robles, 1996 The Effect of Geometry on the Efficiency of Downhole Gas Separator. Omar Lisigurski, 2004 The study and analysis of downhole gas separators started in the sixties when Joe Clegg worked over the gas interference in pumping wells, then in 1989 he published that poorboy is not a good option in high production wells. By 1996 Jorge Robles worked on the characterization of different static downhole gas separators using a pump system. Last year Omar Lisigurski studied the effect of geometry on continuous flow. His work was the starting point for this research.

23 Mark II (3”OD, 1” Dip Tube)

24 Rotaflex (3”OD, 1” Dip Tube)

25 Liquid Fraction (Mark II, fluid entering below the anchor ports)

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