Vapor blow through avoidance in oil production

Abstract

A vapor blow through avoidance method, process and system for oil producing wells developed based on an innovative theory of vapor blow through pump. The system consists of casing gas remover, dynamic fluid level detector and downhole pump. Process includes adjusting casing gas remover and or pump rate based on result of comparison of the detected dynamic fluid level with the pre-set target dynamic fluid level; therefore, it prevents vapor in annular space blowing through pump and optimizes the well production. The avoidance system applies to single or group and horizontal or vertical wells.

Claims

1. A method of preventing vapor blow through in a production well, said method comprising: a. providing a vapor blow through avoidance system for an oil well, said system comprising: i. a casing gas remover (CGR); ii. a dynamic fluid level detector (DFLD) for detecting a dynamic fluid level (DFL); iii. a downhole pump (DHP); iv. a control processor operatively connected to said CGR, DFLD and DHP; b. said DFLD determining said DFL; c. said control processor comparing said DFL against a target DFL (DFLt) and: i. increasing a rate of said CGR or reducing a rate of said DHP if DFL<DFLt, ii. maintaining said rate of said CGR and said rate of said DHP if DFL=DFLt; iii. decreasing said rate of said CGR or increasing said rate of said DHP if DFL>DFLt.

2. The method of claim 1, said vapor blow through avoidance system further comprising temperature sensors, pressure sensors, flow sensors, and one or more pump operating parameter sensors.

3. The method of claim 1, wherein said CGR is a multiphase pump or compressor.

4. The method of claim 1, wherein said CGR is a casing gas blower (CGB) or adjustable choke (AC) or both.

5. The method of claim 1, wherein said CGR includes both an AC and a CGB and wherein primary control is via said AC and secondary control is via said CGB and ternary control is via said DHP.

6. The method of claim 1, wherein said determining step b is continuously determining said DFL.

7. The method of claim 1, wherein said determining step b is repeatedly determining said DFL.

8. The method of claim 1, wherein said DFLt is a range of acceptable dynamic fluid levels.

9. A method of preventing vapor blow through in a production well for producing oil from a reservoir, said method comprising: a. determining a dynamic fluid level (DFL) with a dynamic fluid level detector (DFLD), b. comparing said determined DFL against a target DFL (DFLt), and: i. increasing a rate of casing gas removal or reducing a rate of pumping fluid if DFL<DFLt; ii. maintaining said rate of casing gas removal and said rate of pumping fluid if DFL=DFLt; iii. decreasing said rate of casing gas removal or increasing said rate pumping fluid if DFL>DFLt.

10. The method of claim 9, wherein said DFLt is a range of dynamic fluid levels.

11. The method of claim 9, wherein said DFLt is a range of dynamic fluid levels at least one meter above zero, wherein zero is the level of intake of a downhole pump.

12. A vapor blow through avoidance system for an oil well, said system comprising: a. a casing gas remover (CGR) fluidly connected to a casing gas exit tube fluidly connected to an annular spacing around a production well tubing, wherein said CGR is a casing gas blower (CGB) or an adjustable choke (AC) or both; b. a downhole pump (DHP) inside said casing, connected to the said production tubing and having a pump intake at or near a well bottom; c. a dynamic fluid level detector (DFLD) for measuring a dynamic fluid level (DFL), said DFL being a height of a liquid in said annular spacing from a top of said pump intake to a gas cap in said annular spacing; and d. a control processor operatively connected to said CGR, CGB, DFLD and DHP and capable of comparing said DFL to a target DFL and adjusting said CGR or DHP to keep said DFL at said target DFL.

13. The system of claim 12, wherein said target DFL is a range of acceptable dynamic fluid levels.

14. The system of claim 12, wherein the DFLD continuously determines said DFL and said control processor: a. increases a rate of said CGR or reduces a rate of said DHP if DFL<DFLt; b. maintains said rate of said CGR and said rate of said DHP if DFL=DFLt; or c. decreases said rate of said CGR or increases said rate of said DHP if DFL>DFLt.

15. The system of claim 12, applied to a group of wells.

16. The system of claim 12, applied to a group of wells, each well having an AC and said group of wells having a common CGB.

17. The system of claim 16, said each well having a target DFL and said control processor primarily controlling each well via controlling said AC, secondarily controlling said common CGB, and ternary control of said DHP.

18. A computer system for preventing vapor blow through in an oil production well, said computer system accepting data from an operably connected dynamic fluid level detector (DFLD) and controlling an operably connected downhole pump (DHP) and controlling an operably connected casing gas remover (CGR), said computer system increasing a rate of said CGR or reducing a rate of said DHP if the dynamic fluid level (DFL) is less than a target DFL, and decreasing said rate of said CGB or increases said rate of said DHP if DFL is greater than said target DFL.

Description

BRIEF DESCRIPTION OF FIGURES

(1) The present system is demonstrated with respect to the following figures, which are exemplary only, and should not unduly limit the scope of the appended claims.

(2) FIG. 1A: Schematic of the normal operation of a production system with a downhole pump.

(3) FIG. 1B: Vapor build-up in annular space.

(4) FIG. 1C: Increasing gas build-up in annular space.

(5) FIG. 1D: Vapor blow through.

(6) FIG. 1E: Fluid fill-up after vapor blow through.

(7) FIG. 2: Vapor blow through model indexes.

(8) FIG. 3: Processor logic for vapor blow through avoidance.

(9) FIG. 4: Schematic of vapor blow through avoidance system—single well.

(10) FIG. 5: Schematic of vapor blow through avoidance for a group of wells.

(11) FIG. 6: Schematic of single well vapor blow through avoidance system with both AC and CGB.

DETAILED DESCRIPTION

(12) The present system is exemplified with respect to a SAGD well with an ESP pump. However, this is exemplary only, and the invention can be broadly applied to any high vapor producing well wherein the downhole pump has a tendency to blow through by vapor. The invention also has the advantage of reducing gas-locking, although this is not the primary intent. The following examples are intended to be illustrative only, and not unduly limit the scope of the appended claims.

The Problem

(13) Downhole pumps in the oil industry are designed mainly for lifting liquids. They are designed on the assumption that vapor is separated downhole and directed to the casing annulus, thus not entering the pump and causing problems. Depending on the pump specifications, the presence of vapor/gas phase more or less reduces the downhole pump efficiency.

(14) However, the amount of vapor that can be vented out from the annulus is restricted by the pressure of the casing gas treater. If the rate of the vapor accumulation is higher than the rate that expelled from the casing and tubing, e.g.:
Qdhg>(Qcsg+Qwhg)
More vapor will be accumulated in the casing annulus, and the increased volume and/or pressure can lower the level of liquid above the pump. If this level lowers to the pump intake level, vapor will enter the pump and reduce the overall pump performance, producing periods where no or low liquid is produced.

(15) We have studied a variety of parameters during normal and no-flow or low-flow conditions in actual SAGD wells, and our results are shown in simplified manner in FIGS. 1A-E to 2 and described below.

(16) FIG. 1A illustrates a typical normal flow condition, where vapor in annular is produced at a level that matches the vapor shunted out of the casing. Since gas removal occurs at levels equal to the rate of gas accumulation, the system is stable.

(17) In more detail, FIG. 1A (not drawn to scale) shows the SAGD chamber 110 where oil gravity drains to the casing liner 120. Oil enters the downhole pump 130, but vapor typically rises and is collected in the annular casing 150, where it travels via through casing valve 153 to e.g., casing gas treater 155, and from there to various treatments and/or shipment. Oil continues to flow up via production tubing 140 to valve 143 to e.g., production separator 145 and from there to various treatments and/or shipment. In a desired and ideal operation, such as that shown here, the total vapor entering the system is equal the vapor exiting the system via the casing valve 153. The system is thus stable.

(18) However, casing vapor removal is constrained by pressure and pipe size. When vapor accumulates faster than it can be removed, this results vapor column build up, as shown in FIGS. 1B and 1C. This vapor continuously accumulates in the annular space and pushes the dynamic fluid level (DFL) down (see arrows).

(19) Eventually vapor builds up to a sufficient level as to cause “Gas Blow Through,” as shown in FIG. 1D. In detailed explanation, when the vapor volume is large enough and the DFL is low enough (DFL=0), vapor breaks through into the pump 130 and production tubing 140. As a result, fluid density in the tubing 140 reduces due to vapor or gas emulsions in the tube and pump load reduces.

(20) At this time, well-head pressure approaches the level of casing head pressure. Even though the downhole pump is running, it runs idle, meaning little or no liquid is being “pumped” to the surface since the tubing is filled with mostly vapor or a gassy emulsion, resulting in a NF/LF event. In the case of an ESP pump, the pump current (amperage) drops due to the low load. Some downhole temperature change due to the Joule Thompson effect may also occur, associated with gas expansion or compression.

(21) The blow through is typically of short duration because the annular space volume is relative small, and typically the vapor accumulation rate is much lower than the blow through rate. Thus, the pressure is quickly released. After the blow through, the tubing/casing annular space refills with reservoir fluids (FIG. 1E), which makes the dynamic fluid level rise and production flow eventually recovers.

(22) The reservoir fluid may flow into the wellbore with a velocity that may create a temporary bottom hole pressure surging. This may be explained as a result of fluid velocity momentum due to the fact that reservoir fluid is hydraulically connected to the wellbore, and is many times larger in size than the wellbore.

(23) It is also noted that when fluid is filling up the wellbore the fluid column density increases from the prior vapor blow through condition, and that well head and/or bottom hole temperature changes may be observed due to Joule Thompson effect. The gas column build up may start again, and the cycle repeats.

(24) A simplified Vapor Blow Through Model Indexes are shown in FIG. 2 for an ESP pump case. As can be seen, when gas blow through occurs, the pump current drops although the pump frequency remains the same. This is because the vapor or gassy emulsion weighs less, which reduces the load on the pump, resulting in reduced current draw (amperage).

(25) Also seen in FIG. 2, the casing well-head pressure remains the same. Bottom hole or pump intake pressure increases when tubing fluid falls down and back to the annulus. Another reason for bottom hole pressure to increase is the wellbore is recharged by reservoir fluid. Once the blow though completed, a liquid fill-up stage occurs, wherein pump temperature and bottom hole temperature rise, fluid density in the tubing recovers and bottom hole pressure and pump intake pressure increase.

(26) This cycle could repeat at various rates, depending on the existing well conditions. For instance, cycle repeat can happen in hours for some high vapor wells, while in days or weeks for low vapor wells. It is also noted that the production rate also impacts the cycle period.

The Solution

(27) The solution to the problem of vapor blow through is the installation of a vapor blow through avoidance system, discussed next. The system typically requires the following components:

(28) 1. A casing gas remover (CGR), which can be a any type of compressor or multiphase pump, but preferably a casing gas blower (CGB) or an adjustable choke (AC), or both. The CGR is installed at e.g., the well-head casing to reduce casing gas pressure, removing it to e.g., the casing gas treater or other unit.

(29) 2. A dynamic fluid level (DFL) detector (DFLD) is installed at the well-head or downhole (as appropriate) that can detect the DFL. Such detectors detect e.g., the interface between vapor and liquid (or a pseudo interface) numerically representing DFL. Alternatively, this DFL can be calculated based on the bottom hole pressure if fluid density can be well defined. Other ways to calculate DFL include detecting fluid density profile by series of density sensor or pressure sensors. Buoyancy, sound wave detector, optic, temperature or acoustic, resistance or capacitance and other methods could be used as well. Either gradient, absolute value or their profile can be used to detect the DFL.

(30) 3. A downhole pump, which could be any pump used for lifting the fluid. It is noted that since ESP is used as example in this disclosure, amperage is the pump load indicator. As a skilled person knows for other types of pump, pump load is indicated as: rod pump by its load cell on rod, PCP (progress cavity pump) by rod torque and hydraulic pumps by their power fluid pressure.

(31) 4. A control processor that collects the related data, performs the analysis, and directs the action of the CGR and the DHP as needed.

(32) DFL is continuously collected with the DFLD and the processor compares the collected DFL with the DFLt. The system can also diagnose if vapor blow through is happening via checking other related production and pump performance data and comparison with the model index in FIG. 2. However, vapor blow through should not occur if the vapor blow through avoidance system is operating correctly.

(33) The CGR rate and DHP rate are then adjusted as needed based on the following logic (see also FIG. 3):

(34) a. Increase CGR rate, or reduce DHP rate as a second option, if gas column building up is detected to the pre-set criteria (DFL<DFLt).

(35) b. Reduce CGR or increase DHP rate if DFL>DFLt.

(36) c. Keep CGR and the DHP rates constant if DFL remains stable at the target level DFLt or within the target DFLt range.

(37) Importantly, removing casing gas will result in pressure reduction in the casing, which may further promote gas break out or steam flashing. Thus, the rate of gas exit through the CGB or AC should be controlled so the pressure does not get too low. Of course, the CGR should have enough power and throughput to be able to remove adequate vapor for practical ranges of casing pressure.

(38) The DFLt can be adjusted or changed any time between each logic cycle. Setting or changing the target DFLt is based on: pump submergible height request considering reservoir productivity and to allow the least frequent changes of the CGB and the highest possible pump rate. Typically, a suitable range of DFLs will be set as the target DFL, thus minimizing the on/off cycling of the systems.

(39) The schematic of the entire system is shown by FIG. 4. In FIG. 4, the SAGD chamber is 410 and it is fluidly connected to the casing liner (slotted liner) 420. Fluid enters pump 430 and is pumped to the surface via tubing 440 where it passes valve 443 on its way to e.g., unit 445. Vapor floats and is trapped in the annular space between casing 450 and pump tubing 440, past valve 453 to e.g., gas treater 455. Casing gas remover 454 is operably coupled to the control processor (herein represented symbolically with dotted lines). The control processor is also operably connected to a DFL detector 457 and pump 430. The control processor controls DFL primarily by activating the CGR, and secondarily by controlling the pump 430. The CGR 454 can be an adjustable choke or a casing gas blower or both can be used. FIG. 6 shows a system using both.

(40) A group well application is illustrated in FIG. 5 (three shown, but could be any number). Three wells are shown, each with a DFLD, pump, and AC. Common CGB is shown and is connected to common casing gas line, downstream of the individual lines. The control processor can be single or multiple, as desired, but a single processor is shown and is more cost effective. The processor is operably connected (see dotted line) to the DFLDs, pumps, ACs and common CGB.

(41) The DFLt is set individually for each specific well, and individual casing pressure is primarily controlled through the separate adjustable chokes (AC) installed on each gas casing. A larger CGB is installed and connected to the combined casing gas flow line for all three wells, and the CGB rate can be increased if the pressure is too high for the AC to function. The CGB should have sufficient horsepower and created sufficient pressure sink and rate for the combined wells. One advantage of this embodiment is cost savings, since multiple AC's are used instead of multiple CGBs. The ACs are passive, thus also saving energy costs over CGB use.

(42) A schematic of an alternate embodiment is shown in FIG. 6. In FIG. 6, the SAGD chamber is 710 and it is fluidly connected to production tubing (slotted liner) 720. Fluid enters pump 730 and is pumped to the surface via tubing 740 where it passes valve 743 on its way to e.g., unit 745. Gas floats and is trapped in the annular space between outer casing 750 and pump tubing 740, past valve 753 to e.g., gas treater 755. CGB 754 and adjustable choke 756 are fluidly connected to the casing gas exit line and operably coupled to the control processor (herein represented symbolically with dotted lines). The control processor is also operably connected to a DFLD 757 and pump 730. The control processor controls DFL primarily by activating the AC, because this is a passive system not requiring energy. If needed, the CGB can be activated as a secondary control measure, and as a ternary option, the DHP speed can by changed by controlling the pump 730.

(43) The process is applicable to any high gas content producing well, where gas disturbs pump performance. The producing well could be crude oil or gas well or any subsurface reservoir fluid producing well, including horizontal, vertical, deviated and cluster wells, for instance coal bed methane water removing well or SAGD bitumen producing well. Equipment and process control computer program can be further developed and manufactured based on this innovation.