CA2866274A1

CA2866274A1 - System and method of increasing production from oil and gas reservoirs

Info

Publication number: CA2866274A1
Application number: CA2866274A
Authority: CA
Inventors: Radhakrishnan Mahadevan
Original assignee: Individual
Current assignee: Pamban Energy Systems Canada
Priority date: 2014-09-30
Filing date: 2014-09-30
Publication date: 2016-03-30

Abstract

The following relates to systems and methods of increasing well production by real-time interpretation of distributed temperature sensor (DTS) data, distributed acoustic sensor (DAS) data, distributed pressure sensor (DPS) data, or other such distributed sensor data, to obtain zonal flow rates, development and use of control systems, development of control processes, use of down-hole control valves, use of sensor systems into existing wells and other systems and methods.

Description

System and Method of Increasing Production From Oil and Gas Reservoirs Field of the Disclosure [0001] This generally relates to subsurface oil and gas wells. More particularly, the following relates to systems and methods of increasing well production by real-time interpretation of distributed temperature sensor (DTS) data, distributed acoustic sensor (DAS) data, distributed pressure sensor (DPS) data, or other such distributed sensor data, to obtain zonal flow rates, development and use of control systems, development of control processes, use of down-hole control valves, use of sensor systems into existing wells and other systems and methods.
Background

[0002] U.S. Published Patent Application 20040244989 by Eken etal.
published on December 9, 2004 discloses general means of improving well production by controlling flow at a single point mainly at the surface.

[0003] U.S. Published Patent Application 20120241148 by Alsop et al.
published on September 27, 2012 discloses a method of injection into the material from a single injection well to multiple production wells.

[0004] U.S. Published Patent Application 2008/0262736 by Thigpen et al.
discloses a method of producing fluid from a completed well by changing parameters of the production well. The field of disclosure pertains to mainly production well equipment. It does not include injection well systems and the specific use of distributed sensing for injection well. Additionally, well pairs or multiple well profile control to improve sweep efficiency is not considered in their disclosure. Furthermore, Thigpen et al. fails to extend the method to include the aspect of real-time. The computer based control disclosed is not applicable for real-time, based on the patent disclosure, because of the absence of real-time measurements; well logs etc are not real-time. There is no method to interpret real-time measurements and hence there is also no method to control the production or injection settings in real-time.

[0005] U. S. Patent Application 20120160484 by Sierra et al. discloses a method for improving waterflood performance using Barrier Fractures and Inflow Control Devices. However, in this invention, an inflow control device is used in a horizontal production well to prevent the flow of non-hydrocarbon fluids using an inflow control valve.

[0006] U. S. Patent Application 20090188665 by Tubel et al. discloses a method for monitoring downhole parameters using fibre optics. Tubel et al invention is focused on using fibre optics to monitor chemical injection into the oil well and to control the amount of chemicals pumped into the well using a control system.

[0007] U.S. Published Patent Application 20030051873 by Patzek etal.
published on March 20, 2003 discloses a basic control system for determining optimal injection pressure to increase the growth and propagation of a single fracture.

[0008] Generally, wells penetrate vertically or linearly deep into the ground and pass through zones of horizontally displaced oil or gas contained within void spaces in geologic material known as reservoir rock. In order to obtain resources within horizontal zones of material, openings, also known as perforations, perpendicular to the well shaft are created. In one application, fluids may then be added to the well and the added fluids may exit though the perforations and fracture the horizontal zones of material. The fluids so added create temperature changes in the region surrounding the wellbore and also acoustic signals. The added fluid along with the desirable oil or gas may then drain back into the newly created fracture and subsequently in to the same vertical well shaft. This process is sometimes called fracturing or 'tracking' in short. The fracturing process creates very large surface areas in the reservoir rock which allows more efficient drainage of the reservoir fluids from the created fracture into the vertical shaft or well.

[0009] While general fracturing is known in the prior art, the prior art lacks means or methods to monitor multiple perforation sites and control individual valves and/or horizontal well perforation flow rates.

[0010] In another method of production of hydrocarbons, fluids may be added into an injection well and the added fluids exit from the injection well into the perforations and into the horizontal reservoir rock thereby displacing the valuable hydrocarbon into the shaft of another well, known as a production well, located some distance away. The added fluids generally change the temperature and pressure around the well shaft. These may be measured using DTS/DAS/DPS.
While general displacement methods are known in prior art, real-time monitoring of individual zonal flow rates using interpretation of DTS/DAS/DPS, control of zonal flow rates using a control valve assembly, in both injection and production wells, and the integration of all these devices to increase oil recovery is lacking.
SUMMARY

[0011] According to one aspect, there is provided a control system for injection and/or production flow profiling in at least one subsurface well, preferably a plurality of subsurface wells, preferably oil and gas wells, wherein said system uses interpretation of at least one of DTS, DAS DPS data and combinations thereof. In one embodiment, said system uses interpretation of at least one production well data, preferably at least one of water oil ratio, water gas ratio, water flow, oil flow, gas flow, pressure, temperature and combinations thereof.

[0012] According to another aspect, there is provided a method of estimating subsurface zonal flow rates, preferably via at least one distributed fiber optic sensor and continuous control of subsurface zonal flow rates.

[0013] According to yet another aspect, there is provided a system and method of controlling flow allocation of injection/production wells from subsurface zones.

[0014] According to yet another aspect, there is provided real-time control of injection and production flow rate from each zone.

[0015] According to yet another aspect, said system and method increases vertical sweep efficiency in reservoir management.

[0016] According to yet another aspect, said system comprises:
i. At least one real time flow rate measurement unit, preferably from at least one of DTS, DAS, DPS data and combinations thereof;
ii. In one embodiment, said system uses interpretation of at least one production well data, preferably at least one of water oil ratio, water gas ratio, water flow, oil flow, gas flow, pressure, temperature and combinations thereof;
iii. Optionally at least one real time method/process for detection of at least one breakthrough event, preferably for detection of a plurality of breakthrough events from said at least one of DTS, DAS, DPS
and combinations thereof data and/or production well data;
iv. at least one controller based on real time flow rate estimation from said DTA, DAS, DPS and combinations thereof data; and v. at least one control process for controlling flow allocation based on real time zonal flow measurement, preferably using down hole control valves.

[0017] According to yet another aspect, there is provided a system and method for flow allocation in a well, comprising:

I. At least one fiber optic cable for DTS, DAS, DPS and combinations thereof data measurement, preferably at high resolution;
ii. At least one real time data interpreter process to obtain a zonal flow rate;
iii. At least one control panel to receive said zonal flow rate generating a control signal for closing or opening at least one control valve meeting a predetermined flow allocation in real time.

[0018] According to yet another aspect, there is provided a system to improve recovery of oil and/or gas in a subsurface well, said system comprising:
i. At least one DTS, DAS, DPS and combinations thereof for obtaining data;
ii. At least one process to obtain an estimated zonal flow rate from said obtained data; optionally to further obtain an estimation of at least one breakthrough event; and further optionally using said at least one breakthrough event in combination with estimated zonal flow rate;
iii. At least one controller for receiving said estimated zonal flow rate and generating a control signal as a flow allocation parameter of at least one subsurface well; and iv. At least one down-hole control valve assembly for receiving said control signal and adjusting said flow allocation parameter in said subsurface well.

[0019] According to another aspect, there is provided a combination and configuration of methods and components to monitor multiple control points within a well to improve, preferably optimize, fluid injection into wells facilitating efficient fracturing and similar means of recovering oil, gas and other resources spread out laterally in a geologic system.

[0020] According to yet another aspect, there is provided a process and system of providing and using interpretation of DTS/DAS/DPS data obtained from multiple down-hole points within a well. The interpretation of DTS/DAS/DPS
data further allowing well operators to find and improve, preferably optimize the locations of the most productive fracture points within a well and to improve, preferably maximize production of oil or gas. Embodiments further include means and methods of installing and using flow control valves at multiple fracture voids of a well. Such fracture voids are typically located at different depths within a well.

[0021] Embodiments further include at least one control device or instrumentation, such as a programmable logic control (PLC) or a distributed control system (DCS) that may read and process temperature or other types of distributed sensor data from the well and send back a control signal to down-hole control valves. Each well may be equipped with at least one device reporting back data to another main control center at the surface. Each horizontal well void may also be equipped with a control valve having means to partially and/or variably open and close the well void at different zones along the well.
Control of each valve may facilitate efficient fracturing and recovery of horizontally displaced resources. Embodiments further include systems, methods to enable real-time monitoring of conditions at each horizontal pipe void or perforation. The continuous and multiple point data readings may then be fed to a disclosed control and prediction system that continuously adjusts the gross zonal rates and/or the gross pressure of fluids administered from the top of a well and continuously adjusts the down-hole valves. By monitoring temperatures, or other distributed measurements, at each horizontal pipe void, predictions may be made as to which down-hole valves should be partially closed or opened and by how much, to improve, preferably maximize resource recovery.

[0022] Embodiments also include means and methods of DTS/DAS/DPS
using fiber optic cables and other means. The data, preferably the temperature data, acquired may be inputted into the disclosed control system for flow allocation.

[0023] These and other objects and advantages will be made apparent when considering the following detailed specification when taken in conjunction with the drawings. Embodiments also include use and interpretation of other distributed fiber optic sensor data such as distributed acoustic sensors (DAS) to obtain quantitative flow profiles in real-time in addition to interpretation of DTS/DPS data for the same purpose.
Brief Description of the Drawings

[0024] FIG. 1 depicts a schematic view of a contemplated process well injection optimization

[0025] FIG. 2 depicts an injection well flow schematic

[0026] FIG. 3 depicts a control system for an injector

[0027] FIG. 4 depicts the interplay between an injection well and a production well

[0028] FIG. 4b depicts a well system with DTS/DAS/DPS installation and zonal flow control in both injection and production wells along with the controller signal flow

[0029] FIG. 5 depicts a well system of the prior art

[0030] FIG. 6 depicts a well system using means and methods consistent with the principles of the presently disclosed embodiments

[0031] FIG. 7 depicts the produced water-oil ratio with and without control as described in this disclosure.

[0032] FIG. 8 depicts the oil fraction in produced fluids with and without control as described in this disclosure.

[0033] FIG. 9 depicts a well of the prior art

[0034] FIG. 10 depicts a well system using means and methods consistent with the principles of the presently disclosed embodiments

[0035] The injected fluids in the injection wells may consist of any fluid with ability to exchange heat with the surroundings. Examples include, but are not limited to, water, steam, carbon dioxide, chemicals, and polymeric fluids.

[0036] All fluids, regardless of their heat exchange capacity, produce acoustic signals which may be measured using DAS.
DETAILED DESCRIPTION

[0037] The following detailed description is directed to certain specific embodiments. However, the system, method and/or process may be embodied in a multitude of different ways as defined and covered by the claims and their equivalents. In this description, reference is made to the drawings wherein like parts are designated with like numerals throughout.

[0038] Unless otherwise noted in this specification or in the claims, all of the terms used in the specification and the claims will have the meanings normally ascribed to these terms by workers in the art.

[0039] Unless the context clearly requires otherwise, throughout the description and the claims, the words "comprise," "comprising" and the like are to be construed in an inclusive sense as opposed to an exclusive or exhaustive sense; that is to say, in a sense of "including, but not limited to." Words using the singular or plural number also include the plural or singular number, respectively.
Additionally, the words "herein," "above," "below," and words of similar import, when used in this application, shall refer to this application as a whole and not to any particular portions of this application.

[0040] The detailed description is not intended to be exhaustive or limiting to the disclosure herein. While specific embodiments, and examples, are described for illustrative purposes, various equivalent modifications are possible within the scope herein, as those skilled in the relevant art will recognize. For example, while steps are presented in a given order, alternative embodiments may perform routines having steps in a different order. The teachings provided herein may be applied to other systems, not only the systems described herein. The various embodiments described herein may be combined to provide further embodiments. These and other changes may be made in light of the detailed description.

[0041] As shown in FIG. 1 DTS/DAS/DPS data from multiple points within a given well is fed into a DTS/DAS/DPS interpretation module and such output, in real-time, is used as input to a Control System For Flow Allocation module.
The Control System For Flow Allocation module is in connection with the control valves and may variably open and/or close control valves and/or set a specific flow rate as needed to optimize resource recovery.

[0042] FIG. 2 depicts a schematic of an injection well flow system wherein a first cylinder bore hole represents injected fluid in connection with a plurality of down-hole control valves, shown as u1 to u4. Here, while only four zones are shown, this may be extended to as many zones as there are in the field. The flow rate passing through each control valve is shown as q1 to q4. Reservoir pressure is shown as Po.

[0043] More specifically in FIG. 2 q1, q2, q3 and q4 are flow rates of the injected liquid into each zone of the reservoir, while, Pi and Po are the pressures in the well and the reservoir side of the wellbore, respectively. u1, u2, u3 and u4 are the actuator signals and in one embodiment may be the control valves that throttle the flow in a particular zone of the injection well. The flow rates q1, q2, q3 and q4 are obtained using the real-time interpretation of the DTS/DAS/DPS
data.
The method of real-time interpretation of the DTS/DAS/DPS data is an embodiment herein.

[0044] The total flow rate of injected fluids is q and is related to the individual rates by,

[0045] q = q1 + q2 + q3 + q4

[0046] Assuming instantaneous flow rate changes, and that the flow rate is proportional to pressure drop (P,,j, Poj is the pressures in the well and the reservoir side of the wellbore respectively of the jth zone , and An is pressure drop for the jth zone) one is able to relate the interval or zonal flow rates to the valve actuator setting or signal uj as follows, q = (Pi ¨ Po)itt = APitij Or, ql 11 = Api where the subscript] denotes the zone number going from 1 to 4. Based on the historic and real-time estimated values of qj one may establish a criterion for calculating the desired value of the ciisP, which would serve as the set-point for the flow rate. Alternatively these desired values may also be arbitrarily selected.
A common criteria would be to achieve uniform distribution of flow in each zone.
Other criteria may also be set such as to divert fluid from a zone to another zone based on the quantum of fluid injected into the first zone and so on.

[0047] FIG. 3 depicts the control process for a two-well system consisting of both an injection well and a production well. Here, a Cascade control system is presented where the production flow controller determines the flow rate set points for the injection well controller. This approach is illustrative and further embodiments include extensions to alternative control configurations using measurements from the production well to control the flow rates in the individual zones in the injection well directly. The desired flow rate in the intervals, of the injection well, rates qjsP , may be achieved by sending a new signal (in the form of the deviation variable for the valve actuator itiPv) to the valve actuators that is given by the following equation, DV K SI' U =j, n I

[0048] The above control strategy may be applied in any injector well to improve, preferably optimize the injection rates of the fracturing fluid to give uniform rates. Thus, in the case of a limited entry fracturing process, the above control strategy may be applied to ensure that all the reservoir rock intervals are uniformly exposed to injected fracturing fluid. Additional aspects such as the diversion of fracturing fluid may also be carried out by assigning appropriate values to the parameter Kj (which is the controller gain) in the above equation.
Here, qj is the measured /estimated flow rate.

[0049] The above form of control is the simplest form of controller action called the proportional control. Additional actions such as proportional integral and proportional integral derivative type of controls may also be achieved as shown below.
DV

= K1 (q q. SP ) + Kilt (q7 q dt + u u I AP Ti 0 AP J

[0050]
A distributed control system that implements model predictive control may be used if reservoir specific models or such information are available.
Also, note that if there are different equation forms that relate the pressure drop to the flow rate, one may also derive a control law based on such forms using the methodology outlined above.

[0051] FIG. 3 depicts a control system for an injector wherein both an injection well and production well are subjected to flow control of the present invention.
The unique aspect of this control system is the improved control of injection well flow zonal rates based on the observation of individual oil phase and water phase flow rate in the production well.

[0052] FIG. 4a depicts a disclosed Distributed Control System (DCS) in control and in communication with an injection well, down-hole control valves, zonal temperature data, a multiphase flow meter and a production well. The multiphase flow meter measures the flow rate of oil and water from the production well and this information is passed to the distributed control system.
The distributed control system then controls zonal injection rates in the injection well in such a way as to reduce, preferably minimize water injection into the swept zones and increase, preferably maximize the injection to the bypassed regions. This process increases, and preferably maximizes oil production as described in the next section. An alternative process is the reduction, preferably elimination of water production in the production well by a separate set of down-hole control valves in the production well as shown in FIG 4b. The symbols depict the control valve actuator positions of the production well.

[0053] FIG. 5 depicts a well system of the prior art wherein many oil zones are bypassed (in this depiction the first four zones are bypassed). The cause of such bypassed oil is the differences in the resistance to water flow in each zone and the ability of injected water to take the path of least resistance to flow to the production well. It is known, from geologic sciences, that the fluids from a zone do not migrate from one zone to another due to the high resistance to flow in the vertical direction.

[0054] FIG. 6 depicts a well system having improved vertical sweep due to the disclosed means and methods of the embodiments herein FIG. 6 shows a layered approach wherein horizontally disposed material is accessed via down-hole features. The simple, layered reservoir model, with different zone properties, shown here may be one of the many models to represent the reservoir rock system containing oil and gas.

[0055] The present system also embodies the case of improving the vertical sweep efficiency in systems of injector and producing wells wherein the ratio of the number of injector to producer wells either exceeds unity or is less than unity.
Under such multiple well conditions, the zonal flow rate data, obtained by interpretation of the DTS/DAS/DPS data from the production wells, may be used in the controller processes to control the injection flow rates in the injector wells to increase the oil production rate and the sweep efficiency. The production wells may also simultaneously be equipped with down-hole control valves to control production rate from multiple perforation sites.

[0056] As such, the methods for optimization and the controller processes may be written in multitude of methods and the embodiments herein include all such methods to control the injection rates and the zonal production rates in both wells to increase, preferably maximize oil recovery and reduce, preferably minimize water production rates. The present system, process and method also includes processes to increase, preferably maximize horizontal sweep efficiency between multiple injector producer well systems. Such an process may increase, preferably optimize oil production and/or reduce, preferably minimize water production, based on real-time field data as provided by the interpretation of DTS
and/or DAS and/or DPS measurements A sampling of the performance of such an process is shown in Figures 7 and 8. Another aspect of the methods proposed is an process for detecting breakthroughs based on the oil water ratio at the production well, which may be coupled to a control process/system for controlling the flow rate.

[0057] In one embodiment, the implementation of the control process/system comprises at least two components, one is the process for breakthrough detection and second is the actual manipulation of the flow rate in the thief zones. Preferably the breakthrough detection process uses measurements that are readily available in the field and relies on robust methods that are insensitive to potential noise in the measurements. Such breakthrough detection at any time (t(i) may be determined by the following conditions:
if adyma8(i)-dyma20(i)]>=a1) & (y(i)>I31)) & (t(i)-timelastbreakthough>cl) breakthroughevent=1

[0058] Here dyma8 and dyma20 are the moving averages of the rate of change of water-oil ratio with 8 and 20 day intervals, y is water-oil ratio, timelastbreakthrough corresponds to the time at which the last breakthrough is deemed to have occurred, and al, bl and cl refers to threshold that would be case specific for each well. These case specific parameters along with the optimal windows for the moving averages may be easily determined from well history data or using data from simulations of the well. For extremely noisy data, these filters may be improved by integrating peak detection processes with the approach shown above.

[0059] In the second part of the control process, manipulation of the flow rate in the thief zones may be achieved in several ways. In the simplest version, the flow in the wells is simply shut-off or in other words, an on-off control system is implemented. The proposed strategy has been implemented using a sophisticated 3D simulator that is the industry standard for water flooding studies in petroleum engineering (UTCHEM) however other simulators know to people skilled in the art may also be used, for example, but not limited to ECLIPSE, CMG IMEX and JewelSuiteTm. Here, the layered reservoir was divided into eight zones with varying permeability that is representative of typical oil fields.
While eight zones were used herein, this approach may be extended to consider a different number of zones. Two cases, namely the "with control" and "without control" were studied. In the "without control" case, no control is implemented and water is injected at uniform pressure at rates naturally accepted by the geologic formation across the zones. In the "with control" case, an process was used to detect breakthroughs and manipulate the flow rate in the different zones using the DTS measurements. The results of using such an process are seen in Figures 7 and 8 describing the Water-Oil Production Rate Ratio and the Oil Fraction (ratio of the oil flow rate to the total fluid flow rate). The resulting effect of the control process improves the oil recovered by minimizing the amount of water in the production well. While the effect of simple control strategy has been illustrated, this may be extended to sophisticated control processes such as model predictive control, where 3D models such as the one used to simulate water flooding are also used to design the optimal manipulation of the flow rate to reduce, preferably minimize water-oil ratio and to increase, preferably maximize hydrocarbon recovery.

[0060] FIG. 9 depicts a low productivity well of the prior art not having an injection profile control system. The well of FIG. 9 has low productivity due to non-uniform hydraulic fracturing stimulation. The extent of opening of the rock, due to hydraulic fracturing, is shown as the magnitude of the symbol resembling a thunderbolt. The larger the symbol, the larger the fracture opening.

[0061] FIG. 10 depicts an improvement over the prior art and displays principles of the present system, method and/or process which includes uniform fracturing obtained with an injection profile control system.

[0062] An additional application is in the field of alternative energy technology, such as geothermal well heat recovery from hot rock geothermal systems, using wells for injection and production. Heat recovery from subsurface geothermal systems is affected by similar inefficiencies as in oil and gas reservoirs. In general, the methods described for the above applications may also be used to improved sweep efficiency in geothermal systems by improving, preferably optimizing the injection profile and flow rate of cold water to improve, preferably maximize the exposure of the hot rock for efficient heat exchange.

[0063] In another embodiment, the method and products developed based on this method may also be applied to wells that are placed horizontal to the Earth's surface for improved and enhanced oil and gas recovery.

[0064] In another embodiment, this invention may be extended to multiple injection and production wells, where the methods and products described here may be applied to manipulate injection in multiple wells based on the data from multiple wells.

[0065] These and other changes may be made in light of the above detailed description. In general, the terms used in the following claims, should not be construed to limit the invention to the specific embodiments disclosed in the specification.

Claims

What is claimed is:

1. A control system for injection and/or production flow profiling in at least one subsurface well, preferably oil and gas wells, wherein said system uses interpretation of at least one of DTS, DAS DPS data and combinations thereof and/or production well data such as water oil ratio, water gas ratio, water flow, oil flow, gas flow, temperature and pressure.

2. Use of at least one of DTS, DAS DPS data and combinations thereof and/or production well data such as water oil ratio, water gas ratio, water flow, oil flow, gas flow, temperature and pressure for controlling injection and/or production flow in at least one subsurface well.

3. A method of estimating subsurface zonal flow rates via at least one distributed fiber optic sensor and continuous control of subsurface zonal flow rates comprising the steps of:
i. Filtering and processing said field data to obtain representative values of distributed temperature, pressure, or acoustics;
ii. Interpreting said field data using a mathematical model to obtain zonal flow rates in real time; and optionally iii. Feeding said field data into an process for estimating flow rates.

4. A system and method of controlling allocation of injection/production from subsurface zones as described herein.

5. Real-time control of injection and production flow rate from each zone as described herein.

6. A system for controlling allocation of injection/production from subsurface zones comprising:
i. real time flow rate measurement unit, from at least one of DTS, DAS, DPS data and combinations thereof;
ii. additional optional real time method for detection of breakthrough events from the said data and/ or production data;
iii. at least one controller based on real time flow rate estimation from said data; and iv. at least one control process for controlling flow allocation based on real time zonal flow measurement.

7. A system and method for flow allocation in at least one well, said system comprising:
i. at least one fiber optic cable for DTS, DAS, DPS and combinations thereof data measurement, preferably at high resolution;
ii. at least one real time data interpreter to obtain a zonal flow rate;
and iii. at least one control panel to receive said zonal flow rate generating a control signal closing or opening at least one control valve meeting a predetermined flow allocation in real time.
and said method comprising the method of claim 2 and 1. a control/optimization process to determine flow allocation using the estimated zonal flow rate data and/or production well data.

8. A system to improve recovery of oil and/or gas in a subsurface well, said system comprising:
i. at least one DTS, DAS, DPS and combinations thereof for obtaining data;
ii. at least one process to obtain an estimated zonal flow rate from said obtained data;

iii. at least one controller for receiving said estimated zonal flow rate and generating a control signal as a flow allocation parameter; and iv. at least one down-hole control valve assembly for receiving said control signal and adjusting said flow allocation in said subsurface well.