US20180187533A1 - Hydrocarbon production by fluidically isolating vertical regions of formations - Google Patents
Hydrocarbon production by fluidically isolating vertical regions of formations Download PDFInfo
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- US20180187533A1 US20180187533A1 US15/399,661 US201715399661A US2018187533A1 US 20180187533 A1 US20180187533 A1 US 20180187533A1 US 201715399661 A US201715399661 A US 201715399661A US 2018187533 A1 US2018187533 A1 US 2018187533A1
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
- E21B43/14—Obtaining from a multiple-zone well
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/12—Packers; Plugs
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B34/00—Valve arrangements for boreholes or wells
- E21B34/06—Valve arrangements for boreholes or wells in wells
- E21B34/08—Valve arrangements for boreholes or wells in wells responsive to flow or pressure of the fluid obtained
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
- E21B43/162—Injecting fluid from longitudinally spaced locations in injection well
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
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- E21B47/065—
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
Abstract
Techniques of hydrocarbon production by fluidically isolating vertical regions of formation are described. A subterranean zone entrapping hydrocarbons includes multiple vertically arranged regions. Each region has a respective permeability for fluid flow. An open production well to produce the hydrocarbons and an open injection well to aid hydrocarbon production are formed in the subterranean zone through the multiple vertically arranged regions. At each of the production well and the injection well, the vertically arranged regions are fluidically isolated from each other. Injection fluid injected through the injection well into a fluidically isolated region is substantially confined to flow in the fluidically isolated region. A flow of the injection fluid into each fluidically isolated region is controlled to control a recovery of hydrocarbons trapped in each fluidically isolated region.
Description
- This specification relates to a hydrocarbon production from a hydrocarbon reservoir.
- Production wells are formed in hydrocarbon reservoirs to retrieve hydrocarbons. In some instances, injection wells are also formed in the same reservoir to enhance hydrocarbon production through the production wells. Sometimes, the factors within the reservoir, such as variable permeability, can cause injection fluid to flow from the injection wells into one region of the hydrocarbon reservoir more than another.
- This specification describes technologies relating to hydrocarbon production by fluidically isolating vertical regions of formations.
- Certain aspects of the subject matter described here can be implemented as a method. A subterranean zone entrapping hydrocarbons includes multiple vertically arranged regions. Each region has a respective permeability for fluid flow. An open production well to produce the hydrocarbons and an open injection well to aid hydrocarbon production are formed in the subterranean zone through the multiple vertically arranged regions. At each of the production well and the injection well, the vertically arranged regions are fluidically isolated from each other. Injection fluid injected through the injection well into a fluidically isolated region is substantially confined to flow in the fluidically isolated region. A flow of the injection fluid into each fluidically isolated region is controlled to control a recovery of hydrocarbons trapped in each fluidically isolated region.
- This, and other aspects, can include one or more of the following features. The multiple vertically arranged regions can include a first region, a second region, and a third region vertically arranged in that sequence. A permeability of the first region can be more than a permeability of the second region and less than a permeability of the third region. To fluidically isolate the vertically arranged regions from each other, an injection tubing can be lowered into the injection well. The injection tubing can extend from a surface of the subterranean zone through the first region, the second region and the third region. A first packer can be installed around the injection tubing in an annulus between the injection well and the subterranean zone and at a location of the second region. The first packer can have at least a thickness of the second region. To control the flow of the injection fluid into each fluidically isolated region to control the recovery of the hydrocarbons trapped in each fluidically isolated region, a first valve can be installed in a portion of the injection tubing residing in the first region and a second valve in a portion of the injection tubing residing in the third region. The flow of the injection fluid into the first region and the third region can be controlled by controlling the first valve and the third valve, respectively. A first sensor can be installed in the portion of the injection tubing residing in the first region. The first sensor can be configured to sense a fluid parameter of the injection fluid flowed through the portion of the injection tubing. The flow of the injection fluid into the first region can be controlled based on the fluid parameter sensed using the first sensor. The first sensor can include a pressure sensor or a flow meter. A production tubing can be lowered into the production well. The production tubing can extend from a surface of the subterranean zone through the first region, the second region and the third region. A second packer can be installed around the production tubing in an annulus between the production well and the subterranean zone and at a location of the second region. The second packer can have at least a thickness of the second region. A second sensor can be installed in the portion of the injection tubing residing in the first region. The second sensor can be configured to sense a temperature of the injection fluid flowed through the injection tubing. The flow of the injection fluid through the first region can be controlled based on the temperature sensed using the second sensor. The second sensor can include a pressure sensor or a flow meter. The flow of the injection fluid into each fluidically isolated region can be controlled based on determining breakthrough of injection fluid from the injection well into the production well. To control the flow of the injection fluid into each fluidically isolated region based on determining breakthrough of the injection fluid from the injection well into the production well, breakthrough of the injection fluid into a region of the subterranean zone in which the production well resides can be detected. The production well can be shut in at the surface. Injection fluid flow into the region of the subterranean zone in which the injection well resides can be shut off. The flow of the injection fluid into each fluidically isolated region can be controlled based on determining cross flow from a high permeability region to a low permeability region that is fluidically isolated from the high permeability region. To control the flow of the injection fluid into each fluidically isolated region based on determining cross flow from a high permeability region to a low permeability region, injection fluid flow can be shut off in response to determining the cross flow from the high permeability region to the low permeability region.
- Certain aspects of the subject matter described here can be implemented as a method. A production well is formed in a subterranean zone that includes multiple vertically arranged regions. Each vertically arranged region has a respective permeability for fluid flow. The production well extends through the multiple regions. An injection well is formed in the subterranean zone to aid hydrocarbon production through the production well. The injection well extends through the multiple regions. At each of the production well and the injection well, the vertically arranged regions are fluidically isolated from each other. Injection fluid injected through the injection well into a fluidically isolated region is substantially confined to flow in the fluidically isolated region. A flow of the injection fluid into each fluidically isolated region is controlled to control a recovery of hydrocarbons trapped in each fluidically isolated region.
- This, and other aspects, can include one or more of the following features. The flow of the injection fluid into each fluidically isolated region can be controlled based on determining breakthrough of injection fluid from the injection well into the production well. To control the flow of the injection fluid into each fluidically isolated region based on determining breakthrough of the injection fluid from the injection well into the production well, breakthrough of the injection fluid into a region of the subterranean zone in which the production well resides can be detected. The production well can be shut in at the surface. Injection fluid flow into the region of the subterranean zone in which the injection well resides can be shut off. The flow of the injection fluid into each fluidically isolated region can be controlled based on determining cross flow from a high permeability region to a low permeability region that is fluidically isolated from the high permeability region. To control the flow of the injection fluid into each fluidically isolated region based on determining cross flow from a high permeability region to a low permeability region, injection fluid flow into the high permeability region can be shut off in response to determining the cross flow from the high permeability region to the low permeability region.
- Certain aspects of the subject matter described here can be implemented as a method. A subterranean zone entrapping hydrocarbons includes a first region, a second region, and a third region vertically arranged in that sequence. A permeability of the first region is more than a permeability of the second region and less than a permeability of the third region. An open production well to produce the hydrocarbons and an open injection well to aid hydrocarbon production are formed in the subterranean zone through the three regions. At each of the production well and the injection well, the first region is fluidically isolated from the third region. Injection fluid injected through the injection well into the first region is substantially confined to flow in the first region and not the third region, and vice versa. A flow of the injection fluid into each fluidically isolated region is controlled to control a recovery of hydrocarbons trapped in each fluidically isolated region.
- This, and other aspects, can include one or more of the following features. To fluidically isolate the first region from the third region, an injection tubing can be lowered into the injection well. The injection tubing can extend from a surface of the subterranean zone through the first region, the second region and the third region. A first packer can be installed around the injection tubing in an annulus between the injection well and the subterranean zone, and at a location of the second region. The first packer has at least a thickness of the second region. To control the flow of the injection fluid into each fluidically isolated region to control the recovery of the hydrocarbons trapped in each fluidically isolated region, a first valve can be installed in a portion of the injection tubing residing in the first region and a second valve can be installed in a portion of the injection tubing residing in the third region. The flow of the injection fluid into the first region and the third region can be controlled by the first valve and the third valve, respectively.
- The details of one or more implementations of the subject matter described in this specification are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.
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FIG. 1 is a schematic of an example production field with fluidically isolated regions in the same reservoir zone. -
FIG. 2 is a schematic of an example production field with open hole completions. -
FIG. 3 is a schematic of the example production field ofFIG. 1 with an isolated region. -
FIG. 4 is a schematic of the example production field ofFIG. 1 with isolated injection sections. -
FIG. 5 shows a flowchart of an example method for creating and utilizing a production field with fluidically isolated regions in the same reservoir zone. - Like reference numbers and designations in the various drawings indicate like elements.
- This disclosure describes a method for producing a hydrocarbon field which utilizes both injection and production wellbores. In hydrocarbon production, there are many methods that can be utilized to complete a wellbore including open hole completions. An open hole wellbore has no casing and leaves the rock of a geological formation exposed to the interior of the wellbore. Often in a production field, there are both production wellbores and injection wellbores. Hydrocarbons are produced out of production wellbores while fluid (for example, gas, water, brine, or other fluid) is injected into the formation with injection wellbores. The injection process helps “push” hydrocarbons towards the production wellbore where they can be produced. In the case of open hole completions, it is difficult to direct the injection fluid where it is needed. The injection fluid will follow the path of least resistance, that is, go through sections of the reservoir with higher permeability. The higher permeability areas of a reservoir typically need less injection fluid to push the hydrocarbons towards the production wells. This can result in early water breakthrough when the injection fluid starts being produced with the hydrocarbons. Alternatively, hydrocarbons are left in place within low to medium permeability regions of a production field. On top of hydrocarbons being left in place, injection fluids can cross flow from one porous region to another within the production wellbore and push hydrocarbons away from the production wellbore.
- Early water breakthrough can occur when injection fluid has pushed much of the recoverable hydrocarbons out of its region leaving injection fluid free to be produced. Early water breakthrough can increase the water-cut, that is, the percentage of the production fluid that is water, of the production well. Higher water-cuts can lead to process and flow assurance issues, such as hydrate formation. Another potential issue is cross flow in the production wellbore. Cross flow occurs when there is sufficient pressure differential between two production regions to cause fluid flow in between them via the wellbore. This often occurs when the production wellbore is shut-in (not producing). When cross flow occurs, injection fluid can push hydrocarbons away from the production wellbore.
- As described later, an integrated recovery system including production tubing, well-placed open hole packers, isolation valves, and various sensors, can prevent early water breakthrough and cross flow. The system described here also allows for targeted injection and production within a reservoir to maximize hydrocarbon recovery in a tight layer. For example, a low permeability region cannot produce hydrocarbons at the same rate as other regions. Therefore, if the other regions are shut-in, as will be explained later, all of the production wells in a given field could be temporarily converted to only low permeability wells to enhance the hydrocarbon recovery in the low permeability region. The techniques described later can be applied to a production zone that has any number of vertically arranged production regions of differing permeabilities. The techniques described later are not limited to vertical wellbores and will work for angled wellbores.
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FIG. 1 shows a schematic of anexample production field 100 with a subterranean zone entrapping hydrocarbons. This zone is subdivided into vertically arranged, fluidically isolated regions in the same reservoir zone. In this example, theproduction field 100 has anon-producing region 101, an upper layer ofseal rock 102, afirst production region 104, a first (low permeability)tight streak 106, asecond production region 108, a secondtight streak 110, and athird production region 112. - Tight streaks are sections of low permeability, but they are different from seal rock, which has almost no permeability. As a result, the various regions in
field 100 are within the same production zone of the reservoir. Permeability is a measure of how easily fluid can flow through a section of rock. The higher the permeability, the easier fluid flows through the rock. Production zones do not always have a uniform permeability, andintegrated production system 1000 takes advantage of that by placing packers in line with naturally occurring tight streaks. Tight streaks have a low permeability in comparison to the production regions. Inexample production field 100, permeability of thefirst production region 104 is less than the permeability of thesecond production region 108, and the permeability of thesecond production region 108 is less than a permeability of thethird production region 112. - Within the production field there is a
production wellbore 162 and aninjection wellbore 164. The production wellbore 162 has aproduction well tree 131 and aproduction panel box 132 positioned on the uphole end of theproduction wellbore 162. Theproduction well tree 131 is configured to control the flow of the well, and theproduction panel 132 acts as the interface for all of the sensors and controls forproduction wellbore 162. The injection wellbore 164 has aninjection well tree 133 and aninjection panel box 134 positioned on the uphole end of theinjection wellbore 164. The injection welltree 164 is configured to control the flow of the well and theinjection panel 134 acts as the interface for all of the sensors and controls forproduction wellbore 162. A production cased-hole packer 144 positioned at the top of the producing section of thewellbore 162 while the injection wellbore 164 has an injection cased hole packer 114 at the top of the injection section of theinjection wellbore 164. As stated above, hydrocarbons can be produced out ofproduction wellbore 162 while fluid (for example, gas, water, brine, or other fluid) can be injected into the formation withinjection wellbore 164. The injection process helps “push” hydrocarbons towards the production wellbore 162 where they can be produced. - As permeability is variable across each production region, the effectiveness of injection is variable as well. For example,
production region 112 has a high permeability, so injection may push the hydrocarbons in this region towards the production wellbore 162 at a faster rate than they would inproduction region 104. The effects of variable permeability are explained in greater detail later in the disclosure. - An
integrated recovery system 1000 is installed inproduction field 100. The production wellbore 162 contains aproduction tubing 166 that is substantially the length of the wellbore. That is, theproduction wellbore 162 is long enough to reach every production region that theproduction wellbore 162 goes through. Theproduction tubing 166 has a flow regulator to regulate the flow in each production region. The flow regulation can be done with a valve or by other techniques. In other words, production for each region can be turned on or off or throttled somewhere in between. In the example ofFIG. 1 , a firstopen production valve 148 is located on theproduction tubing 166 within thefirst production region 104. A secondopen production valve 154 is located onproduction tubing 166 within thesecond production region 108. A thirdopen production valve 160 is located onproduction tubing 166 within thethird production region 112. The valves inproduction tubing 166 can be any valve suitable for both sealing and throttling flow, such as a gate valve. The valves inproduction tubing 166 can be controlled through several different types of control systems, such as a hydraulic control system. The flow through theproduction tubing 166 is co-mingled between all regions. - Each production region within the
production wellbore 162 is fluidically isolated with an open hole packer and a tight streak, that is, flow between each region is negligible; Flow only flows substantially through the regions rather than across regions. Tight streaks can have a permeability of 0.5 to 2 millidarcy while a production region can have a permeability of 20 to 150 millidarcy. In the example ofFIG. 1 , thefirst production region 104 is isolated from thesecond production region 108 by afirst production packer 150 and the firsttight streak 106. Thefirst production packer 150 is positioned in line with the firsttight streak 106 to provide proper isolation. The low permeability of the tight streaks reduces fluid flow across them to the point that production flow between regions is negligible. Each production region within the production wellbore 162 can contain a pressure sensor, a flow meter, or both. In the example ofFIG. 1 , a firstproduction pressure sensor 146 can be positioned within thefirst production region 104 ofproduction wellbore 162. A secondproduction pressure sensor 152 can be positioned within thesecond production region 108 ofproduction wellbore 162. A thirdproduction pressure sensor 158 can be positioned within thethird production region 112 ofproduction wellbore 162. Different types of pressure sensor can be used inwellbore 162, such as quartz pressure transducers. Each sensor is capable of transmitting information to a topside facility. The information is transmitted via a firstproduction sensor line 126. The firstproduction sensor line 126 can be made up of hydraulic tubing, electrical conductors, fiber optic cabling, or any combination of the three. Afirst flow meter 172 can be positioned within thefirst production region 104 ofproduction wellbore 162. Asecond flow meter 174 can be positioned within thesecond production region 108 ofproduction wellbore 162. Athird flow meter 176 can be positioned within thethird production region 112 ofproduction wellbore 162. Different types of flowmeters can be used withinwellbore 162, such as a venturi meter. Each flow meter is capable of transmitting information to a topside facility. The information can be transmitted via a secondproduction sensor line 170 or via the firstproduction sensor line 126. The secondproduction sensor line 170 can be made up of hydraulic tubing, electrical conductors, fiber optic cabling, or any combination of the three. - Any of the production sensors are capable of detecting water breakthrough. Water breakthrough can be detected by the increase in water-cut at the surface; downhole sensors, such as
flow meter 172 orpressure sensor 146, can indicate which production region is producing water. Early water breakthrough may be considered more than 35% water at the surface of an oil producing well. Early water breakthrough occurs when a high oil flow rate from a high permeability production zone is displaced byinjection fluid 208. High volumes of theinjection fluid 208 preferentially flows through higher permeability production regions. When water breakthrough is detected, a single production region can be shut-in or multiple production regions can be shut-in. Any of the production sensors are capable of detecting cross flow. The Crossflow can happen when theproduction wellbore 162 is shut-in at surface. Shutting-in the production wellbore 162 at surface is required at times for maintenance or during periods of low oil demand. In some cases, crossflow is detected with a wireline flow meter survey. A wireline flowmeter survey involves running a spinner meter downhole. - A single production region can be shut-in or multiple production regions can be shut-in. A region is shut-in whenever both the production valve and the injection valve is closed within the same region. As each region is effectively isolated, the other regions can continue injection and production operations. Additionally, each region can be configured to shut-in when a well-choke is closed. Shutting-in a region is disclosed in detail later in this disclosure.
- The injection wellbore 164 contains an
injection tubing 168 that is substantially the length of the wellbore, that is, it is long enough to reach every production region that the injection wellbore 164 goes through. Theinjection tubing 168 has a flow regulator to regulate the flow in each production region. The flow regulation can be done with a valve or any other techniques. In other words, injection for each region can be turned on or off or throttled somewhere in between. In the example ofFIG. 1 , a firstopen injection valve 116 is located on theinjection tubing 168 within thefirst production region 104. A secondopen injection valve 120 is located oninjection tubing 168 within thesecond production region 108. A thirdopen injection valve 124 is located oninjection tubing 168 within thethird production region 112. The valves ininjection tubing 168 can be any valve suitable for both sealing and throttling flow, such as a gate valve. The valves ininjection tubing 168 can be controlled through several different types of control systems, such as a hydraulic control system. The flow through theinjection tubing 168 is co-mingled between all of the regions. - Each production region within the injection wellbore 164 is fluidically isolated with an open hole packer and a tight streak. In the example of
FIG. 1 , thefirst production region 104 is isolated from thesecond production region 108 by afirst injection packer 118 and the firsttight streak 106. Thefirst injection packer 118 is positioned in line with the firsttight streak 106 to provide proper isolation. The low permeability of the tight streaks reduces fluid flow across them to the point that injection flow between regions is negligible. - Each production region within the injection wellbore 164 contains a sensor that can measure pressure, flow, or both. In the example of
FIG. 1 , a firstinjection pressure sensor 138 is positioned within thefirst production region 104 ofinjection wellbore 164. A secondinjection pressure sensor 140 is positioned within thesecond production region 108 ofinjection wellbore 164. A thirdinjection pressure sensor 142 is positioned within thethird production region 112 ofinjection wellbore 164. Each sensor is capable of transmitting information in real time to a topsides facility. The information is transmitted via a firstinjection sensor line 136. The firstinjection sensing line 136 can be made up of hydraulic tubing, electrical conductors, fiber optic cabling, or any combination of the three. In some implementations, a first injection flowmeter is positioned within thefirst production region 104 ofinjection wellbore 164. A second injection flowmeter is positioned within thesecond production region 108 ofinjection wellbore 164. A third injection flowmeter is positioned within thethird production region 112 ofinjection wellbore 164. Each flowmeter is capable of transmitting information in real time to a topsides facility. The information can be transmitted via a firstinjection sensor line 136, or a dedicated sensor line can be used. The firstinjection sensing line 136 can be made up of hydraulic tubing, electrical conductors, fiber optic cabling, or any combination of the three. Flow of injection fluid into each region can be controlled in real time based on readings from the flowmeters. Different flowmeters can be used ininjection wellbore 164, such as a venture flow meter. - Each production region within the injection wellbore 164 can contain a temperature sensor, such as
sensing line 130. In the example ofFIG. 1 ,temperature sensing line 130 is a fiber optic cable capable of sensing a temperature profile across multiple production regions. Thetemperature sensing line 130 is capable of transmitting information to a topside facility. Flow of injection fluid into each region can be controlled based on readings from thetemperature sensing line 130. For example, thetemperature sensing line 130 could be used to determine a warm-back profile of the wellbore. A warm back profile is taken whenever an injection well is shut-in, and details the rate that the wellbore “warms up”. Based on the warm-up rate for each region, permeability can be determined. The warm-back profile can assist engineers in determining an ideal injection rate for each region. - As mentioned earlier,
integrated production system 1000 prevents several issues that can plague open hole wellbores, such as those shown inproduction field 100. Such issues can include crossflow in a wellbore, early water breakthrough, as well as others.FIG. 2 shows theproduction field 100 ofFIG. 1 withoutintegrated recovery system 1000 installed. In this example,injection fluid 208 is pumped down the injection wellbore 164 whilehydrocarbons 202 are produced from theproduction well 162. Injection fluid starts to travel through the various production zones once the injection wellbore 164 is pressurized. Afirst injection flow 210 flows through thefirst production region 104. Asecond injection flow 212 flows through thesecond production region 108. Athird injection flow 214 flows through thethird production region 112. Thefirst injection flow 210 is substantially confined from the second injection flow by the firsttight streak 106. Thesecond injection flow 212 is substantially confined from thefirst injection flow 210 and thethird injection flow 214 bytight streak 106 andtight streak 110 respectively. Thethird injection flow 214 is substantially confined from thesecond injection flow 212 bytight streak 110. The flow through the injection wellbore 164 is co-mingled between all of the regions. The flow through theproduction wellbore 162 is co-mingled between all regions as well. Co-mingling can occur because the various production regions are in the same production zone of the reservoir, so chemical reactions between the regions is unlikely to occur. - The injection flow rates in each production region are proportional to the permeability of each production region, that is, the injection flow rate can be different in each region. As mentioned earlier, the variable permeability in each region can lead to
early water breakthrough 204 orcrossflow 206. InFIG. 3 , theexample production field 100 is shown with thethird production region 112 isolated from bothinjection tubing 168 andproduction tubing 166. A closedthird injection valve 304 and a closedthird production valve 302 isolate theproduction region 112 from theinjection tubing 168 andproduction tubing 166. Both closed valves in addition to thesecond production packer 156,second injection packer 122, andtight streak 110 effectively isolateproduction region 112 from the rest of theproduction field 100. Such isolation preventsearly water breakthrough 204 andcross flow 206. - In
FIG. 4 , theexample production field 100 is shown with injection disabled inproduction zone 108 andproduction zone 112. A secondclosed injection valve 402 in addition to thefirst injection packer 118, the firsttight streak 106, thesecond injection packer 122, and the secondtight streak 110 isolateproduction region 108 from injection. A thirdclose injection valve 304 in addition to thesecond injection packer 122 and the secondtight streak 110 isolateproduction region 112 from injection. Such isolation allows injection fluid to be targeted only where it is needed, preventsearly water breakthrough 204, and preventscross flow 206. -
FIG. 5 shows a flowchart for a potential method to utilize theintegrated recovery system 1000 for hydrocarbon production. At 502, a production well is formed in a geologic formation. At 504, an injection well is formed in a geologic formation. At 506, vertically arranged regions are fluidically isolated from one another. The isolation occurs by loweringproduction tubing 166 into theproduction wellbore 162, and loweringinjection tubing 168 intoinjection wellbore 164. Packers are placed around theproduction tubing 166 in the annulus between the outer surface of theproduction tubing 166 and the inner surface of theproduction wellbore 162. Packers are also placed around theinjection tubing 168 in the annulus between the outer surface of theinjection tubing 168 and the inner surface of theinjection wellbore 164. Each packer is installed in line with a respective tight streak. Valves are installed on theproduction tubing 166 at depths that correspond with each production region. Valves are also installed on theinjection tubing 168 at depths that correspond with each production region. The valves can be throttled to control the rate of injection in each production region. At 508, the flow of injection fluid is controlled into each fluidically isolated region. The fluid injection and production operations can be controlled by an operator or an automated controller. An automated controller can control valves within a wellbore or within a topside facility. - As stated previously, the techniques described here can be applied to a production zone that has any number of vertically arranged regions of differing permeabilities. The techniques disclosed before are not limited to vertical wellbores and will work for angled wellbores.
- Thus, particular implementations of the subject matter have been described. Other implementations are within the scope of the following claims.
Claims (20)
1. A method comprising:
in a subterranean zone entrapping hydrocarbons, the subterranean zone comprising multiple vertically arranged regions, each region having a respective permeability for fluid flow, an open production well to produce the hydrocarbons and an open injection well to aid hydrocarbon production formed in the subterranean zone through the multiple vertically arranged regions:
at each of the production well and the injection well, fluidically isolating the vertically arranged regions from each other, wherein injection fluid injected through the injection well into a fluidically isolated region is substantially confined to flow in the fluidically isolated region; and
controlling a flow of the injection fluid into each fluidically isolated region to control a recovery of hydrocarbons trapped in each fluidically isolated region.
2. The method of claim 1 , wherein the multiple vertically arranged regions comprise a first region, a second region, and a third region vertically arranged in that sequence, wherein a permeability of the first region is more than a permeability of the second region and less than a permeability of the third region, wherein fluidically isolating the vertically arranged regions from each other comprises:
lowering an injection tubing into the injection well, the injection tubing extending from a surface of the subterranean zone through the first region, the second region and the third region; and
installing a first packer around the injection tubing in an annulus between the injection well and the subterranean zone and at a location of the second region, the first packer having at least a thickness of the second region.
3. The method of claim 2 , wherein controlling the flow of the injection fluid into each fluidically isolated region to control the recovery of the hydrocarbons trapped in each fluidically isolated region comprises:
installing a first valve in a portion of the injection tubing residing in the first region and a second valve in a portion of the injection tubing residing in the third region; and
controlling the flow of the injection fluid into the first region and the third region by controlling the first valve and the second valve, respectively.
4. The method of claim 3 , further comprising:
installing a first sensor in the portion of the injection tubing residing in the first region, the first sensor configured to sense a fluid parameter of the injection fluid flowed through the portion of the injection tubing, wherein the flow of the injection fluid into the first region is controlled based on the fluid parameter sensed using the first sensor.
5. The method of claim 4 , wherein the first sensor comprises a pressure sensor or a flow meter.
6. The method of claim 2 , further comprising:
lowering a production tubing into the production well, the production tubing extending from a surface of the subterranean zone through the first region, the second region and the third region; and
installing a second packer around the production tubing in an annulus between the production well and the subterranean zone and at a location of the second region, the second packer having at least a thickness of the second region.
7. The method of claim 6 , further comprising:
installing a second sensor in the portion of the injection tubing residing in the first region, the second sensor configured to sense a temperature of the injection fluid flowed through the injection tubing, wherein the flow of the injection fluid through the first region is controlled based on the temperature sensed using the second sensor.
8. The method of claim 6 , wherein the second sensor comprises a pressure sensor or a flow meter.
9. The method of claim 1 , further comprising controlling the flow of the injection fluid into each fluidically isolated region based on determining breakthrough of injection fluid from the injection well into the production well.
10. The method of claim 9 , wherein controlling the flow of the injection fluid into each fluidically isolated region based on determining breakthrough of the injection fluid from the injection well into the production well comprises:
detecting breakthrough of the injection fluid into a region of the subterranean zone in which the production well resides;
shutting in the production well at the surface; and
shutting off injection fluid flow into the region of the subterranean zone in which the injection well resides.
11. The method of claim 1 , further comprising controlling the flow of the injection fluid into each fluidically isolated region based on determining cross flow from a high permeability region to a low permeability region that is fluidically isolated from the high permeability region.
12. The method of claim 11 , wherein controlling the flow of the injection fluid into each fluidically isolated region based on determining cross flow from a high permeability region to a low permeability region comprises, in response to determining the cross flow from the high permeability region to the low permeability region, shutting off injection fluid flow into the high permeability region.
13. The method of claim 11 , further comprising detecting the cross flow using a sensor.
14. A method comprising:
forming a production well in a subterranean zone comprising multiple vertically arranged regions, each having a respective permeability for fluid flow, the production well extending through the multiple regions;
forming an injection well in the subterranean zone to aid hydrocarbon production through the production well, the injection well extending through the multiple regions;
at each of the production well and the injection well, fluidically isolating the vertically arranged regions from each other, wherein injection fluid injected through the injection well into a fluidically isolated region is substantially confined to flow in the fluidically isolated region; and
controlling a flow of the injection fluid into each fluidically isolated region to control a recovery of hydrocarbons trapped in each fluidically isolated region.
15. The method of claim 14 , further comprising controlling the flow of the injection fluid into each fluidically isolated region based on determining breakthrough of injection fluid from the injection well into the production well.
16. The method of claim 15 , wherein controlling the flow of the injection fluid into each fluidically isolated region based on determining breakthrough of the injection fluid from the injection well into the production well comprises:
detecting breakthrough of the injection fluid into a region of the subterranean zone in which the production well resides;
shutting in the production well at the surface; and
shutting off injection fluid flow into the region of the subterranean zone in which the injection well resides.
17. The method of claim 14 , further comprising controlling the flow of the injection fluid into each fluidically isolated region based on determining cross flow from a high permeability region to a low permeability region that is fluidically isolated from the high permeability region.
18. The method of claim 17 , wherein controlling the flow of the injection fluid into each fluidically isolated region based on determining cross flow from a high permeability region to a low permeability region comprises, in response to determining the cross flow from the high permeability region to the low permeability region, shutting off injection fluid flow into the high permeability region.
19. A method comprising:
in a subterranean zone entrapping hydrocarbons, the subterranean zone comprising a first region, a second region, and a third region vertically arranged in that sequence, wherein a permeability of the first region is more than a permeability of the second region and less than a permeability of the third region, an open production well to produce the hydrocarbons and an open injection well to aid hydrocarbon production formed in the subterranean zone through the three regions:
at each of the production well and the injection well, fluidically isolating the first region from the third region, wherein injection fluid injected through the injection well into the first region is substantially confined to flow in the first region and not the third region, and vice versa; and
controlling a flow of the injection fluid into each fluidically isolated region to control a recovery of hydrocarbons trapped in each fluidically isolated region.
20. The method of claim 19 , wherein fluidically isolating the first region from the third region comprises:
lowering an injection tubing into the injection well, the injection tubing extending from a surface of the subterranean zone through the first region, the second region and the third region; and
installing a first packer around the injection tubing in an annulus between the injection well and the subterranean zone and at a location of the second region, the first packer having at least a thickness of the second region, and
wherein controlling the flow of the injection fluid into each fluidically isolated region to control the recovery of the hydrocarbons trapped in each fluidically isolated region comprises:
installing a first valve in a portion of the injection tubing residing in the first region and a second valve in a portion of the injection tubing residing in the third region; and
controlling the flow of the injection fluid into the first region and the third region by controlling the first valve and the second valve, respectively.
Priority Applications (4)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US15/399,661 US20180187533A1 (en) | 2017-01-05 | 2017-01-05 | Hydrocarbon production by fluidically isolating vertical regions of formations |
PCT/US2018/012197 WO2018129053A1 (en) | 2017-01-05 | 2018-01-03 | Hydrocarbon production by fluidically isolating vertical regions of formations |
CN201880008765.6A CN110249109A (en) | 2017-01-05 | 2018-01-03 | Pass through the hydrocarbon production of the vertical area on fluid isolation stratum |
EP18701613.4A EP3565949A1 (en) | 2017-01-05 | 2018-01-03 | Hydrocarbon production by fluidically isolating vertical regions of formations |
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US15/399,661 US20180187533A1 (en) | 2017-01-05 | 2017-01-05 | Hydrocarbon production by fluidically isolating vertical regions of formations |
Publications (1)
Publication Number | Publication Date |
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US20180187533A1 true US20180187533A1 (en) | 2018-07-05 |
Family
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Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
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US15/399,661 Abandoned US20180187533A1 (en) | 2017-01-05 | 2017-01-05 | Hydrocarbon production by fluidically isolating vertical regions of formations |
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US (1) | US20180187533A1 (en) |
EP (1) | EP3565949A1 (en) |
CN (1) | CN110249109A (en) |
WO (1) | WO2018129053A1 (en) |
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US6279660B1 (en) * | 1999-08-05 | 2001-08-28 | Cidra Corporation | Apparatus for optimizing production of multi-phase fluid |
US8760657B2 (en) * | 2001-04-11 | 2014-06-24 | Gas Sensing Technology Corp | In-situ detection and analysis of methane in coal bed methane formations with spectrometers |
US20080257544A1 (en) * | 2007-04-19 | 2008-10-23 | Baker Hughes Incorporated | System and Method for Crossflow Detection and Intervention in Production Wellbores |
CN101705810B (en) * | 2009-12-11 | 2012-09-05 | 安东石油技术(集团)有限公司 | Segmented current controlling method of current controlling filter pipe column of oil-gas well having perforated pipe |
US20130245952A1 (en) * | 2012-01-13 | 2013-09-19 | University Of Southern California | System and method for characterizing a flow property of a production well site in a reservoir |
US9359883B2 (en) * | 2013-07-22 | 2016-06-07 | Schlumberger Technology Corporation | Zonal compositional production rates in commingled gas wells |
US9828840B2 (en) * | 2013-09-20 | 2017-11-28 | Statoil Gulf Services LLC | Producing hydrocarbons |
US10934811B2 (en) * | 2014-08-22 | 2021-03-02 | Chevron U.S.A. Inc. | Flooding analysis tool and method thereof |
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- 2017-01-05 US US15/399,661 patent/US20180187533A1/en not_active Abandoned
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- 2018-01-03 WO PCT/US2018/012197 patent/WO2018129053A1/en unknown
- 2018-01-03 EP EP18701613.4A patent/EP3565949A1/en not_active Withdrawn
- 2018-01-03 CN CN201880008765.6A patent/CN110249109A/en active Pending
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CN110249109A (en) | 2019-09-17 |
EP3565949A1 (en) | 2019-11-13 |
WO2018129053A1 (en) | 2018-07-12 |
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