EP3085885B1 - Verfahren, vorrichtung und computerprogramm zur bestimmung der herstellung von der jeweiligen fertigstellung eines aus einer doppelzonenfördersonde angehobenen gases - Google Patents

Verfahren, vorrichtung und computerprogramm zur bestimmung der herstellung von der jeweiligen fertigstellung eines aus einer doppelzonenfördersonde angehobenen gases Download PDF

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EP3085885B1
EP3085885B1 EP15164713.8A EP15164713A EP3085885B1 EP 3085885 B1 EP3085885 B1 EP 3085885B1 EP 15164713 A EP15164713 A EP 15164713A EP 3085885 B1 EP3085885 B1 EP 3085885B1
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Prior art keywords
flow rate
completion
gas lift
relationship
well
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French (fr)
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EP3085885A1 (de
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Abdelhamid Guedroudj
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Petroleum Experts Ltd
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Petroleum Experts Ltd
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/06—Measuring temperature or pressure
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
    • E21B43/121—Lifting well fluids
    • E21B43/122—Gas lift

Definitions

  • the present disclosure relates to a method of, and apparatus for monitoring the production of hydrocarbons from a reservoir via a well comprising dual completions, and in particular for predicting the volumetric rate of gas lift gas flowing into each well completion in a well completed with a dual completion. This allows the production from each completion of a dual completion well to be separately calculated.
  • Gas lift is an artificial lift method which comprises injecting gas into the production tubing string to reduce the hydrostatic pressure of the production fluid. This injection of gas reduces the bottomhole pressure, thereby allowing fluids to be produced from the reservoir at a higher flow rate.
  • the production gas may be conveyed down the tubing-casing annulus and injected into the production tubing via one or more gas lift valves and/or orifices.
  • a method of monitoring the production of hydrocarbons from a reservoir via a well comprising a dual completion, each completion producing from a different reservoir formation as claimed in claim 1.
  • a computer program comprising computer readable instructions which, when run on suitable computer apparatus, cause the computer apparatus to perform the method of the first aspect.
  • Nodal analysis calculates the pressures and rates within a system from fixed boundary conditions.
  • Figure 1 shows a diagram of a model representing a single tubing string 100 producing from a reservoir 110.
  • the model can be considered to start at the edge of the drainage region within a reservoir, where the pressure will be the drainage region pressure P R , and continues until the wellhead 120 at the top of the tubing string.
  • the wellhead pressure P WH at the top of the tubing string and the pressure at the edge of the drainage region P R can be considered boundary conditions of the model and are fixed for any given calculation.
  • a tubing string 100 can be split into two main parts; the inflow and the outflow.
  • the inflow of the tubing string also called the inflow performance relationship or IPR
  • IPR inflow performance relationship
  • the outflow of the tubing string (also called the vertical lift performance or VLP) considers the path from the bottom of the well to the wellhead 120.
  • a multiphase flow wellbore pressure drop model e.g., a correlation
  • the bottomhole pressure To calculate the pressure P BH at the 'solution node' 130 (often referred to as the bottomhole pressure); one can consider firstly, the drainage region pressure into the solution node and secondly, the tubing head pressure down to the solution node. Both of these pressure drops depend upon the production flow rate being produced.
  • Figure 2 is a plot of pressure P against production flow rate Q. Shown on the plot is the IPR curve (inflow) 210 and VLP curve (outflow) 220.
  • a solution node pressure may be estimated by considering the IPR and VLP pressure relationships. Both IPR and VLP pressures vary as a function of production flow rate Q. If a single liquid production rate Q L is defined within a well, a solution to both pressure relationships would be at the intersection of these two curves 230. Therefore, by calculating VLP and IPR curves for the current conditions, and finding the intersection point of the two curves, the production flow rate Q L produced by a well can be determined. Clearly, a VLP curve needs to be calculated in order to infer the solution node pressure P BH .
  • FIG 3 is a schematic illustration of a dual completion arrangement arranged to produce a first formation 310 and a second formation 320 of a reservoir.
  • a completion comprises generally a tubing string and associated equipment required for production from a well.
  • the arrangement illustrated comprises a first tubing string 330 and a second tubing string 340 inside a casing 350.
  • An annulus 360 is defined between the casing 350 and production tubing strings 330, 340.
  • the proposed method acts to predict the gas lift gas flowing into each tubing string of a dual (or multiple) completion. This enables the production from each tubing string to be determined, which can be summed to compute the overall well performance.
  • FIG. 4 is a flowchart describing a first stage of the method according to an embodiment of the invention.
  • This first stage of the method comprises determining the sensitivity of pressure P BH and production flow rate Q L at the solution node, on the gas lift rate Q g . This is done by determining a number, n, of VLP curves, one for each of a number of gas lift rates Q g,i , and an IPR curve for each completion. Each intersection of a VLP curve with the IPR curve corresponds to a different gas injection rate; however in each case the same water cut WC, gas-oil ratio GOR and tubing head pressure is applied, and can be obtained either from measurements in the field or well test data.
  • a gas lift rate of the iteration Q g,i is set.
  • Gas lift rate is an exemplary parameter used in this embodiment; any other parameter related to the amount of gas lift gas introduced to the production tubing string can be used.
  • the choice of gas lift rate may be arbitrary for the first iteration, and may increase incrementally for subsequent iterations, so as to cover a realistic range of gas lift rates over the course of this stage of the method.
  • the first gas lift rate may be at the high end of the range and decrease for each iteration, or other methods of setting a different gas lift rate for each iteration may be employed.
  • VLP and IPR relationships are calculated for each completion.
  • the IPR relationship will be the same for each iteration and therefore need only be calculated (for each completion) in a first iteration.
  • the VLP relationship is dependent upon the gas lift rate and therefore will be different for each iteration.
  • Figure 5 is a graph of bottomhole pressure P against production flow rate Q L resultant from this step (for one of the completions), after n iterations. It shows a IPR curve 500, a number of VLP curves 510, each one representing a different nominal gas lift rate Q g,i for that completion.
  • Each intersection 520 of a VLP curve 510 with the IPR curve 500 yields an intersection production flow rate Q L,i and an intersection bottomhole pressure P BHi corresponding to each nominal gas lift rate Q g,i .
  • the intersection bottomhole pressure P BHi from the previous step is used to compute a pressure profile (vs. the depth) in the relevant completion. This may be done using the same multiphase flow correlation applied when calculating the VLP.
  • Figure 6(a) is a graph of pressure P against depth D resultant from this step, for a single iteration and completion.
  • a separate pressure drop calculation should be performed across the gas lift valve. This may be computed based on the amount of gas injected (corresponding to the VLP curve) and the orifice size.
  • the pressure drop ⁇ P valve across the gas lift valve can either be computed with an orifice choke model or alternatively using the manufacturer's curves.
  • This pressure drop ⁇ P valve is added to the tubing pressure at the gas lift valve depth D valve .
  • the casing gradient is computed up to the casing head to yield the casing head pressure P ch,i for the completion. This is illustrated in the graph of Figure 6(b) . This is repeated for each iteration.
  • performance plots are updated.
  • the performance plots show casing head pressure P ch and liquid rate Q L as a function of gas lift rate Q g , for each completion, the plots being generated over a number of iterations.
  • Figure 7 shows examples of such performance plots.
  • Figure 7(a) is a plot of fluid production rate Q L as a function of gas lift rate Q g
  • Figure 7(b) is a plot of casing head pressure P ch as a function of gas lift rate Q g .
  • n may be any number over 1, and may be for example, between 5 and 100, between 10 and 50 or may be in the region of 20. If there have been sufficient iterations, then the routine ends (step 460). If there have not been sufficient iterations, another iteration (step 470) is performed using a different gas lift rate Q g,i at step 410.
  • the allocation of gas lift to each completion can be calculated based on the physical principle that both completions must share the same casing head pressure, as there is pressure communication throughout the casing. This principle can be applied in a second stage of the method, through two independent embodiments which will each provide an estimate for the gas lift allocation.
  • Figure 8 is a flowchart illustrating the first of these approaches.
  • the method uses the measured casing head pressure (obtained at step 810) from field measurements and the performance curves to estimate the gas lift rate Q g,comp1 , Q g,comp2 and (optionally) fluid production rate Q L,comp1 , Q L,comp2 for the first completion (step 820) and the second completion (step 830) independently.
  • the fluid production flow rates Q L,comp1 , Q L,comp2 for the first completion and second completion can then be summed (step 840) to provide the overall well production flow rate Q L .
  • the gas lift rates Q g,comp1 , Q g,comp2 for the first completion and second completion can be summed to yield the total gas lift rate Q g,well .
  • the calculation can be validated by comparing the total calculated gas lift with the measured total gas lift for the well.
  • the method of Figure 8 is illustrated conceptually in Figure 9 (for the first completion only).
  • the top curve 900 is the performance curve of production flow rate Q L,comp1 against gas lift rate Q g,comp1 for the first completion.
  • the bottom curve 910 is the performance curve of measured casing head pressure P ch against gas lift rate Q g,comp1 for the first completion.
  • the gas lift rate Q g,comp1 for the first completion can be obtained from the measured casing head pressure P ch using the performance curve 910.
  • This gas lift rate Q g,comp1 can then be used to find the production flow rate Q L,comp1 for the first completion using the performance curves 900. This can then be repeated for the second completion using the appropriate performance curves for the second completion and the same measured casing head pressure P ch (as the casing head pressure is the same for both completions).
  • the calculation can be validated by comparing the total calculated gas lift rate with the measured total gas lift rate for the well.
  • Figure 10 is a flowchart illustrating the second approach for calculating the allocation of gas lift rate to each completion, according to an embodiment of the invention.
  • the second approach takes the total measured gas lift rate Q g,well for the well from the field measurements and uses the performance curves to estimate the gas lift and liquid production for each completion by iteratively finding the gas lift ratio which minimises the difference in calculated casing pressure for the two completions.
  • the method starts at step 1000, with an arbitrary gas lift ratio.
  • the gas lift ratio is the ratio describing the division of the total measured gas rate Q g,well between the first completion and the second completion.
  • the initial gas lift ratio is 0.5 (i.e. a 50/50 split), but any initial arbitrary ratio may be chosen.
  • the total measured gas lift rate Q g,well is obtained, and at step 1020, this total measured gas lift rate is divided between the first and second completions according to the present gas lift ratio.
  • a casing pressure P c,comp1 is calculated based upon the allocated gas lift ratio Q g,comp1 for the first completion determined in the previous step.
  • a casing pressure P c,comp2 is calculated based upon the allocated gas lift ratio Q g,comp2 for the second completion determined in step 1020.
  • the routine ends (step 1060).
  • the gas lift allocation arrived at following this algorithm can then be used, with the total measured gas rate Q g,well to determine the rate of gas lift gas delivered to each completion. Once this is determined, it is possible to determine the production fluid rate for each completion using the corresponding performance curve of production fluid rate against gas lift gas for the completion.
  • the calculation can be validated by comparing the calculated casing head pressure with the measured casing head pressure for the well.
  • the method of Figure 10 is illustrated conceptually in Figure 11 .
  • the total measured gas lift rate Q g,well is divided according to the gas lift ratio and allocated such that Q g,comp1 is x% of the total measured gas lift rate Q g,well and Q g,comp2 is (100-x)% of the total measured gas lift rate Q g,well .
  • a value for the casing head pressure P ch,comp1 and P ch,comp2 is determined for each completion, and a difference between casing head pressures P ch,comp1 and P ch,comp2 is then calculated.
  • the curves 1120 and 1130 can be used to determine the production flow rate Q L,comp1 and Q L,comp2 for the first and second completions.
  • representative performance curve for the well i.e., both completions
  • the principle that the casing head pressure is the same for both completions is again used.
  • a sensitivity on the casing pressure is carried out, from which the variation of gas lift rate to each completion and the corresponding fluid production rate from each completion can be determined.
  • These are then summed to determine variation of the total gas lift rate with casing head pressure, and the variation of the total fluid production rate of the well with the total gas lift rate.
  • Corresponding gas lift rates and fluid production rates are recorded per completion for varying casing head pressure. In each case, the per completion rates can be summed to obtain the corresponding gas lift rates and fluid production rates for the well.
  • Figure 14(a) is a plot of well fluid production rate Q L,well (equals the sum of Q L,comp1 and Q L,comp2 ) as a function of well gas lift rate Q g,well (equals the sum of Q g,comp1 and Q g,comp2 ).
  • Figure 14(b) is a plot of casing head pressure P ch as a function of well gas lift rate Q g,well . These are similar to the performance curves for a completion, as shown in Figure 7 . Of main interest for optimisation purposes is the plot of Figure 7(a) showing variation of well fluid production rate with well gas lift rate.
  • step 1215 additional performance curves are added to the Figure 17(b) plot, corresponding to differing flowing wellhead pressure (FWHP) values.
  • the pressure profile (and therefore the calculated casing head pressure P ch,i ) is dependent on the flowing wellhead pressure (also labelled on Figure 6 ).
  • Figure 15 is a graph of well fluid production rate Q L,well as a function of well gas lift rate Q g,well showing a number of performance curves, each corresponding to a different flowing wellhead pressure FWHP 1 -FWHP 4 .
  • many more than four of such performance curves may be generated for a well. In this way, the entire performance of the well can be captured.
  • performance curves can then be fed into a network model describing the well or a plurality of wells (step 1220).
  • the model can then be solved (step 1230), as part of an optimisation algorithm which can vary either the flowing wellhead pressure or gas lift rate for the well in order to find optimal values for these parameters, so as to maximise oil production.
  • One or more steps of the methods and concepts described herein may be embodied in the form of computer readable instructions for running on suitable computer apparatus, or in the form of a computer system comprising at least a storage means for storing program instructions embodying the concepts described herein and a processing unit for performing the instructions.
  • the storage means may comprise a computer memory (of any sort), and/or disk drive, optical drive or similar.
  • Such a computer system may also comprise a display unit and one or more input/output devices.
  • the concepts described herein find utility in all aspects of surveillance, monitoring, optimisation and prediction of hydrocarbon reservoir and well systems, and may aid in, and form part of, methods for extracting hydrocarbons from such hydrocarbon reservoir and well systems.

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Claims (10)

  1. Ein Verfahren zum Überwachen der Herstellung von Kohlenwasserstoffen aus einem Reservoir über eine Sonde, die eine doppelte Fertigstellung beinhaltet, wobei sich jede Fertigstellung aus einer unterschiedlichen Reservoiranordnung ergibt, wobei das Verfahren für jede Fertigstellung Folgendes beinhaltet:
    Erhalten von ersten Daten, die eine erste Beziehung (210, 500) beschreiben, die die Änderung des Produktionsdurchflusses mit Druck zwischen einem Punkt innerhalb der relevanten Reservoiranordnung und dem Sondenboden beschreibt,
    Durchführen der folgenden Schritte für jede Fertigstellung:
    Erhalten von mehrfachen Sätzen von zweiten Daten, wobei jeder Satz von zweiten Daten eine zweite Beziehung (220, 510) beschreibt, die die Änderung des Produktionsdurchflusses mit Druck zwischen dem Sondenboden und dem Sondenkopf für eine Vielzahl von Sollwerten für einen Gasdurchfluss des Gasauftriebs beschreibt,
    wobei sich der Gasdurchfluss des Gasauftriebs auf die Menge des Gases des Gasauftriebs bezieht, das während der Herstellung für die Fertigstellung in Bearbeitung eingeleitet wird;
    gekennzeichnet durch
    Verwenden der ersten Daten und der zweiten Daten, um eine dritte Beziehung zu bestimmen, die die Änderung eines Rohrkopfdrucks innerhalb der Sonde mit dem Gasdurchfluss des Gasauftriebs (440) beschreibt, durch das Bestimmen jedes Schnittpunkts jedes Satzes von zweiten Daten mit den ersten Daten, um einen Schnittwert (230, 520) für Druck und einen Schnittwert (230, 520) für den Produktionsdurchfluss für jeden des Sätzen von zweiten Daten zu erhalten, wobei die Schnittwerte für Druck und Produktionsdurchfluss verwendet werden, um die dritte Beziehung zu bestimmen;
    Verwenden der bestimmten dritten Beziehung und der Annahme, dass der Rohrkopfdruck für jede Fertigstellung der gleiche ist, um den Gasdurchfluss des Gasauftriebs für die Fertigstellung in Bearbeitung zu bestimmen.
  2. Verfahren gemäß Anspruch 1, wobei der Schritt des Verwendens der ersten Daten und der zweiten Daten, um die dritte Beziehung zu bestimmen, das Verwenden des Schnittwerts für Druck und jedes entsprechenden Sollwerts für den Gasdurchfluss des Gasauftriebs beinhaltet, um einen Wert für den Rohrkopfdruck zu bestimmen, der jedem der Sollwerte für den Gasdurchfluss des Gasauftriebs (430) entspricht.
  3. Verfahren gemäß einem der vorhergehenden Ansprüche, wobei der Schritt des Bestimmens des Gasdurchflusses des Gasauftriebs für jede Fertigstellung Folgendes beinhaltet:
    Erhalten eines Messwerts des Rohrkopfdrucks, der beiden Fertigstellungen gemein ist;
    und für jede Fertigstellung (810):
    Verwenden des Messwerts des Rohrkopfdrucks und der bestimmten dritten Beziehung, die relevant für die Fertigstellung in Bearbeitung ist, um den Gasdurchfluss des Gasauftriebs für diese Fertigstellung (820, 830) zu bestimmen.
  4. Verfahren gemäß einem der Ansprüche 1 bis 3, wobei der Schritt des Bestimmens des Gasdurchflusses des Gasauftriebs für jede der Fertigstellungen Folgendes beinhaltet:
    Erhalten eines Messwerts eines Gesamtgasdurchflusses des Gasauftriebs, der sich auf die Gesamtmenge des Gases des Gasauftriebs bezieht, das während der Herstellung für beide Fertigstellungen (1010) eingeleitet wird;
    Auswählen eines nominellen Zuteilungsverhältnisses, das die Zuteilung des Gesamtgasdurchflusses des Gasauftriebs zwischen den Fertigstellungen (1020) beschreibt;
    Bestimmen eines Fehlerwerts, der sich auf den Unterschied bei berechneten, aus dem nominellen Zuteilungsverhältnis (1050) folgenden Rohrkopfdrücken bezieht;
    Aktualisieren des nominellen Zuteilungsverhältnisses, um den Fehlerwert (1070) zu minimeren;
    Wiederholen von Iterationen der vorherigen zwei Schritte, bis der Fehlerwert unter einen Schwellenwert minimiert ist; und
    Verwenden des endgültigen Zuteilungsverhältnisses, um einen Gasdurchfluss des Gasauftriebs für jede Fertigstellung zu bestimmen.
  5. Verfahren gemäß einem der vorhergehenden Ansprüche, das das Durchführen der folgenden Schritte für jede Fertigstellung beinhaltet:
    Verwenden der ersten Daten und der mehrfachen Sätze von zweiten Daten, um eine vierte Beziehung zwischen dem Produktionsdurchfluss für die Fertigstellung in Bearbeitung und dem Gasdurchfluss des Gasauftriebs zu bestimmen; und
    Verwenden des bestimmten Gasdurchflusses des Gasauftriebs und der bestimmten vierten Beziehung, um den Produktionsdurchfluss für die Fertigstellung in Bearbeitung zu bestimmen.
  6. Verfahren gemäß Anspruch 5, wobei das Verfahren ferner die folgenden Schritte beinhaltet:
    Verwenden der bestimmten dritten Beziehung und der bestimmten vierten Beziehung für jede Fertigstellung, um Folgendes zu bestimmen:
    eine fünfte Beziehung zwischen dem Rohrkopfdruck innerhalb der Sonde und einem Gesamtgasdurchfluss des Gasauftriebs, der sich auf die Gesamtmenge des Gases des Gasauftriebs bezieht, das während der Herstellung für beide Fertigstellungen (1010) eingeleitet wird; und
    eine sechste Beziehung zwischen dem Gesamtproduktionsdurchfluss von beiden Fertigstellungen und dem Gesamtgasdurchfluss des Gasauftriebs (1210).
  7. Verfahren gemäß Anspruch 6, das den weiteren Schritt des Bestimmens der sechsten Beziehung für die Sonde für eine Vielzahl unterschiedlicher Fließdrücke am Sondenkopf (1215) beinhaltet.
  8. Verfahren gemäß Anspruch 7, das die folgenden Schritte beinhaltet:
    Verwenden der sechsten Beziehung, die für eine Vielzahl unterschiedlicher Fließdrücke am Sondenkopf als Input für ein die Sonde (1220) beschreibendes Modell bestimmt wird; und
    Durchführen eines Optimierungsalgorithmus, der einen oder beide Fließdrücke am Sondenkopf oder den Gesamtgasdurchfluss des Gasauftriebs variiert, um die Kohlenwasserstoffproduktion (1240) zu maximieren.
  9. Ein Computerprogramm, das durch einen Computer lesbare Anweisungen beinhaltet, die bei Betrieb auf einer geeigneten Computervorrichtung bewirken, dass die Computervorrichtung das Verfahren gemäß einem der vorhergehenden Ansprüche durchführt.
  10. Ein Computerprogrammprodukt, das das Computrprogamm gemäß Anspruch 9 beinhaltet.
EP15164713.8A 2015-04-22 2015-04-22 Verfahren, vorrichtung und computerprogramm zur bestimmung der herstellung von der jeweiligen fertigstellung eines aus einer doppelzonenfördersonde angehobenen gases Active EP3085885B1 (de)

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