Classifications

• • 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
  • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
  • E21B49/08—Obtaining fluid samples or testing fluids, in boreholes or wells
• • 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
  • E21B47/10—Locating fluid leaks, intrusions or movements
• • 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

Definitions

• the present invention relates to a method for determining the contributions of individual wells to the production of a cluster of wells and/or of individual well segments to the production of a well and/or a cluster of wells .
• well effluent fluid streams produced by individual wells of a well cluster are commingled on a header (manifold) and routed via a fluid stabilization and separation assembly (comprising one or more bulk or production separators).
• the well effluent fluid is separated in the production separator into nominally single-phase streams of oil, water, gas and/or other fluids (or optionally, a gross liquid phase comprising oil and water, and a gas phase) .
• the separated single- phase fluids are thereafter routed to the production separator outlet conduits for metering, transportation and sales.
• a problem associated with management of fluid flow at the outlets of the production separator is that this fluid flow stems from the commingled production (or "flux") from some or all the wells of the cluster and at first glance the metering data does not provide information about the oil, water and gas (or liquid and gas) production by the individual wells.
• Multiphase well effluent meters are often too expensive, have too restricted an operating envelop and are too complex to install on individual well flowlines to allow individual oil, water and gas components of the well production to be measured continuously in real time, particularly as the well effluent composition and associated flow characteristics may change significantly over the life of the well.
• multiphase well effluent meters may require calibration at start up and/or from time to time.
• a well testing facility is consequently made available to be shared among a cluster of wells.
• the production from the wells are individually in turn routed to the well testing facility in which the individual oil, water and gas components of the production are determined directly, without interruption to the production of the other wells, and used as representative of the well production during normal production.
• Well testing facilities and their associated well production routing valve manifolds in spite of being shared by all the wells in the cluster of wells, are commonly regarded to be expensive, bulky and difficult to operate and maintain. In many cases, such well test facilities are not available.
• the first method (A) is the simple method of producing each well individually in turn, while all other wells are closed in from production, thus resulting in significant production deferment .
• a second approach (B) is "piggy back testing", that is, by testing one well and establishing its nominal production, and thereafter putting a second well into production, thereby computing the estimated nominal production of the second well by subtracting the nominal production from the first well from the measured production while the second well was also producing and so on .
• a third method (C) is "testing by difference”
• TBD the practice of shutting in one well and measuring the consequent difference in commingled production before and after the shut in of the well .
• the difference in production levels is then an estimate of the nominal production of the well.
• Method (C) causes less production deferment than methods (A) and (B), but is nevertheless has drawbacks, including the deferment of production of the tested well during the test period..
• the PU RTM method allows accurate real time estimation of the contributions of individual wells to the total commingled production of a cluster of crude oil, gas and/or other fluid production wells, based on well models derived from well test data and updated regularly using commingled production dynamic data.
• DDWTs Deep Well Tests
• a method for determining the contributions of individual wells to the production of a cluster of wells of which the well effluent streams are commingled and routed via a fluid separation assembly into fluid outlet conduits for transportation of at least partly separated streams of crude oil, gas and/or other fluids comprising: a) providing flow meters for measuring fluid flow in the fluid outlet conduits of the fluid separation assembly, and providing well monitoring equipment for monitoring one or more production variables, such as pressure and/or other characteristics, relating to well effluent streams of individual wells; b) sequentially testing wells of the well cluster by performing a well test during which production from a tested well is varied; c) monitoring during step b one or more production variables by the monitoring equipment and simultaneously measuring by means of the flow meters at the fluid outlet conduits of the fluid separation assembly any variation of the flow pattern of effluents produced by the cluster of wells, including the tested well, and obtaining from the measured variation an estimate of the production of the tested well during the
• 7 ⁇ are initially unknown weight coefficients, which are uniform across the selected period of time; expressing the monitored fluid flow pattern, which is measured by the flowmeters in the outlet conduits of the separation assembly, as XO monitored; comparing XO monitored with XO estimated and - estimating a value of each of the weight coefficients ⁇ i by iteratively varying the weight coefficients ⁇ i until XO estimated substantially equals XO monitored.
• Each of the wells of the well cluster may be tested for characterization by performing a series of actions during which production from a tested well is varied, including closing in the well production for a period of time, and then production of the tested well is started up in steps such that the tested well is induced to produce at multiple production rates over a normal potential operating range of the well, which test is hereinafter referred to as a Deliberately Disturbed Well Testing by Difference (DDWTBD) .
• DSWTBD Deliberately Disturbed Well Testing by Difference
• a sequence of well tests may be performed such that sequentially each of the wells of the well cluster is tested for characterization by initially closing in all the wells in the cluster, and subsequently starting up one well at a time, in sequence, with wells individually started up in steps to produce at multiple production rates over the normal potential operating range of the well, which sequence of well tests is referred to as “Deliberately Disturbed Production Testing” (DDPT), from which well tests:
• DDPT Deliberately Disturbed Production Testing
• an estimate of the production of a first well to be started up is directly obtained from the well test of the first well, and the well production estimation model is calculated for that well
• the production from the second well to be started-up up is derived from subtracting the production of the first well using the well model of the first well already established and
• the production and well production estimation model of the third and any subsequently started well are computed in sequence of their start-ups, thereby obtaining the well production estimation model of each well of the well cluster.
• the well production estimation model for each of the wells is constructed by combining data from: performing a Testing by Difference (TBD) test, whereby a base well production is established by interrupting the individual well production for a period of time, while monitoring by means of the flowmeters in the fluid outlet conduits of the fluid separation assembly the variation of the flow pattern of effluents produced by the cluster of wells, thereby obtaining an estimate of the base well production of the well of which production has been interrupted, and performing an extended Deliberately Disturbed Well Test (eDDPT), during which the measurements from fluid outlets of the fluid separation assembly are recorded over a period of time together with the measurable quantities at all the wells.
• TDD Testing by Difference
• Each well production estimation model may have a static and a dynamic part, wherein the static part is constructed by comparing the outcome of a plurality of alternative curve fitting approaches and the dynamic part is constructed by comparing the outcome of a plurality of alternative dynamic identification approaches.
• the "well production estimation models” can additionally incorporate a "well decline factor” which will be a function of time.
• the decline factor is computed as a best fit to allow the "well production estimation models” to reflect the decline of well production due to the inherent decrease in well potential as a function of cumulative well production.
• the tests "DDPTBD” or “TBD” plus “eDDPT” can both or in combination be used to generate "well production estimation models" for each well in a cluster of wells with commingled production channelled into a production separator with measurements on its single phase outlet flows. It is noted that “eDDPT” data need not be obtained from dedicated testing, but often be directly obtained from the historic production record of the cluster of wells . It is observed that the optional "DDWTBD”, “TBD” and/or "eDDPT” tests apply to two specific but economically important special cases . The first special case is that of oil and gas production wells that have multiple individual producing zones, each with its own production control devices and measurement.
• the second special case is that where multiple subsea wells share a single pipeline to surface production facilities, and which have no subsea well test facilities or dedicated pipeline for routing flow from individual wells to surface well testing facilities .
• the method according to the invention is essential to allow the derivation of "well (or zone) production estimation models" of each individual well in the well cluster, at an acceptable deferment of production, which in turn allows the continuous real time production monitoring of the production of individual well zones or subsea wells .
• the methods (A), (B) and (C) above, in particular the methods (B) and (C), may be incorporated in the method according to the invention.
• a method in accordance with claim 14 for determining the contributions of one or more segments of an segmented inflow region of a multi-zone and/or multilateral well to the production of the multi-zone and/or multilateral well and/or of a cluster of wells.
• FIG. 1 schematically shows a crude oil and/or natural gas production system comprising a cluster of wells
• FIG.2 illustrates a multi-zone well with segments that form different inflow regions .
• a preferred embodiment of the computation of the "well production estimation model” either from “TBD” for each well, and a “eDDPT”, or from a set of "DDWTBD” for each well, is as follows:
• ⁇ is the "well production estimation model" (alternatively dynamic fingerprint / mathematical functional) relating J 1 (O to parameterised by vectors a , and Pi 1 with f or a n /?, f or some nominal set of well operating measurements M i,' M 2,'-" .
• M i,' M 2,'-", and a ⁇ can be viewed as the "bias” or “offset” or “anchor” about that operating point, and the function (al ) / ⁇ A' M i,(0>"2,(0v) can be linear or non-linear but in any case parameterised by the vector A ; computing a, from a "TBD” on the well i for wells, via a straightforward averaging and subtraction process, and thereafter computing A simultaneously for all the wells from "eDDPT" data, for example, via a mathematical best fit using least squares. or, optionally, computing a , and A from a "DDWTBD" for each well, for example, via a mathematical best fit using least squares.
• the "well production estimation model" obtained from the preceding steps for each individual well may then be inserted into "PU RTM" .
• FIG.l schematically shows a crude oil and/or natural gas production system comprising a cluster of wells, including wells 1 and 2.
• the well 1 (typical for well 2, and the other wells) comprises a well casing 3 secured in a borehole in the underground formation 4 and a production tubing 5 extending from surface to the underground formation.
• the well 1 further includes a wellhead 10 provided with well measurement equipment, typically a pressure transmitter
• FLP Flowline Pressure
• lift gas flow measurement 12 or subsurface pressure gauges and/or other downhole production measurement equipment available, for example a downhole Downhole
• Tubing Pressure (DTP) gauge 18 also Fig. 2, item 66
• flowline differential pressure meters for example wet gas meters (not shown)
• the well 1 also may have means of adjusting production, such as a production control choke 11, a fixed bean choke (not shown) and / or lift- gas injection 12 or downhole interval control valves (Fig. 2, item 67) .
• the production system further includes well effluent well production flow lines 20, extending from the wellheads 10 to a production header 21, and a production separator 25.
• the production separator 25 is provided with outlets for water, oil and gas 35, 36 and 37 respectively. Each outlet 35, 36 or 37 is provided with flow metering devices, 45, 46 and 47 respectively. Optionally, the water and oil outlets can be combined.
• the production separator pressure 26 may be controlled by regulating the gas flow from gas outlet 37, thereby affecting the flowline pressure 14 and the production of the individual wells.
• the well measurements comprising at least data from 13 and optionally from 14, 18, lift gas injection rate from 12, position of production choke 11, and so on, are continuously transmitted to a Production Data Acquisition and Control System 50.
• the commingled production measurements 45, 46, 47 are continuously transmitted to the Production Data Acquisition and Control System 50.
• the data transferred to the Production Data Acquisition and Control System is stored for real time and subsequent data retrieval for analysis and "well production estimation model" construction as outlined in this patent.
• the typical data transmission paths are illustrated as 14a and 45a.
• the data in the Production Data Acquisition and Control System are also accessed by PU RTM in real time for use in conjunction with "well production estimation models" for the continuous real time estimation of individual well productions .
• TBD Transmission by Difference
• DWTBD DwT by Difference
• the tubing head pressures for the other wells are also monitored and preferably, if the tubing head pressures of the other wells substantially change after the shutdown of the well on test, the production choke valves of the other wells, or optionally, the pressure of the separator, should be adjusted to return the tubing head pressures of the wells not on test to the pressures prior to the shutdown of the well on test. Similarly, as the well on test is ramped in steps up to its normal production as part of the "DDWTBD", adjustments should be made to return the tubing head pressures of the wells not on test to the pressures prior to the shutdown of the well on test.
• eDDPT Extended Deliberately Disturbed Production Testing
• a "TBD” For “Extended Deliberately Disturbed Production Testing” (“eDDPT”), a "TBD” requires to first be performed for all wells. For each well i, a “TBD” is conducted to estimate the well production.
• DDWTBD the well measurements from the wells in the cluster, particularly the tubing head pressures 13 of the wells, and the commingled production measurements 45, 46, 47 are initially monitored to confirm a period of stable production for all wells in the cluster.
• the computations for the models then follow as before.
• the application the decline factor is important in the case where test data has been accumulated over a long period of time, or if the duration - ⁇ 3 in the eDDPT is significant.
• the invention has important and significant application to oil, water and gas production systems in the case where one or more wells in the cluster of wells have, at subsurface (or downhole) level, multiple fluid producing zones or branches.
• the details are illustrated by reference to a multizone well, but the principles are equally applicable to a multi-branch or a multilateral well.
• FIG.2 illustrates a multizone well 60 with tubing 5 extending to well segments, which form three distinct producing zones 62, 63, 64.
• Each zone has means of measuring the variations of thermodynamic quantities of the fluids within zone as the fluid production from the zone varies, and these can include downhole tubing pressure gauges 66 and downhole annulus pressure gauges 65.
• Each zone may also have a means for remotely adjusting the production through the zone from the surface, for example, an interval control valve 67, either on-off or step-by-step variable or continuously variable.
• the multizone well 60 further includes a wellhead 10 provided with well measurements, for example, "Tubing Head Pressure" 13 and "Flowline Pressure" 14.
• the well 60 may also have some means of adjusting production at the surface, for example a production control choke 11.
• the well 60 produces into a multiphase well effluent flowline 20, extending from the well to a production header (already shown on FIG.l).
• the multizone well 60 can be part of a cluster of wells producing to a production separator with or without a dedicated well test facility, or optionally, the multizone well 60 can have a dedicated well effluent meter that directly measures its production. In any case, if more than one zone of the well is producing, the direct measurement of the production from one of the zones is not possible without interruption of the continued production from the other zones . As such, both the approaches of:
• DDWT by Difference (“DDWTBD);
• TBD Transmission by Difference
• eDDPT Extended Deliberately Disturbed Production Testing
• the vectors a j and Pj are computed using best fit methods based on DDWTBD or TBD plus eDDPT as outlined above .

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• 2007
  • 2007-04-05 CA CA2645253A patent/CA2645253C/en active Active
  • 2007-04-05 AU AU2007235957A patent/AU2007235957B2/en active Active
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  • 2007-04-05 WO PCT/EP2007/053345 patent/WO2007116006A1/en active Application Filing
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• 2008
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