EP3631164B1 - Perfectionnements apportés ou afférents à des puits d'injection - Google Patents

Perfectionnements apportés ou afférents à des puits d'injection Download PDF

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Publication number
EP3631164B1
EP3631164B1 EP18739576.9A EP18739576A EP3631164B1 EP 3631164 B1 EP3631164 B1 EP 3631164B1 EP 18739576 A EP18739576 A EP 18739576A EP 3631164 B1 EP3631164 B1 EP 3631164B1
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EP
European Patent Office
Prior art keywords
injection
well
fluid
pressure
parameters
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EP18739576.9A
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German (de)
English (en)
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EP3631164A1 (fr
Inventor
Frederic Joseph SANTARELLI
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Geomec Engineering Ltd
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Geomec Engineering Ltd
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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
    • E21B49/008—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 by injection test; by analysing pressure variations in an injection or production test, e.g. for estimating the skin factor
    • 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
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • 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
    • E21B43/25—Methods for stimulating production
    • 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
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • 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
    • E21B47/00—Survey of boreholes or wells
    • E21B47/06—Measuring temperature or pressure
    • E21B47/07—Temperature
    • 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
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
    • 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
    • E21B49/006—Measuring wall stresses in the borehole

Definitions

  • the present invention relates to injecting fluids into wells and more particularly, to a method for injection testing in appraisal wells to evaluate thermal stress effect characteristics for reservoir modelling and so better determine injection parameters for the well.
  • Reservoir models are used in the industry to analyze, optimize, and forecast production. Such models are used to investigate injection scenarios for maximum recovery and provide the injection parameters for an injection program.
  • Geological, geophysical, petrophysical, well log, core, and fluid data are typically used to construct the reservoir models.
  • the properties of the rock in the formation are traditionally obtained by taking measurements on core samples and the results are used in the models.
  • a known disadvantage in this approach is in the limitation of the models used and their reliance on the data provided by the core samples. While many techniques exist to contain and transport the core samples so that they represent well conditions in the laboratory, many measurements cannot scale from the laboratory to the well and there is a lack of adequate up-scaling methodologies.
  • US 8,116,980 to ENI S.p.A. describes a testing process for testing zero emission hydrocarbon wells in order to obtain general information on a reservoir, comprising the following steps: injecting into the reservoir a suitable liquid or gaseous fluid, compatible with the hydrocarbons of the reservoir and with the formation rock, at a constant flow-rate or with constant flow rate steps, and substantially measuring, in continuous, the flow-rate and injection pressure at the well bottom; closing the well and measuring the pressure, during the fall-off period (pressure fall-off) and possibly the temperature; interpreting the fall-off data measured in order to evaluate the average static pressure of the fluids (Pav) and the reservoir properties: actual permeability (k), transmissivity (kh), areal heterogeneity or permeability barriers and real Skin factor (S); calculating the well productivity.
  • k average static pressure of the fluids
  • kh transmissivity
  • S real Skin factor
  • WO 2015/126388 and WO 2016/099470 are to methods useful for understanding the invention.
  • injection parameters can be determined for injection confinement with the greatest injection efficiency and better characterisation of the effects of the cooling effect can be determined.
  • the method includes the steps of performing a series of step rate tests and measuring fracture pressure. In this way, fracturing can occur on the first step and other steps.
  • the method includes the steps of performing injection cycling and fall-off analysis.
  • the first model describes the development of the thermal stresses around the well on the measured data to estimate a thermal stress characteristic. More preferably the thermal stress characteristic is a thermal stress parameter.
  • the second model is a reservoir model or a hydraulic model.
  • Such models are known in the art for well planning and optimization. In this way, the present invention can utilize models and techniques already used in industry.
  • At least one downhole sensor also measures temperature.
  • the sensors data sampling rate is 1 Hz or greater. There may be a plurality of sensors to ensure redundancy.
  • the downhole sensors transmit data to the surface in real-time.
  • the downhole sensors include memory gauges on which the measured data is stored.
  • the method includes the step of measuring pressure at different zones in the well. In this way, characterisation of fracture pressure and the thermal stresses can be determined over the formation.
  • pressure, temperature and flow rate are measured at the surface of the well.
  • the injection parameters based on these values can be better determined.
  • the method includes the step of measuring the pressure and flow rate during the first injection cycle and shut in/step rate test and determining fracturing has occurred. In this way, remedial steps can be taken to ensure fracturing occurs in the second injection cycle and shut in.
  • parameters for the second injection cycle are determined from the first injection cycle. In this way, rate ramping schedule and duration of high rate injection can be optimized. Preferably, these steps are repeated for further injection cycles/step rate tests.
  • the injected fluid is water.
  • the injected fluid may be selected from a group comprising: drill water, filtered seawater or unfiltered seawater.
  • the injected fluid may be treated such as with a bactericide or scale inhibitor.
  • the injected fluid may further include a viscosifier.
  • the method may include the step of introducing a viscosifier to the fluid during injection. In this way, the viscosifier can be added if fracturing is not achieved on a first injection cycle.
  • the appraisal well has a well completion. More preferably the well completion is with a cemented and perforated liner over an interval. Other completions may be used such as open-hole screens with packers.
  • the downhole sensors are run in the well on a string.
  • the string may be drill pipe, test string or wireline.
  • the well injection parameters are selected from a group comprising: perforation length, injection fluid temperature, fluid pump rate, fluid pump duration and fluid injection volume.
  • the method includes the further step of carrying out well injection using the well injection parameters.
  • FIG. 1 there is shown a simplified illustration of an appraisal well, generally indicated by reference numeral 10, in which an injection test is being performed.
  • An injection test system 12 is used.
  • the injection test system 12 comprises a string 13, being a drill pipe on which is mounted a downhole sensor 14. Though only one sensor is shown, there may be additional sensors for other measurements or for redundancy.
  • the sensor 14 measures pressure and temperature and sends the measured data back in real-time to a surface data acquisition and transmission unit 16 via a cable (not shown) to surface 18.
  • the data may be transmitted to the unit 16 by wireless telemetry.
  • the data is stored in a memory on each sensor and then later analysed but this is not preferred as it does not allow real-time analysis and test program modifications based on the response of the formations.
  • the unit 16 can also transmit the data to a remote location so off-site analysis in real-time can be performed.
  • the sensors 14 have a sampling frequency of 1Hz. Other sampling frequencies may be used but they must be sufficient to measure changes in the pressure during the rate ramp-up and when shut-in occurs.
  • the appraisal well 10 is shown as entirely vertical with a single formation interval 22, but it will be realised that while appraisal wells are typically vertical they can also be slightly deviated or even horizontal in rare instances. Dimensions are also greatly altered to highlight the significant areas of interest.
  • Well 10 is drilled and completed in the traditional manner providing a casing 24 to support the borehole 26 through the length of the cap rock 28 to the location of the formation 22.
  • Casing 24 is cemented in place and a perforated or slotted liner 19, is hung from a liner hanger 20 at the base 30 of casing 24 and extends into the borehole 26 through the formation 22.
  • Formation 22 is a conventional oil reservoir.
  • Other completions may also be considered such as an open-hole screen with packers for example.
  • Wellhead 30 provides a conduit 32 for the injection of fluids from pumps 34 into the well 10.
  • Wellhead gauges 36 are located on the wellhead 30 and are controlled from the data acquisition unit 16 which also collects the data from the wellhead gauges 36.
  • Wellhead gauges 36 include a temperature gauge, a pressure gauge and a rate gauge. These will also measure data.
  • Control units may also be mounted on the surface 18 which will control the pumps 34, to vary their on/off status, temperature of the pumped fluid and flow rate of the pumped fluid.
  • the pumps 34 may be the cement pump already present on the rig and the fluid may be held in pits also as standard on the rig. Additional equipment in the form of a heat exchanger to vary the temperature of the fluid at surface 18 may also be present.
  • the injected fluid is water.
  • This may be drill water, filtered seawater or unfiltered seawater. If desired, the water can be treated with chemicals, for example bactericide or scale inhibitors depending on predicted well characteristics obtained from core samples.
  • a viscosifier may also be used, but it may only be required to be added if fracturing is not achieved on first injection.
  • step rate tests with flow and shut in are performed as shown in Figure 2 .
  • the water is injected at an injection rate Q 44 into the well 10 for a period of time 42 and then the well 10 is shut-in for a further period of time.
  • Each period of injection gets progressively longer.
  • the step rate tests are performed with the purpose of ensuring a clear fracturing of the formation in front of the perforated interval for each SRT.
  • the design of the SRT is to use short steps and a large number of them (typically 5min and 100 Ipm).
  • the fracturing during the 1 st SRT and some other SRTs should preferably occur before surface fluid reaches the perforation, thus the wells should preferably be of sufficient depth but shallow well conditions can also be accommodated.
  • This design essentially plays on the (BHT -Tres) term in Equation (1).
  • a typical test duration may be 24 to 48 hours depending on the results expected with the reduced time being preferable based on rig costs.
  • the injection is constant and at a high rate. This increases the zone affected by the thermal effect during each injection cycle and thus plays on the k term in Equation (1). This injection regime also allows for the estimation of the flow properties of the reservoir during the last long injection period.
  • shut-in periods these must be hard i.e. occur over a very brief time period. If measurements can be made in this time period, this may allow the determination of the fracture closure pressure. (square root of time, Nolte's G-function, etc.) However, short fractures are expected and this may prove difficult to measure.
  • the shut-in period here can be used to allow characterisation of the well environment using the same factors as in standard production well testing. The shut-in further allows there to be reheating of the fluid inside the well and this can be measured.
  • the test is followed up and analysed in real-time either on site or remotely.
  • the first injection cycle is analysed during its shut-in to ensure that fracturing has occurred and at which pressure/rate. If fracturing has not occurred a switch of pumps can be undertaken or the introduction of a viscosifier to increase the fluid viscosity can be considered. If it has the occurrence of a clear break-down, this must be accounted for.
  • the second cycle may be modified based on the results of the first cycle from which modifications in the form of rate ramping schedule and duration of high rate injection can be modified. The analysis is repeated for each cycle.
  • FIG. 3 there is illustrated a graph of the change in pressure 46 versus time 42, with the data shown as individual points 48a-f across a number of SRTs.
  • a model 50 describing the development of the thermal stresses around the well on the measured data to estimate the thermal stress parameter.
  • the fit can be a manual fit or use linear Lagrangian optimization.
  • FIG. 4 shows an illustration of the measured fracture pressure 52 variation over time 42 around an injector. This is shown both in real-time 54 and by back analysis 56. This illustrates that the reservoir pressure 58, injection temperature and cold zone development all affect the fracture pressure.
  • a hydraulic fracture model can also be considered i.e. either a numerical model or asymptotic solutions (PKN, GdK, etc.).
  • injection parameters can be incorporated into a reservoir model or other known models known to those skilled in the art from which the injection parameters can be calculated.
  • Such injection parameters will be injection fluid temperature, fluid pump rate, fluid pump duration and fluid injection volume. These values will also provide an indication of pump requirements.
  • DST Drill Stem Testing
  • the principle advantage of the present invention is that it provides a method for a well injection program in which injection testing is used to determine thermal stress characteristics of the well.
  • a further advantage of the present invention is that it provides a method for a well injection program in which injection testing is used to determine parameters for well interpretation.

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  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Geophysics (AREA)
  • Remote Sensing (AREA)
  • Chemical & Material Sciences (AREA)
  • Analytical Chemistry (AREA)
  • Investigating Strength Of Materials By Application Of Mechanical Stress (AREA)
  • Testing Resistance To Weather, Investigating Materials By Mechanical Methods (AREA)
  • Investigating Or Analyzing Materials Using Thermal Means (AREA)
  • Measuring Fluid Pressure (AREA)
  • General Engineering & Computer Science (AREA)
  • Operations Research (AREA)
  • Testing Of Devices, Machine Parts, Or Other Structures Thereof (AREA)

Claims (13)

  1. Procédé pour un programme d'injection de puits, le procédé comprenant les étapes :
    (a) choix d'un puits d'évaluation (10) ;
    (b) choix d'un intervalle et d'une longueur de perforation ;
    (c) positionnement d'au moins un capteur de fond de trou (14) pour mesurer la pression dans le puits ;
    (d) injection d'un fluide dans le puits ;
    (e) variation du débit (44) de fluide injecté ;
    (f) mesure de la pression (46) avec des variations de débit pour obtenir des données mesurées ;
    (g) adaptation d'un premier modèle (50) aux données mesurées pour estimer une caractéristique de contrainte thermique du puits ;
    (h) saisie de la caractéristique de contrainte thermique dans un second modèle ; et
    (i) détermination des paramètres d'injection à partir du second modèle
    caractérisé en ce que :
    le procédé comprend l'étape de mesure de la pression pour différentes températures de fluide injecté.
  2. Procédé selon la revendication 1, ledit procédé comprenant les étapes de réalisation d'une série d'essai de gradation de débit et de mesure de la pression de fracture.
  3. Procédé selon la revendication 1, ledit procédé comprenant les étapes de réalisation d'un cycle d'injection et d'une analyse de décroissance.
  4. Procédé selon une quelconque revendication précédente, ladite pression, ladite température et ledit débit étant mesurés à la surface du puits.
  5. Procédé selon une quelconque revendication précédente, ledit procédé comprenant l'étape de mesure de la pression et du débit durant un premier cycle d'injection et de détermination de la survenue d'une fracturation.
  6. Procédé selon la revendication 5, lesdits paramètres du second cycle d'injection étant déterminés à partir du premier cycle d'injection.
  7. Procédé selon la revendication 6, ladite étape étant répétée pour des cycles d'injection supplémentaires.
  8. Procédé selon une quelconque revendication précédente, ledit fluide injecté étant de l'eau.
  9. Procédé selon la revendication 8, ledit fluide injecté étant choisi dans un groupe comprenant : l'eau de forage, l'eau de mer filtrée ou l'eau de mer non filtrée.
  10. Procédé selon la revendication 8 ou la revendication 9, ledit fluide injecté étant traité chimiquement.
  11. Procédé selon l'une quelconque des revendications 8 à 10, ledit fluide injecté comprenant un agent de viscosité.
  12. Procédé selon une quelconque revendication précédente, lesdits paramètres d'injection de puits étant choisis dans un groupe comprenant : la température du fluide d'injection, le débit de la pompe à fluide, la durée de la pompe à fluide et le volume d'injection de fluide.
  13. Procédé selon une quelconque revendication précédente, ledit procédé comprenant l'étape supplémentaire de réalisation d'une injection de puits à l'aide des paramètres d'injection de puits.
EP18739576.9A 2017-05-24 2018-05-23 Perfectionnements apportés ou afférents à des puits d'injection Active EP3631164B1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
GB1708290.0A GB2562752B (en) 2017-05-24 2017-05-24 Improvements in or relating to injection wells
PCT/GB2018/051394 WO2018215763A1 (fr) 2017-05-24 2018-05-23 Perfectionnements apportés ou afférents à des puits d'injection

Publications (2)

Publication Number Publication Date
EP3631164A1 EP3631164A1 (fr) 2020-04-08
EP3631164B1 true EP3631164B1 (fr) 2021-04-21

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US (1) US20200072027A1 (fr)
EP (1) EP3631164B1 (fr)
CN (1) CN110678626A (fr)
AU (1) AU2018274699A1 (fr)
CA (1) CA3065359A1 (fr)
EA (1) EA201891498A1 (fr)
GB (1) GB2562752B (fr)
MX (1) MX2019013636A (fr)
WO (1) WO2018215763A1 (fr)

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* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
GB2565034B (en) * 2017-05-24 2021-12-29 Geomec Eng Ltd Improvements in or relating to injection wells
CN112343576B (zh) * 2020-11-25 2023-12-26 大庆嘉景石油工程技术有限公司 一种利用光纤传感手段监测油气井产量的工艺方法
CN112796719B (zh) * 2021-01-15 2022-05-20 大庆石油管理局有限公司 一种油田加密调整井用钻关方法

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Publication number Priority date Publication date Assignee Title
US7774140B2 (en) * 2004-03-30 2010-08-10 Halliburton Energy Services, Inc. Method and an apparatus for detecting fracture with significant residual width from previous treatments
ITMI20060995A1 (it) * 2006-05-19 2007-11-20 Eni Spa Procedimento per testare pozzi di idrocarburi a zero emissioni
EA021727B1 (ru) * 2007-09-13 2015-08-31 Эм-Ай ЭлЭлСи Способ использования характеристик давления для прогнозирования аномалий нагнетательных скважин
WO2013008195A2 (fr) * 2011-07-11 2013-01-17 Schlumberger Canada Limited Système et procédé de réalisation d'opérations de stimulation de trou de forage
US9097819B2 (en) * 2012-12-13 2015-08-04 Schlumberger Technology Corporation Thermoelastic logging
WO2015126388A1 (fr) * 2014-02-19 2015-08-27 Halliburton Energy Services, Inc. Estimation de la perméabilité dans des réservoirs sous-terrains non classiques utilisant des essais d'injection de fracture de diagnostic
CA2959593A1 (fr) * 2014-12-17 2016-06-23 Halliburton Energy Services Inc. Optimisation d'un traitement d'acidification de matrice
CN105696996B (zh) * 2016-01-29 2018-12-11 太原理工大学 一种干热岩地热人工热储的建造方法

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Publication number Publication date
WO2018215763A1 (fr) 2018-11-29
CA3065359A1 (fr) 2018-11-29
GB201708290D0 (en) 2017-07-05
AU2018274699A1 (en) 2019-11-21
EP3631164A1 (fr) 2020-04-08
GB2562752B (en) 2021-11-24
US20200072027A1 (en) 2020-03-05
EA201891498A1 (ru) 2020-03-20
GB2562752A (en) 2018-11-28
MX2019013636A (es) 2021-01-08
CN110678626A (zh) 2020-01-10

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