CN110678626A

CN110678626A - Improvements in or relating to injection wells

Info

Publication number: CN110678626A
Application number: CN201880033050.6A
Authority: CN
Inventors: F·J·桑塔蕾丽
Original assignee: Geological Engineering Co
Current assignee: Geological Engineering Co
Priority date: 2017-05-24
Filing date: 2018-05-23
Publication date: 2020-01-10
Also published as: GB201708290D0; GB2562752A; CA3065359A1; EA201891498A1; AU2018274699A1; MX2019013636A; EP3631164B1; EP3631164A1; US20200072027A1; WO2018215763A1; GB2562752B

Abstract

A method for providing a well injection plan in which injection tests are performed on an evaluation well. Selecting an evaluation well, a downhole sensor positioned in the well to measure pressure and temperature, injecting water into the well in a series of pace tests or injection cycles, modeling the data to determine thermal stress characteristics of the well, and determining optimal injection parameters for the well injection plan by reservoir modeling to provide maximum recovery. This eliminates the need to make thermal stress characteristic measurements on the core sample.

Description

Improvements in or relating to injection wells

The present invention relates to injecting fluids into wells, and more particularly to a method of conducting injection tests in evaluating wells to assess thermal stress effect characteristics for reservoir modeling and thus better determining injection parameters for the wells.

Current oil and gas production is primarily focused on maximizing the recovery of the well. This is because we have mined all areas that may contain oil, leaving only remote and environmentally sensitive areas of the world (e.g., north and south). Despite the large number of unconventional oil and gas sources, such as highly viscous oils, oil shale, shale gas, and natural gas hydrates, many of the technologies that utilize these resources are either very energy intensive (e.g., steam injection into heavy oil) or politically/environmentally sensitive (e.g., "cracking" to recover shale gas).

To improve recovery in wells, it is now common to inject a fluid (usually water) into the reservoir through an injection well. This form of enhanced oil recovery uses injected water to increase the depletion pressure within the reservoir and to move the oil to the appropriate location so that it can be recovered. This also results in environmental benefits if produced water is re-injected.

Reservoir models are used in the industry to analyze, optimize and predict production. Such models are used to investigate injection scenarios to achieve maximum recovery and provide injection parameters for injection planning. Reservoir models are typically constructed using geological, geophysical, petrophysical, well logging, core and fluid data. Traditionally, the properties of rock in the formation are obtained by taking measurements on core samples and using the results in a model.

One known disadvantage of this method is the limitations of the models used and their dependence on the data provided by the core sample. While many techniques exist for containing and transporting core samples so that they represent well conditions in a laboratory, many measurements cannot be scaled from laboratory to well and lack adequate magnification methods.

In addition, when cold fluid is injected into a warm subterranean reservoir, a cooling effect will occur around the injector. This changes the stress in the region as the temperature changes. As a result, the fracture pressure around the injector will change over time. The amount of change will depend on the thermal stress characteristics of the formation. While it is theoretically possible to measure these properties of core samples in the laboratory, measurements that rely on pressure/temperature relationships do not scale properly, and they have been found to take into account a number of factors when attempting to scale to well sizes.

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 of the reservoir, comprising the steps of: injecting into the reservoir at a constant flow rate or in constant flow rate steps a suitable liquid or gaseous fluid compatible with the hydrocarbons of the reservoir and with the formation rock, and substantially continuously measuring the flow rate and injection pressure at the bottom of the well; close the well and measure pressure and possibly temperature during the drawdown period (pressure drawdown); the measured drawdown data was interpreted to evaluate the average static pressure (Pav) of the fluid and the reservoir properties: actual permeability (k), transmittance (kh), area heterogeneity or permeability barrier, and actual skin factor (S); well productivity is calculated. The advantage of such injection testing on evaluation wells compared to conventional production testing is that the requirement to dispose of produced hydrocarbons in the presence of safety and environmental issues is eliminated. However, to date, such tests have been limited to determining fluid properties, particularly permeability, and formation damage when measuring skin factors to determine well productivity.

It is therefore an object of the present invention to provide a method for well injection planning, wherein injection tests are used to determine thermal stress characteristics of a well.

It is another object of the present invention to provide a method for well injection planning in which injection tests are used to determine parameters for well interpretation.

According to a first aspect of the present invention, there is provided a method for well injection planning, comprising the steps of:

(a) selecting an evaluation well;

(b) selecting a perforation interval and length;

(c) positioning at least one downhole sensor to measure pressure in the well;

(d) injecting a fluid into the well;

(e) changing the flow rate of the injection fluid;

(f) measuring pressure with a change in flow rate to provide measured data;

(g) fitting a first model to the measured data to estimate thermal stress characteristics of the well;

(h) inputting the thermal stress characteristic into a second model; and

(i) injection parameters are determined from the second model.

In this way, by estimating thermal stress characteristics prior to developing the wellsite, injection parameters may be determined to achieve injection constraints at maximum injection efficiency.

Further, by determining thermal stress characteristics at the well, more accurate calibration data is used in the second model than would otherwise be available from measurements on the core sample.

Preferably, the method comprises the steps of performing a series of pace tests and measuring the fracture pressure. In this way, fracturing can occur on the first step and on other steps. Alternatively, the method comprises the step of performing an injection cycle and a drop analysis.

Preferably, the first model describes the development of thermal stress around the well based on the measured data to estimate thermal stress characteristics. More preferably, the thermal stress characteristic is a thermal stress parameter.

Preferably, 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 take advantage of models and techniques already used in the industry.

Preferably, the at least one downhole sensor also measures temperature. Preferably, the sensor data sampling rate is 1Hz or higher. Multiple sensors may be present to ensure redundancy.

Preferably, the downhole sensors transmit data to the surface in real time. Alternatively, the downhole sensor comprises a memory gauge on which the measured data is stored.

Preferably, the method comprises the step of measuring the pressure of the injected fluid at different temperatures. In this way, a better characterization of the effect of the cooling effect may be determined.

Preferably, the method comprises the step of measuring the pressure at different zones in the well. In this way, a characterization of fracture pressure and thermal stress across the formation may be determined.

Preferably, the pressure, temperature and flow rate at the surface of the well are measured. In this way, the implant parameters based on these values may be better determined.

Preferably, the method comprises the steps of: the pressure and flow rate are measured during the first injection cycle and shut-in/pace test, and it is determined that a fracture has occurred. In this way, remedial steps may be taken to ensure that fractures occur during the second injection cycle and shut-in. Preferably, the parameters of the second injection cycle are determined from the first injection cycle. In this way, the rate ramp schedule and duration of the high rate injection may be optimized. Preferably, these steps are repeated for further injection cycles/pace tests.

Preferably, the injection fluid is water. The injection fluid may be selected from the group comprising: drilling water, filtered seawater, or unfiltered seawater. The injection fluid may be treated, for example, with a biocide or a scale inhibitor. The injection fluid may further comprise a viscosifier. The method may comprise the step of introducing a viscosifier to the fluid during injection. In this way, if no fracture is achieved on the first injection cycle, a tackifier may be added.

Preferably, the evaluation well has a completion. More preferably, the completion is accomplished using cemented and perforated pads at certain intervals. Other completion equipment such as an open hole screen with packers may be used.

Preferably, the downhole sensor is run on a tubing string in the well. The string may be a drill pipe, a test string or a wireline.

Preferably, the well injection parameters are selected from the group comprising: perforation length, injection fluid temperature, fluid pump rate, fluid pump duration, and fluid injection volume.

Preferably, the method comprises the further step of performing well injection using well injection parameters.

Accordingly, the drawings and description are to be regarded as illustrative in nature and not as restrictive. Furthermore, the terms and phrases used herein are for descriptive purposes only and should not be construed as limiting scope, e.g., the language comprising, including, having, containing or referring to and variants thereof is intended to be broad and encompass the subject matter listed thereafter, equivalents and additional subject matter not recited, and is not intended to exclude other additives, components, integers or steps. Also, for the purposes of applicable law, the term comprising is considered synonymous with the term comprising or containing. Any discussion of documents, acts, materials, devices, articles or the like is included in the present specification solely for the purpose of providing a context for the present invention. It is not suggested or represented that any or all of these matters formed part of the prior art based on the common general knowledge in the field relevant to the present invention. All numerical values in this disclosure are understood to be modified by the word "about". All singular forms of elements or any other components described herein are understood to include the plural forms thereof, and vice versa.

Although the description will refer to up and down and up and down, these are to be understood as relative terms relating to the borehole and the inclination of the borehole, although shown vertically in some drawings, may be inclined or even horizontal.

Embodiments of the invention will now be described, by way of example only, with reference to the accompanying drawings, in which:

FIG. 1 is a schematic illustration of an injection well test being performed uphole in accordance with an embodiment of the present invention;

FIG. 2 is a graph of injection rate versus time during an injection test in a series of pace tests;

FIG. 3 is a graph of pressure versus time during an injection test and a fit of a first model to measured data; and

fig. 4 is a graph of fracture opening pressure and reservoir pressure around an injector versus time.

Referring initially to FIG. 1, a simplified illustration of an evaluation well in which an injection test is being performed is shown, generally indicated by reference numeral 10. An injection testing system 12 is used. The injection testing system 12 includes a tubular string 13, which is a drill pipe on which downhole sensors 14 are mounted. Although only one sensor is shown, there may be additional sensors for other measurements or for redundancy.

The sensors 14 measure pressure and temperature, and send the measured data back to the surface data acquisition and transmission unit 16 in real time via a cable (not shown) to the surface 18. Alternatively, the data may be transmitted to the unit 16 by wireless telemetry. In an alternative embodiment, the data is stored in memory on each sensor and then analyzed later, but this is not preferred because it does not allow for real-time analysis and test plan modification based on the response of the formation. The unit 16 may also transmit data to a remote location so real-time off-site analysis may be performed. The sensor 14 has a sampling frequency of 1 Hz. Other sampling frequencies may be used, but must be sufficient to measure the change in pressure during the rate ramp and when shut-in occurs.

In fig. 1, the evaluation well 10 is shown as being perfectly vertical with a single interval 22 of formation, but it will be appreciated that while the evaluation well is typically vertical, it may also be slightly deviated or even horizontal in rare instances. The dimensions are also greatly modified to highlight important regions of interest. The well 10 is drilled and completed in a conventional manner to provide a housing 24 to support a wellbore 26 through the length of overburden 28 to a location in the formation 22. Casing 24 is cemented in place and perforated or slotted liners 19 are suspended from liner hooks 20 at base 30 of casing 24 and extend through formation 22 into wellbore 26. Formation 22 is a conventional oil reservoir. Other completion equipment, such as an open hole screen with packers, is also contemplated.

At the surface 18, there is a wellhead 30. The wellhead 30 provides a conduit 32 for injecting fluid from a pump 34 into the well 10. The wellhead gauge 36 is positioned on the wellhead 30 and is controlled by the data acquisition unit 16, which also collects data from the wellhead gauge 36. The wellhead gauge 36 includes a temperature gauge, a pressure gauge, and a rate gauge. These will also measure data. A control unit may also be mounted on the surface 18 that will control the pump 34 to vary its on/off state, the temperature of the pumped fluid, and the flow rate of the pumped fluid. For simplicity, the pump 34 may be a cement pump already present on the rig and the fluid may be held in the pit, which is also the standard situation on a rig. There may also be additional equipment in the form of a heat exchanger to change the temperature of the fluid at the surface 18.

The injection fluid is water. This may be drilling water, filtered seawater or unfiltered seawater. If desired, the water may be treated with chemicals such as biocides or scale inhibitors, depending on the predicted well characteristics obtained from the core sample. Tackifiers may also be used, but may only need to be added if fracture is not achieved at the first injection.

For data analysis we need to consider how to define the thermal stress. We consider studies in t.k.perkins and j.a.gonzalez: "Changes in Earth stress around a borehole Caused by Radially symmetric pressure and temperature gradients (Changes in Earth stress around a Wellbore used by radial symmetry pressure and temperature gradients)", journal of SPE, 4.1984, page 129- "140; and "The Effect of Thermoelastic stress on injector well fracture" (The Effect of thermo elastic Stresses on Injection well fracture) ", SPE J, 2.1985, pages 78-88, incorporated herein by reference. Both papers describe temperature changes due to injection of fluids at a constant temperature (BHT), which is different from the original reservoir temperature (Tres). In turn, the stress will also change in the region of the temperature change. Specifically, the stress change (Δ σ) is quantified by the following equation (tension is negative):

Δσ＝k AT(BHT-Tres) ….(1)

-k is the form factor and Perkins and Gonzalez give the formula for circular and elliptical discs;

AT is a thermal stress parameter related to the thermoelastic properties of the formation by the following equation:

AT＝aT E/(1-v) ….(2)

-aT is the thermal expansion of the formation

E is the Young's modulus of the formation

-v is the Poisson's ratio of the formation

This tells us that the fracture pressure around the injector will vary over time, and therefore the thermal stress parameter is a key factor in designing the well injection plan and the injection parameters chosen. From the point of view of hydraulic fracture propagation, the injection constraints basically depend on three main parameters:

the cleanliness of the water can be controlled at the surface, but can be deteriorated due to circulation in the pipes and ducts;

if present, the natural stress between sand and shale in the top reservoir contrasts; and is

The fracture pressure around the injection well decreases due to the cooling effect.

The latter will persist throughout the life of the reservoir. However, if the produced water is re-injected, its magnitude may decrease over time as more produced water is added to the injected mixture. This is so because the produced water increases the temperature of the injection mixture. If we consider the annual injection efficiency at which an injection plan can be run, the percentage of produced water, temperature, harmful solids and oil droplets, and fracture pressure all increase during the life of the well, and the risk of injection leaking out of the injection zone also increases with the life of the well.

Thus, the time-varying results caused by the thermal stress parameter mean that it is critical to quantify this parameter before any wellsite development plan is executed.

To determine the thermal stress parameter, we performed injection tests at the well. Using the arrangement shown in fig. 1, we performed repeated fracture pressure measurements during the pace test and/or drawdown analysis after the injection cycle.

We will now consider an example of an injection test sequence, but it must be remembered that it will be adapted to the situation of each well, i.e. time slot, depth, rig, etc. It is also necessary to adapt to the formation encountered, thus tracking the well and inputting deviations from the initial plan into the test design model. The log is analyzed to select the best interval to test (puncture). The spacing should be as uniform as possible in terms of porosity, i.e. stiffness and permeability. The perforation length can be modified.

As shown in fig. 2, a series of pace tests with flow and shut-in were performed. For each pace test 40a-d, water is injected into the well 10 at an injection rate Q44 for a period of time 42, and the well 10 is then shut down for another period of time. Each injection period becomes progressively longer.

The purpose of performing the step test (SRT) is to ensure that for each SRT the formation is clearly fractured before the perforation interval. The SRT is designed to use short steps and a large number of short steps (typically 5 minutes and 100 lpm). Fracturing during the first SRT and some other SRTs should preferably occur before the surface fluid reaches the perforations, so that the well should preferably have sufficient depth, but may also accommodate shallow well conditions. This design essentially works on the (BHT-Tres) term in equation (1). Typical test durations may be 24 to 48 hours, depending on the desired result, with reduced times being desirable in terms of rig cost.

The implant is constant and at a high rate during the implant period. This increases the area affected by thermal effects in each injection cycle and therefore acts on the k term in equation (1). The injection scheme also allows the flow characteristics of the reservoir to be estimated during the last long injection period.

These must be difficult, i.e. occur in a very short period of time, during the shut-in period. If measurements can be taken during this time period, the fracture closure pressure can be determined. (square root of time, nortel G function, etc.) however, short breaks are expected to occur, which may prove difficult to measure. Since injection well testing is performed by shutting in the well, the well environment can be characterized using the shut-in period herein using the same factors as standard production well testing. Shutting in further allows the fluid in the well to be reheated and this can be measured.

The test is tracked and analyzed in real time, either on site or remotely. The first injection cycle is analyzed during shut-in of the first injection cycle to ensure that a fracture has occurred and at which pressure/rate. If no fracturing has occurred, the pump may be switched, or a viscosifier may be considered to increase the fluid viscosity. If significant failure occurs, it must be considered. The second loop may be modified based on the result of the first loop, from which modifications in the form of a rate ramp schedule and duration of high rate injection may be modified. The analysis was repeated for each cycle.

Referring to fig. 3, a graph of the change in pressure 46 versus time 42 is shown with data shown as individual points 48a-f across several SRTs. Then, we fit a model 50 describing the thermal stress development around the well based on the measured data to estimate the thermal stress parameters. Those skilled in the art will appreciate that the fitting may be a manual fitting or using linear lagrangian optimization.

To fully explain the data, we compared the fracture pressure (Pfrac) with the injection volume (V). One skilled in the art will recognize that closed type solutions or numerical models may be used. In either case, the injection history (injection rate Q and bottom hole temperature BHT) is discrete: more precisely, a BHT versus injection volume (V) curve is created.

For closed solutions, the temperature distribution in the area affected by thermal convection is established; the kernel solution provided by Perkins and Gonzalez is used in conjunction with the superposition theorem (i.e., the linear problem) to calculate stress variations in regions affected by thermal effects; and the change in fracture pressure near the well over time is calculated. Fig. 4 illustrates the change in fracture pressure 52 measured around the injector over time 42. This is shown in real time 54 as well as by inverse analysis 56. This indicates that reservoir pressure 58, injection temperature and cold zone development all affect fracture pressure.

For numerical models, there are two solutions to calculate the change in fracture pressure around the well over time. The "classical" method consists in using a flow model that takes into account thermal convection (usually based on finite differences) and then coupling it with a mechanical model (usually based on finite elements). Alternatively, a fully coupled model of simultaneous convection, heat transfer and mechanical solution may be used. However, this requires complex numerical techniques not commonly used in the oil industry, such as mixing elements, mesh refinement, etc.

For either case, it is also contemplated to employ hydraulic fracture models, i.e., numerical models or asymptotic solutions (PKN, GdK, etc.).

The values may be incorporated into a reservoir model or other known models known to those skilled in the art that may be used to calculate injection parameters. Such injection parameters would be injection fluid temperature, fluid pump rate, fluid pump duration, and fluid injection volume. These values will also provide an indication of the pump requirements.

Thus, injection testing provides two main pieces of information for optimal wellsite development planning:

the value of large-scale thermal stress parameters for water injection system design.

By well test interpretation, the large-scale flow properties of the reservoir can be used as calibration points for the reservoir model.

Those skilled in the art will appreciate that production tests, i.e., drill pipe tests (DST), are rarely performed in evaluation wells due to the environmental consequences of storing produced oil and burning natural gas. Thus, the large-scale flow of new wellsites will be left to the model. The injection test is advantageous compared to the production test, because pumps can be used on the drilling rig, and there is also a pit for storing the injection fluid. Since oil and gas are not generated, the influence on the environment is also limited. Additionally, by fracturing injection wells in conventional reservoirs, we can use a produced water re-injection plan.

A primary advantage of the present invention is that it provides a method for well injection planning in which injection tests are used to determine thermal stress characteristics of a well.

Another advantage of the present invention is that it provides a method for well injection planning in which injection tests are used to determine parameters for well interpretation.

The foregoing description of the invention has been presented for purposes of illustration and description and is not intended to be exhaustive or to limit the invention to the precise form disclosed. The described embodiments were chosen and described in order to best explain the principles of the invention and its practical application, to thereby enable others skilled in the art to best utilize the invention in various embodiments and with various modifications as are suited to the particular use contemplated. Accordingly, further modifications or improvements may be incorporated without departing from the scope of the invention herein contemplated.

Claims

1. A method for well injection planning, comprising the steps of:

(a) selecting an evaluation well;

(b) selecting a perforation interval and length;

(c) positioning at least one downhole sensor to measure pressure in the well;

(d) injecting a fluid into the well;

(e) changing the flow rate of the injection fluid;

(f) measuring pressure with a change in flow rate to provide measured data;

(h) inputting the thermal stress characteristic into a second model; and

(i) injection parameters are determined from the second model.

2. The method of claim 1, wherein the method comprises the steps of performing a series of pace tests and measuring fracture pressure.

3. The method of claim 1, wherein the method comprises the step of performing an injection cycle and a droop analysis.

4. The method of any preceding claim, wherein the first model describes the development of thermal stress around the well based on the measured data to estimate thermal stress characteristics.

5. The method of any preceding claim, wherein the thermal stress characteristic is a thermal stress parameter.

6. The method of any preceding claim, wherein the second model is a reservoir model.

7. The method of any preceding claim, wherein the second model is a hydraulic fracture model.

8. The method of any preceding claim, wherein the at least one downhole sensor also measures temperature.

9. The method of any preceding claim, wherein the downhole sensor data sampling rate is 1Hz or greater.

10. The method of any preceding claim, wherein the downhole sensor transmits data to the surface in real time.

11. The method of claim 10, wherein the downhole sensor transmits data to a surface via a wireline.

12. The method of claim 10, wherein the downhole sensor transmits data to the surface via telemetry.

13. The method of any preceding claim, wherein the downhole sensor comprises a memory gauge on which the measured data is stored.

14. A method according to any preceding claim, wherein the method comprises the step of measuring the pressure at different temperatures of the injected fluid.

15. A method according to any preceding claim, wherein pressure, temperature and flow rate are measured at the surface of the well.

16. The method of any preceding claim, wherein the method comprises the step of measuring the pressure and flow rate during a first injection cycle and determining that a fracture has occurred.

17. The method of claim 16, wherein parameters for a second injection cycle are determined from the first injection cycle.

18. The method of claim 17, wherein the steps are repeated for further injection cycles.

19. The method of any preceding claim, wherein the injection fluid is water.

20. The method of claim 19, wherein the injection fluid is selected from the group comprising: drilling water, filtered seawater, or unfiltered seawater.

21. The method of claim 19 or claim 20, wherein the injection fluid is chemically treated.

22. The method of any one of claims 20 to 22, wherein the injection fluid comprises a viscosifier.

23. The method of any preceding claim, wherein the evaluation well has a completion.

24. The method of claim 24 wherein the completion is accomplished with cemented and perforated liners at intervals.

25. The method of any preceding claim, wherein the downhole sensor is run on a tubing string in the well.

26. The method of any preceding claim, wherein the well injection parameter is selected from the group comprising: injection fluid temperature, fluid pump rate, fluid pump duration, and fluid injection volume.

27. A method according to any preceding claim, wherein the method comprises the further step of performing well injection using the well injection parameters.