US20150096748A1 - Systems and methods for enhancing steam distribution and production in sagd operations - Google Patents
Systems and methods for enhancing steam distribution and production in sagd operations Download PDFInfo
- Publication number
- US20150096748A1 US20150096748A1 US14/508,789 US201414508789A US2015096748A1 US 20150096748 A1 US20150096748 A1 US 20150096748A1 US 201414508789 A US201414508789 A US 201414508789A US 2015096748 A1 US2015096748 A1 US 2015096748A1
- Authority
- US
- United States
- Prior art keywords
- steam
- injection well
- layer
- steam injection
- unconsolidated
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Abandoned
Links
Images
Classifications
-
- 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
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
- E21B43/2406—Steam assisted gravity drainage [SAGD]
-
- 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
- E21B43/02—Subsoil filtering
- E21B43/08—Screens or liners
- E21B43/086—Screens with preformed openings, e.g. slotted liners
-
- 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
- E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
-
- 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
- E21B43/30—Specific pattern of wells, e.g. optimizing the spacing of wells
- E21B43/305—Specific pattern of wells, e.g. optimizing the spacing of wells comprising at least one inclined or horizontal well
-
- 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
- E21B7/00—Special methods or apparatus for drilling
Abstract
A system for recovering hydrocarbons from a subterranean formation with steam-assisted gravity drainage (SAGD) includes a steam injection well. The steam injection well includes a first portion extending from the surface through an unconsolidated layer of the formation to a consolidated layer of the formation, a second portion extending horizontally through the consolidated layer, and a plurality of third portions extending from the second portion. Each third portion extends upward from the second portion into the unconsolidated layer of the formation and a hydrocarbon reservoir in the unconsolidated layer of the formation. In addition, the system includes a production well. The production well includes a first portion extending from the surface through the unconsolidated and a second portion extending horizontally through the unconsolidated layer. The second portion of the production well is vertically positioned above the second portion of the steam injection well.
Description
- This application claims priority, under 35 U.S.C. §119(e), of Provisional Application No. 61/887,487, filed Oct. 7, 2013, incorporated herein by this reference.
- Not applicable.
- This disclosure relates generally to steam-assisted gravity drainage (SAGD) techniques for producing viscous hydrocarbons from subterranean formations. More particularly, the invention relates to the use of a steam injection well including a horizontal portion extending through a consolidated formation and a plurality of secondary portions extending upward from the horizontal portion into an unconsolidated formation containing a hydrocarbon reservoir to enhance steam distribution and associated production.
- As existing reserves of conventional light liquid hydrocarbons (e.g., light crude oil) are depleted and prices for hydrocarbon products continue to rise, there is a push to find new sources of hydrocarbons. Viscous hydrocarbons such as heavy oil and bitumen offer an alternative source of hydrocarbons with extensive deposits throughout the world. In general, hydrocarbons having an API gravity less than 22° are referred to as “heavy oil” and hydrocarbons having an API gravity less than 10° are referred to as “bitumen.” Although recovery of heavy oil and bitumen present challenges due to their relatively high viscosities, there are a variety of processes that can be employed to recover such viscous hydrocarbons from underground deposits.
- Many techniques for recovering heavy oil and bitumen utilize thermal energy to heat the hydrocarbons, decrease the viscosity of the hydrocarbons, and mobilize the hydrocarbons within the formation, thereby enabling the extraction and recovery of the hydrocarbons. Accordingly, such production and recovery processes may generally be described as “thermal” techniques. A steam-assisted gravity drainage (SAGD) operation is one thermal technique for recovering viscous hydrocarbons such as bitumen and heavy oil. SAGD operations typically employ two vertically spaced horizontal wells drilled into the formation and through the reservoir of interest. Steam is injected into the formation via the upper well, typically referred to as the “injection well,” to form a steam chamber that extends radially outward and upward from the injection well. Thermal energy from the steam reduces the viscosity of the viscous hydrocarbons in the reservoir, thereby enabling them to flow downward through the formation under the force of gravity. The mobilized hydrocarbons drain into the lower well, typically referred to as the “production well.” The hydrocarbons collected in the production well are produced to the surface with artificial lift techniques.
- These and other needs in the art are addressed in one embodiment by a system for recovering hydrocarbons from a subterranean formation with steam-assisted gravity drainage (SAGD). The formation includes an unconsolidated layer containing a hydrocarbon reservoir and a consolidated layer disposed below the unconsolidated layer. In an embodiment, the system comprises a steam injection well including a first portion extending from the surface through the unconsolidated layer to the consolidated layer, a second portion extending horizontally through the consolidated layer, and a plurality of third portions extending from the second portion. Each third portion extends upward from the second portion into the unconsolidated layer of the formation and the hydrocarbon reservoir. In addition, the system comprises a production well including a first portion extending from the surface through the unconsolidated layer and a second portion extending horizontally through the unconsolidated layer. The second portion of the production well is vertically positioned above the second portion of the steam injection well.
- These and other needs in the art are addressed in another embodiment by a method for producing hydrocarbons from a subterranean formation with steam-assisted gravity drainage (SAGD). The formation includes an unconsolidated layer containing a hydrocarbon reservoir and a consolidated layer disposed below the unconsolidated layer. In an embodiment, the method comprises (a) drilling a first portion of a steam injection well through the consolidated layer of the formation. In addition, the method comprises (b) drilling a plurality of second portions of a steam injection well upward from the first portion of the steam injection well into the unconsolidated layer. Further, the method comprises (c) drilling a first portion of a production well through the unconsolidated layer of the formation.
- These and other needs in the art are addressed in another embodiment by a method for producing hydrocarbons from a subterranean formation with steam-assisted gravity drainage (SAGD). The formation includes an unconsolidated layer containing a hydrocarbon reservoir and a consolidated layer disposed below the unconsolidated layer. In an embodiment, the method comprises (a) flowing steam from the surface through a subterranean steam injection well extending through the unconsolidated layer of the formation and into the consolidated layer of the formation. In addition, the method comprises (b) flowing steam through the steam injection well from the consolidated layer of the formation into the unconsolidated layer of the formation. Further, the method comprises (c) injecting steam from the injection well into the unconsolidated layer of the formation.
- Embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.
- For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:
-
FIG. 1 is a schematic cross-sectional side view of an embodiment of a system in accordance with the principles described herein for producing viscous hydrocarbons from a subterranean formation with steam-assisted gravity drainage techniques; -
FIG. 2 is a schematic cross-sectional end view of the system ofFIG. 1 taken along section 2-2 ofFIG. 1 ; -
FIG. 3 is an enlarged partial side view of a section of the liner disposed in the production well and the injection well ofFIGS. 1 and 2 ; -
FIG. 4 is a schematic cross-sectional side view of the system ofFIG. 1 during SAGD production operations; and -
FIG. 5 is a schematic cross-sectional end view of the system ofFIG. 4 taken along section 5-5 ofFIG. 4 during SAGD production operations. - The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.
- Certain terms are used throughout the following description and claim to refer to particular system components. This document does not intend to distinguish between components that differ in name but not function. Moreover, the drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form, and some details of conventional elements may not be shown in the interest of clarity and conciseness.
- In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . . ” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices, components, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis. Further, reference to “up” or “down” may be made for purposes of description with “up,” “upper,” “upward,” or “above” meaning generally toward or closer to the surface of the earth, and with “down,” “lower,” “downward,” or “below” meaning generally away or further from the surface of the earth. Also, as used herein, terms describing orientations such as but not limited to “horizontal” and “vertical” are not intended to denote or require absolute mathematical or geometrical precision. Accordingly, such terms are to be understood as denoting or requiring substantial precision only (e.g., “substantially horizontal”) unless the context clearly requires otherwise. Moreover, as used herein, the term “consolidated” is used to describe naturally occurring geologic materials and formations that have been lithified (turned to stone) and/or whose particles are stratified (layered), cemented, or firmly packed together (hard rock); and the term “unconsolidated” is used to described naturally occurring geologic materials and formations that have not been lithified, that comprise sediment that is loosely arranged or unstratified (not in layers), and/or whose particles are not cemented together (soft rock).
- Referring now to
FIGS. 1 and 2 , an embodiment of asystem 10 for producing viscous hydrocarbons (e.g., heavy oil and bitumen) from asubterranean formation 100 using steam-assisted gravity drainage (SAGD) techniques is schematically shown. Moving downward from thesurface 5,formation 100 includes an upper layer orregion 101 of consolidated cap rock, an intermediate layer orregion 105 of unconsolidated sedimentary rock (e.g., McMurray sandstone), and a lower layer orregion 106 of consolidated sedimentary rock (e.g., Devonian limestone).Layer 105 of unconsolidated sedimentary rock is porous, thereby enabling the storage of hydrocarbons therein and allowing the flow and percolation of fluids therethrough. In particular,layer 105 contains areservoir 108 of viscous hydrocarbons (reservoir 108 shaded inFIGS. 1 and 2 ).Layers interface 109 information 100.Interface 109 extends substantially horizontally, but is not planar or perfectly horizontal as it includes some upward and downward undulations. - In this embodiment, a
layer 107 of sedimentary rock (e.g., shale) extends horizontally acrossintermediate layer 105 andreservoir 108 therein, thereby dividinglayer 105 andreservoir 108 intoupper portions layers lower portions layers layer 107 is less porous thanintermediate layer 105, and thus, restricts and/or prevents the flow of fluids therethrough. Accordingly,layer 107 may also be described as a “barrier” and/or “fluid impermeable” as it restricts and/or prevents fluid flow betweenportions intermediate layer 105, and restricts and/or prevents fluid flow betweenportions reservoir 108. - Referring still to
FIGS. 1 and 2 ,system 10 mobilizes, collects and produces viscous hydrocarbons inreservoir 108 using SAGD techniques. In this embodiment,system 10 includes an steam injection well 20 extending downward from thesurface 5, a hydrocarbon production well 50 extending downward from thesurface 5, and a plurality of vertical ports orpassages 60 extending throughbarrier 107 betweenportions FIGS. 1 and 4 , production well 50 is represented with a dashed line inFIGS. 1 and 4 , andpassages 60 are represented with dotted lines inFIGS. 1 and 4 . During production operations, steam is injected intointermediate layer 105 through well 20, viscous hydrocarbons inreservoir 108 are mobilized and drain into production well 50, and the hydrocarbons that collect in production well 50 are produced to thesurface 5. Accordingly, wells 20, 30 may also be described as a “SAGD well pair.” As will be described in more detail below,passages 60 allow mobilized hydrocarbons inupper portion 105 a to flow throughbarrier 107 intolower portion 105 b to enhance the drainage of mobilized hydrocarbons fromreservoir 108 into production well 50. - As best shown in
FIG. 1 , injection well 20 includes a plurality of interconnected primary bores orportions primary portion 23. First primary portion 21 extends downward from thesurface 5 intounconsolidated layer 105, secondprimary portion 22 extends laterally from first primary portion 21 throughunconsolidated layer 105, and thirdprimary portion 23 extends laterally from first portion 21 throughconsolidated layer 106. In this embodiment, first primary portion 21 extends vertically from thesurface 5 throughunconsolidated layer 105 toconsolidated layer 106, secondprimary portion 22 extends horizontally throughunconsolidated layer 105, and thirdprimary portion 23 extends horizontally throughconsolidated layer 106. Thus,primary portions portion 22 disposed aboveportion 23. Secondary portions 24 extend upward from thirdprimary portion 23 inconsolidated layer 106 throughinterface 109 and intounconsolidated layer 105. Thus, each secondary portion 24 has afirst end 24 a coupled to thirdprimary portion 23 and asecond end 24 b disposed inunconsolidated layer 105. Although four secondary portions 24 are shown inFIG. 1 , in general, any number of secondary portions (e.g., secondary portions 24) can be provided. - For purposes of clarity and further explanation, the four secondary portions 24 shown in
FIG. 1 are labeled 24-1, 24-2, 24-3, 24-4. Secondary portion 24-3 is represented with a hidden dashed line inFIG. 2 , however, the remaining secondary sections 24-1, 24-2, 24-4, as well aspassages 60, are not shown inFIG. 2 . In this embodiment, a first plurality of secondary portions 24-1, 24-2 extend upward from thirdprimary portion 23 intounconsolidated layer 105 and then horizontally throughunconsolidated layer 105. Thus, each secondary portion 24-1, 24-2 of injection well 20 includes a first section 24-1 a, 24-2 a, respectively, extending generally upward fromportion 23 and thecorresponding end 24 a and a second section 24-1 b, 24-2 b, respectively, extending from first section 24-1 a, 24-2 a, respectively, to thecorresponding end 24 b. Second section 24-1 b of secondary portion 24-1 extends horizontally throughlower portions unconsolidated layer 105 andreservoir 108, respectively, and is vertically disposed betweenprimary portion 22 andbarrier 107. Second section 24-2 b of secondary portion 24-2 extends horizontally throughupper portions unconsolidated layer 105 andreservoir 108, respectively, and is positioned abovebarrier 107. Thus, first section 24-2 a of secondary portion 24-2 extends upward throughbarrier 107, while first section 24-la of secondary portion 24-1 does not extend throughbarrier 107. In addition, in this embodiment, a second plurality of secondary portions 24-3, 24-4 extend upward from corresponding ends 24 a andprimary portion 23 throughlower portions unconsolidated layer 105 andreservoir 108, respectively, andbarrier 107 intoupper portions unconsolidated layer 105 andreservoir 108, respectively. However, in this embodiment, secondary portions 24-3, 24-4 do not include any horizontal sections. - Referring still to
FIG. 1 , each secondary portion 24 of injection well 20 includes avalve 25 atfirst end 24 a (i.e., at the juncture with third primary portion 23). Eachvalve 25 has an open position allowing fluid communication between thirdprimary portion 23 and the corresponding secondary portion 24, and a closed position preventing fluid communication between thirdprimary portion 23 and the corresponding secondary portion 24. As will be described in more detail below,valves 25 can be independently opened or closed to selectively control the flow of steam from thirdprimary portion 23 into one or more secondary portions 24. - Referring now to
FIGS. 1 and 2 , production well 50 includes a first portion 51 extending downward from thesurface 5 intounconsolidated layer 105 and asecond portion 52 extending laterally from first portion 51 throughunconsolidated layer 105. In this embodiment, first portion 51 extends vertically from thesurface 5 throughunconsolidated layer 105 to a depthproximal interface 109, andsecond portion 52 extends horizontally throughunconsolidated layer 105proximal interface 109. In particular,second portion 52 of production well 50 is positioned inunconsolidated layer 105 at a minimum height or vertical distance D52 frominterface 109 andconsolidated layer 106. In other words, at the closest proximity betweensecond portion 52 andconsolidated layer 106,second portion 52 is vertically spaced aboveconsolidated layer 106 by distance D52. To maximize the quantity of mobilized hydrocarbons received by production well 50 and produced to thesurface 5, distance D52 is preferably as small as possible. In other words,second portion 52 is preferably positioned withinunconsolidated layer 105 as close as possible toconsolidated layer 106. More specifically, distance D52 is preferably less than 5.0 m, more preferably less than 3.0 m, and even more preferably about 1.0 m. - As shown in
FIG. 1 ,horizontal portions portions portion 22 disposed aboveportion 52, which is disposed aboveportion 23. Althoughportions reservoir 108,barrier 107, andinterface 109, eachportion Horizontal portion 22 of injection well 20 is vertically spaced abovehorizontal portion 52 of production well 50 by a vertical distance D22-52 preferably less than 10.0 m, and more preferably less than or equal to 5.0 m. Each portion and section of wells 20, 50 preferably has a diameter between 4.0 and 12.0 in., and more preferably about 7.0 in. - As best shown in
FIG. 2 , in this embodiment,horizontal portions horizontal portion 52 of production well 50 are parallel and vertically arranged one-above-the-other. In particular, the longitudinal axes ofportions portions portions portion 52 of production well 50) can be laterally offset relative to one or more of the others. First sections 24-1 a, 24-2 a, 24-3 a, 24-4 a of secondary portions 24 extend upward fromprimary portion 23 and pass laterallyadjacent portions 21, 52, and thus, do not intersect eitherportion 21, 52. Moreover, those secondary portions 24 that cross in side view (FIG. 1 ), such as secondary portions 24-1, 24-2, secondary portions 24-1, 24-3, and secondary portions 21-4, 24-4 pass laterally adjacent each other and do not intersect. - Referring to
FIG. 1 , eachpassage 60 extends vertically throughbarrier 107 and has a first orupper end 60 a disposed abovebarrier 107 inupper portion 105 a ofunconsolidated layer 105 and a second orlower end 60 b disposed belowbarrier 107 inlower portion 105 b ofunconsolidated layer 105. In this embodiment,passages 60 are coextensive, parallel, and arranged laterally side-by-side in a row extending parallel tohorizontal portions passages 60 lie in vertical plane V1, and, thus,passage 60 are positioned vertically in-line withhorizontal portions - Each
passage 60 is spaced from eachadjacent passage 60 by a horizontal distance D60-60 preferably between 5.0 and 50.0 m. In addition, eachpassage 60 has a diameter preferably between 3.5 and 12.0 in. Still further, eachpassage 60 extends to a distance D60 measured vertically upward frombarrier 107 toupper end 60 a. Each distance D60 is preferably 1.0 to 5.0 m.Passages 60 are spaced from wells 20, 50 and do not intersection any portion or section of wells 20, 50. - In general,
unconsolidated layer 105 is less stable (i.e., more prone to collapse) thanconsolidated layers barrier 107. Accordingly, at least the portions of wells 20, 50 andpassages 60 extending throughunconsolidated layer 105 are preferably lined or cased to maintain and ensure integrity. As will be described in more detail below, steam injection well 20 transports steam downhole from thesurface 5 and injects the steam intounconsolidated layer 105 to transfer thermal energy to and mobilize the viscous hydrocarbons inreservoir 108, and production well 50 receives and collects the mobilized hydrocarbons that drain/flow downward throughunconsolidated layer 105 under the force of gravity. The mobilized hydrocarbons collected in production well 50 are then produced to thesurface 5. Accordingly, the portions of injection well 20 designed to inject steam intounconsolidated layer 105, and the portion of production well 50 designed to receive and collect mobilized hydrocarbons fromunconsolidated layer 105 are preferably lined with a slotted or perforated liner that allows fluid communication betweenlayer 105 and the inside of well 20, 50. However, the portions of injection well 20 that are not designed to inject steam intoformation 100, and the portions of production well 50 that are not designed to receive or collect mobilized hydrocarbons fromlayer 105 are preferably cased (i.e., lined with a solid tubular that does not include any slots or perforations). In this embodiment, primary portion 21 and sections 24-1 a, 24-2 a of secondary portions 24-1, 24-2, respectively, of injection well 20, and portion 51 of production well 50 are lined withcasing 70; andprimary portion 22, secondary portions 24-3, 24-4, and sections 24-1 b, 24-2 b of secondary portions 24-1, 24-2, respectively, of injection well 20, andhorizontal portion 52 of production well 50 are lined with slottedliners 71.Primary portion 23 of injection well 20 extends throughconsolidated layer 106, which is generally stable and fluid impermeable. Thus,primary portion 23 can be lined with casing (e.g., casing 70), a slotted liner (e.g., liner 71), or left unlined (i.e., without casing 70 and liner 71). - As will be described in more detail below,
passages 60 receive the mobilized hydrocarbons that drain/flow through downward throughupper portion 105 a under the force of gravity, flow the mobilized hydrocarbons downward throughbarrier 107, and release the mobilized hydrocarbons intolower portion 105 b. Accordingly, eachpassage 60 is lined with a slottedliner 71 that extends between ends 60 a, 60 b and allows fluid communication betweenportions unconsolidated layer 105 and the inside of thecorresponding passage 60. In general, the upper and lower ends ofliners 71 inpassages 60 disposed at ends 60 a, 60 b, respectively, can be open or closed. In this embodiment, the ends ofliners 71 inpassages 60 are open to allow fluid flow through ends 60 a, 60 b. - As best shown in
FIG. 3 , one slottedliner 71 is shown it being understood that each slottedliner 71 is configured similarly. Each slottedliner 71 includes a plurality of uniformly circumferential and axially spaced holes ofslots 72. In general,slots 72 may be limited to specific locations along eachliner 71. In this embodiment,slots 72 are provided along the entire length of eachliner 71 disposed inhorizontal portions passages 60. Thus,liners 71 disposed inhorizontal portions slots 72 along their entire lengths;liners 71 disposed in horizontal sections 24-1 b, 24-2 b of secondary portions 24-1, 24-2, respectively, includeslots 72 along their entire lengths;liners 71 disposed in secondary portions 24-3, 24-4 includeslots 72 along their entire lengths; andliners 71 disposed inpassages 60 includeslots 72 along their entire lengths. Eachliner 71 extending through barrier 107 (i.e.,liners 71 disposed inpassages 60 andliners 71 disposed in secondary portions 24-3, 24-4) includes a plurality ofslots 72 positioned immediately abovebarrier 107 and a plurality ofslots 72 are positioned immediately belowbarrier 107. - Referring still to
FIG. 1 , in general,system 10 can be constructed by forming wells 20, 50, andpassages 60 in any desired sequence or in parallel, and further, wells 20, 50 andpassages 60 can be formed by any suitable means known in the art. Due to the various deviations in wells 20, 50, wells 20, 50 are formed via directional drilling techniques. In this embodiment, injection well 20 is formed before production well 50 as formation of secondary portions 24 of injection well 20 facilitate the desired positioning ofsecond portion 52 of production well 50 inunconsolidated layer 105 as close as possible to interface 109 (i.e., at distance D52). In particular, primary portion 21 is drilled from thesurface 5 to the desired depth information 100, and then,primary portions unconsolidated layer 105 andconsolidated layer 106, respectively. Next, secondary portions 24 are drilled fromprimary portion 23 intounconsolidated layer 105—secondary portion 24-1 is not drilled throughbarrier 107, while secondary portions 24-2, 24-3, 24-4 are drilled throughbarrier 107.Casing 70 andliners 71 can be run into injection well 20 during or after drilling well 20. - As shown in
FIG. 1 , secondary portions 24cross interface 109, and thus, logging data acquired while drilling secondary portions 24 is used to map out the position and geometry ofinterface 109. By better understanding the actual location of interface 109 (via the drilling logs) prior to forminghorizontal portion 52 of injection well 50,horizontal portion 52 can be positioned withinunconsolidated layer 105 closer to interface 109 with greater confidence. - After formation of injection well 20 and identification of the location of
interface 109 via drilling logs, injection well 50 is formed. In particular, first portion 51 is drilled from thesurface 5 to the desired depth information 100, and then,second portion 52 is drilled laterally from first portion 51 throughunconsolidated layer 105. As previously described, mapping out the actual location ofinterface 109 via drilling logs from the drilling of secondary portions 24 of injection well 20,horizontal portion 52 can be positioned (with confidence) withinunconsolidated layer 105 much closer to interface 109 than if the actual position ofinterface 109 was not mapped out and is estimated solely based on seismic data.Casing 70 andliners 71 can be run into production well 50 during or after drilling well 50. - In general,
passages 60 can be formed before, during, or after formation of one or both of wells 20, 50. Further,passages 60 can be formed by drilling downward from thesurface 5 throughbarrier 107 or drilling upward from injection well 20 or production well 50 throughbarrier 107 by any suitable drilling technique known in the art. In either case, the drilled boreholes will have lengths much longer thanpassages 60 shown inFIG. 1 (i.e., the drilled boreholes will extend to thesurface 5, injection well 20, or production well 50). However,liners 71 are run into the drill boreholes and positioned between ends 60 a, 60 b-only those portions of the drilled boreholes that definepassages 60 are lined. Thus, the remaining portions of the drilled boreholes extending throughunconsolidated layer 105 will collapse and close, resulting inpassages 60 having ends 60 a, 60 b defined by the upper and lower ends ofliners 71 disposed therein. - Referring now to
FIGS. 4 and 5 , the operation ofsystem 10 to produce viscous hydrocarbons (e.g., bitumen and/or heavy oil) inreservoir 108 is schematically shown. More specifically, steam is pumped from thesurface 5 through injection well 20 and injected intolayer 105 andreservoir 108 therein. In particular, the steam flows down vertical primary portion 21 and through each horizontalprimary portion horizontal portion 22 is injected intolower portion 105 b of unconsolidated layer 105 (andlower portion 108 b ofreservoir 108 therein) belowbarrier 107 viaslots 72 inliner 71 disposed withinportion 22. The steam and associated hot water injected fromprimary portion 22 percolate throughlower portion 105 b, thereby forming asteam chamber 110 that extends horizontally outward and vertically upward fromportion 22 tobarrier 107. Thus,steam chamber 110 is generally shaped like an inverted triangular prism that extends upward from and along the entire length ofportion 22 of injection well 20.Steam chamber 110 does not extend throughbarrier 107 asbarrier 107 is generally fluid impermeable, and thus, restricts and/or prevents the passage of steam therethrough. - Horizontal
primary portion 23 of injection well 20 is disposed inconsolidated layer 106, which is generally fluid impermeable, and thus, regardless of whetherportion 23 is uncased, cased, or lined with a slotted liner,portion 23 does not inject steam intounconsolidated layer 105 orreservoir 108. Rather,portion 23 transports steam to one or more secondary portions 24, which injects steam intounconsolidated layer 105 andreservoir 108. In particular, steam flows fromprimary portion 23 into each secondary portion 24 with its correspondingvalve 25 in the open position, but is prevented from flowing into each secondary portion 24 with its correspondingvalve 25 in the closed position. Thus, by independently controlling the positions ofvalves 25, steam can be directed to any one or more secondary portions 24 as desired. In addition, by independently controlling the positions ofvalves 25, the volumetric flow rate of steam directed to any one or more secondary portions 24 can be adjusted as desired to target specific areas oflayer 105 andreservoir 108. More specifically, for a given volumetric flow rate of steam intoprimary portion 23, the volumetric flow rate of steam into any one secondary portion 24 can be increased by closing the valve(s) 25 of one or more other secondary portions 24, and decreased by closing the correspondingvalve 25 or opening the valve(s) 25 of one or more other secondary portions 24. In general, the volumetric flow rate of steam flowing into and through a given secondary portion 24 is directly related to the volume of steam injected intounconsolidated layer 105 from that secondary portion 24. Thus, the greater the volumetric flow rate of steam flowing into and through into a given secondary portion 24, the greater the volume of steam injected intounconsolidated layer 105 from that secondary portion 24; and the lower the volumetric flow rate of steam flowing into and through a given secondary portion 24, the lower the volume of steam injected intounconsolidated layer 105 from that secondary portion 24. InFIGS. 4 and 5 ,system 10 is illustrated with eachvalve 25 in the open position, and thus, steam flows fromprimary portion 23 into each secondary portion 24. However, it should be appreciated that any one or more ofvalves 25 can be closed to selectively flow steam into and through one or more secondary portions 24 and/or to adjust the volumetric flow rate of steam into any one or more secondary portions 24. - Referring still to
FIGS. 4 and 5 , as previously described, sections 24-1 a, 24-2 a of secondary portions 24-1, 24-2, respectively, are lined withcasing 70; whereas sections 24-1 b, 24-2 b of secondary portions 24-1, 24-2, respectively, and secondary portions 24-3, 24-4 are lined with slottedliners 71. Thus, steam flowing through horizontal section 24-1 b is injected intolower portion 105 b of unconsolidated layer 105 (andlower portion 108 b ofreservoir 108 therein) belowbarrier 107 viaslots 72 inliner 71 disposed within section 24-1 a; steam flowing through horizontal section 24-2 b is injected intoupper portion 105 a of unconsolidated layer 105 (andupper portion 108 a ofreservoir 108 therein) abovebarrier 107 viaslots 72 inliner 71 disposed within section 24-2 b; steam flowing through secondary portion 24-3 is injected into upper andlower portion lower portions reservoir 108 therein) above and belowbarrier 107, respectively, viaslots 72 inliner 71 disposed within secondary portion 24-3; and steam flowing through secondary portion 24-4 is injected into upper andlower portion lower portions reservoir 108 therein) above and belowbarrier 107, respectively, viaslots 72 inliner 71 disposed within secondary portion 24-4. - The steam and associated hot water injected from section 24-1 b percolate through
lower portion 105 b, thereby forming asteam chamber 111 that extends horizontally outward and vertically upward from section 24-1 b tobarrier 107; and the steam and associated hot water injected from section 24-2 b percolate throughupper portion 105 a, thereby forming asteam chamber 112 that extends horizontally outward and vertically upward from section 24-2 b toconsolidated layer 101. Thus, eachsteam chamber Steam chambers barrier 107 orlayer 101, respectively, asbarrier 107 andlayer 101 are generally fluid impermeable, and thus, restricts and/or prevents the passage of steam therethrough. The steam and associated hot water injected from portion 24-3 intolower portion 105 b percolate throughlower portion 105 b, thereby forming asteam chamber 113 that extends horizontally outward and vertically upward from portion 24-3 tobarrier 107; and the steam and associated hot water injected from portion 24-3 intoupper portion 105 a percolate throughupper portion 105 a, thereby forming asteam chamber 114 that extends horizontally outward and vertically upward from portion 24-3. Thus, steam injected intolayer 105 from secondary portion 24-3 forms twosteam chambers barrier 107; neithersteam chamber barrier 107 asbarrier 107 is generally fluid impermeable.Steam chamber 113 has a generally conical shape, andsteam chamber 114 has a generally dome or hemispherical shape. Similarly, the steam and associated hot water injected from portion 24-4 intolower portion 105 b percolate throughlower portion 105 b, thereby forming asteam chamber 115 that extends horizontally outward and vertically upward from portion 24-4 tobarrier 107; and the steam and associated hot water injected from portion 24-4 intoupper portion 105 a percolate throughupper portion 105 a, thereby forming asteam chamber 116 that extends horizontally outward and vertically upward from portion 24-4. Thus, steam injected intolayer 105 from secondary portion 24-4 forms twosteam chambers barrier 107; neithersteam chamber barrier 107 asbarrier 107 is generally fluid impermeable.Steam chamber 115 has a generally conical shape, andsteam chamber 116 has a generally dome or hemispherical shape.Steam chambers FIG. 4 ; andsteam chambers FIG. 5 (steam chambers FIG. 5 ). - In the manner described,
primary portion 23 and secondary portions 24 extending therefrom facilitate the distribution of steam withinunconsolidated layer 105 above and belowbarrier 107. In addition, as compared to a conventional injection well having a single horizontal bore for steam injection,primary portion 23 and secondary portions 24 enhance steam distribution inunconsolidated layer 105 by forming a plurality ofsteam chambers lower portion 105 b ofunconsolidated layer 105 belowbarrier 107, and allowing steam to pass throughbarrier 107 to form a plurality ofsteam chambers unconsolidated layer 105 abovebarrier 107. - As best shown in
FIG. 4 , a portion of the steam inchambers passages 60 and slottedliners 71 disposed therein viaslots 72 positioned belowbarrier 107. The steam then flows upward withinpassages 60 andliners 71 throughbarrier 107, and is injected intoupper portion 105 aabove barrier 107 viaslots 72 inliners 71 positioned abovebarrier 107. The steam injected intoupper portion 105 a frompassages 60, as well as associated hot water, percolate throughupper portion 105 aabove barrier 107, thereby forming a plurality ofsteam chambers 117. Eachsteam chamber 117 extends radially/laterally outward and vertically upward from slottedliners 71 extending upward frombarrier 107. Thus, eachsteam chamber 117 has a generally domed or hemispherical shape. In this embodiment,passages 60 are horizontally/laterally spaced sufficiently close together that eachchamber 117 intersects eachadjacent chamber 117, thereby forming acontinuous steam chamber 118 extending throughupper portion 105 aabove barrier 107 generally parallel tochambers Steam chambers FIGS. 4 and 5 (shown in phantom inFIG. 5 ). - In the manner described,
passages 60 extending throughbarrier 107 and slottedliners 71 disposed therein facilitate the distribution of steam withinunconsolidated layer 105 abovebarrier 107. In addition, as compared to a conventional injection well having a single horizontal run for steam injection,passages 60 and slottedliners 71 disposed therein enhance steam distribution inunconsolidated layer 105, allowing steam to pass through and abovebarrier 107 to formsteam chambers upper portion 105 a ofunconsolidated layer 105 abovebarrier 107. - Referring still to
FIGS. 4 and 5 , thermal energy fromsteam chambers upper portion 108 a ofreservoir 108 to a sufficient extent to allow them to flow under the force of gravity downward throughupper portion 105 a ofunconsolidated layer 105.Barrier 107 substantially blocks the continued downward flow of the viscosity-reduced (i.e., mobilized) hydrocarbons inupper portion 105 a. However, the mobilized hydrocarbons inupper portion 105 a flow intopassages 60 and corresponding slottedliners 71 viaslots 72 disposed abovebarrier 107, and then downward throughbarrier 107. The hydrocarbons passing throughbarrier 107exit passages 60 and corresponding slottedliners 71 intolower portion 105 b ofunconsolidated layer 105 viaslots 72 disposed belowbarrier 107. - Thermal energy from
steam chambers lower portion 108 b ofreservoir 108 to a sufficient extent to allow them to flow under the force of gravity downward throughlower portion 105 b ofunconsolidated layer 105. In addition, thermal energy fromsteam chambers hydrocarbons exiting passages 60 and slottedliners 71 disposed therein intolower portion 105 b and allows them to flow under the force of gravity downward throughlower portion 105 b oflayer 105. The mobilized hydrocarbons inlower portion 105 b drain intohorizontal portion 52 of production well 50 viaslots 72 in the slottedliner 71 disposed inportion 52. The hydrocarbons collect in production well 50, and are produced to thesurface 5 via artificial lift (e.g., pumps). - While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.
Claims (29)
1. A system for recovering hydrocarbons from a subterranean formation with steam-assisted gravity drainage (SAGD), the formation including an unconsolidated layer containing a hydrocarbon reservoir and a consolidated layer disposed below the unconsolidated layer, the system comprising:
a steam injection well including a first portion extending from the surface through the unconsolidated layer to the consolidated layer, a second portion extending horizontally through the consolidated layer, and at least one third portion extending from the second portion, wherein each third portion extends upward from the second portion into the unconsolidated layer of the formation and the hydrocarbon reservoir;
a production well including a first portion extending from the surface through the unconsolidated layer and a second portion extending horizontally through the unconsolidated layer, wherein the second portion of the production well is vertically positioned above the second portion of the steam injection well.
2. The system of claim 1 , wherein the second portion of the production well is disposed in the unconsolidated layer proximal the consolidated layer.
3. The system of claim 2 , wherein the second portion of the production well is disposed at a minimum height H measured vertically from an interface between the consolidated layer and the unconsolidated layer, wherein the minimum height H is less than 5.0 meters.
4. The system of claim 3 , wherein the minimum height H is about 1.0 meter.
5. The system of claim 1 , wherein the steam injection well includes a fourth portion extending horizontally through the unconsolidated layer, wherein the fourth portion of the steam injection well is vertically positioned above the second portion of the production well.
6. The system of claim 1 , wherein the formation includes a fluid impermeable barrier disposed within the unconsolidated layer;
wherein an upper portion of the hydrocarbon reservoir is disposed above the fluid impermeable barrier and a lower portion of the hydrocarbon reservoir is disposed below the fluid impermeable barrier;
wherein the second portion of the injection well and the second portion of the production well are positioned below the fluid impermeable barrier;
wherein at least one of the third portions of the steam injection well extends upward through the fluid impermeable barrier and is configured to transport steam from the second portion of the steam injection well to the upper portion of the hydrocarbon reservoir.
7. The system of claim 6 , further comprising a passage extending through the fluid impermeable barrier, wherein the passage has an upper end disposed in the unconsolidated layer above the fluid impermeable barrier and a lower end disposed in the unconsolidated layer below the fluid impermeable barrier.
8. The system of claim 7 , wherein a slotted liner is disposed in the passage and a slotted liner is disposed in each of the third portions of the steam injection well that extend upward through the fluid impermeable barrier.
9. The system of claim 8 , wherein each slotted liner comprises:
a first plurality of slots positioned above the fluid impermeable barrier; and
a second plurality of slots positioned below the fluid impermeable barrier.
10. The system of claim 7 , wherein the passage is configured to transport hydrocarbons from the unconsolidated layer above the fluid impermeable barrier to the unconsolidated layer below the fluid impermeable barrier.
11. The system of claim 10 , wherein the passage is configured to transport steam from the unconsolidated layer below the fluid impermeable barrier to the unconsolidated layer above the fluid impermeable barrier.
12. The system of claim 1 , further comprising a valve disposed along each third portion of the steam injection well proximal the second portion of the steam injection well;
wherein each valve has an open position allowing fluid communication between the second portion of the steam injection well and the corresponding third portion of the steam injection well, and a closed position preventing fluid communication between the second portion of the steam injection well and the corresponding third portion of the steam injection well.
13. A method for producing hydrocarbons from a subterranean formation with steam-assisted gravity drainage (SAGD), the formation including an unconsolidated layer containing a hydrocarbon reservoir and a consolidated layer disposed below the unconsolidated layer, the method comprising:
(a) drilling a first portion of a steam injection well through the consolidated layer of the formation;
(b) drilling a plurality of second portions of a steam injection well upward from the first portion of the steam injection well into the unconsolidated layer;
(c) drilling a first portion of a production well through the unconsolidated layer of the formation.
14. The method of claim 13 , further comprising:
(d) flowing steam through the first portion of the steam injection well to the second portions of the steam injection well;
(e) flowing steam from the first portion of the steam injection well into at least one of the second portions of the steam injection well during (d); and
(f) injecting steam from the at least one of the second portions of the steam injection well into the unconsolidated layer of the formation during (e).
15. The method of claim 14 , further comprising:
(g) reducing the viscosity of the hydrocarbons and flowing the hydrocarbons through the unconsolidated layer into the first portion of the production well; and
(h) producing the hydrocarbons in the first portion of the production well to the surface.
16. The method of claim 14 , further comprising:
selectively preventing the flow of steam from the first portion of the steam injection well into one or more of the second portions of the steam injection well.
17. The method of claim 13 , wherein (b) comprises:
drilling at least one of the second portions of the steam injection well upward through a fluid impermeable barrier extending through the unconsolidated layer of the formation;
wherein an upper portion of the unconsolidated layer is disposed above the fluid impermeable barrier and a lower portion of the unconsolidated layer is disposed below the fluid impermeable barrier;
wherein an upper portion of the hydrocarbon reservoir is disposed above the fluid impermeable barrier and a lower portion of the hydrocarbon reservoir is disposed below the fluid impermeable barrier.
18. The method of claim 17 , further comprising:
drilling a passage through the fluid impermeable barrier.
19. The method of claim 17 , further comprising:
(d) flowing steam through the first portion of the steam injection well to the second portions of the steam injection well;
(e) flowing steam from the first portion of the steam injection well into at least one of the second portions of the steam injection well during (d); and
(f) flowing steam upward in the at least one of the second portions of the steam injection well through the fluid impermeable barrier during (e); and
(g) injecting steam from the at least one of the second portions of the steam injection well into the upper portion of the hydrocarbon reservoir.
20. The method of claim 18 , further comprising:
(d) flowing steam through the first portion of the steam injection well to the second portions of the steam injection well;
(e) flowing steam from the first portion of the steam injection well into at least one of the second portions of the steam injection well during (d); and
(f) flowing steam upward in the at least one of the second portions of the steam injection well through the fluid impermeable barrier during (e);
(g) injecting steam from the at least one of the second portions of the steam injection well into the upper portion of the hydrocarbon reservoir;
(h) flowing hydrocarbons from the upper portion of the hydrocarbon reservoir through the passage into the lower portion of the unconsolidated layer.
21. The method of claim 20 , further comprising:
flowing hydrocarbons from the passage through the lower portion of the unconsolidated layer into the first portion of the production well; and
flowing hydrocarbons through the first portion of the production well to the surface.
22. The method of claim 13 , further comprising:
drilling each second portion of the steam injection well upward across an interface between the consolidated layer and the unconsolidated layer;
identifying a location where each second portion crosses the interface while drilling each second portion;
utilizing the locations where the second portions cross the interface to determine the location of the first portion of the production well within the unconsolidated layer.
23. A method for producing hydrocarbons from a subterranean formation with steam-assisted gravity drainage (SAGD), the formation including an unconsolidated layer containing a hydrocarbon reservoir and a consolidated layer disposed below the unconsolidated layer, the method comprising:
(a) flowing steam from the surface through a subterranean steam injection well extending through the unconsolidated layer of the formation and into the consolidated layer of the formation;
(b) flowing steam through the steam injection well from the consolidated layer of the formation into the unconsolidated layer of the formation; and
(c) injecting steam from the injection well into the unconsolidated layer of the formation.
24. The method of claim 23 , further comprising:
(d) flowing hydrocarbons from the hydrocarbon reservoir into a portion of a production well extending through the unconsolidated layer of the formation; and
(e) producing hydrocarbons in the production well to the surface.
25. The method of claim 24 , wherein a fluid impermeable barrier extends through the unconsolidated layer of the formation and divides the hydrocarbon reservoir into a lower portion disposed below the fluid impermeable barrier and an upper portion disposed above the fluid impermeable barrier;
wherein (b) further comprises flowing steam through the injection well and the fluid impermeable barrier;
wherein (c) further comprises injecting steam from the injection well into the upper portion of the hydrocarbon reservoir.
26. The method of claim 25 , further comprising:
(f) flowing hydrocarbons downward through a passage in the fluid impermeable barrier.
27. The method of claim 23 , wherein the injection well includes a first portion extending horizontally through the consolidated layer of the formation and a plurality of second portions extending from the first portion into the unconsolidated layer of the formation.
28. The method of claim 27 , wherein at least one of the second portions extends through a fluid impermeable barrier in the unconsolidated layer of the formation, wherein the fluid impermeable barrier divides the hydrocarbon reservoir into a lower portion disposed below the fluid impermeable barrier and an upper portion disposed above the fluid impermeable barrier.
29. The method of claim 27 , further comprising:
drilling each second portion from the first portion across an interface between the consolidated layer and the unconsolidated layer;
identifying a location where each second portion crosses the interface while drilling each second portion;
utilizing the locations where each second portion crosses the interface to position a horizontal portion of a production well extending from the surface through the unconsolidated layer of the formation.
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US14/508,789 US20150096748A1 (en) | 2013-10-07 | 2014-10-07 | Systems and methods for enhancing steam distribution and production in sagd operations |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US201361887487P | 2013-10-07 | 2013-10-07 | |
US14/508,789 US20150096748A1 (en) | 2013-10-07 | 2014-10-07 | Systems and methods for enhancing steam distribution and production in sagd operations |
Publications (1)
Publication Number | Publication Date |
---|---|
US20150096748A1 true US20150096748A1 (en) | 2015-04-09 |
Family
ID=51743587
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US14/508,789 Abandoned US20150096748A1 (en) | 2013-10-07 | 2014-10-07 | Systems and methods for enhancing steam distribution and production in sagd operations |
Country Status (2)
Country | Link |
---|---|
US (1) | US20150096748A1 (en) |
WO (1) | WO2015054267A2 (en) |
Cited By (7)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20140345855A1 (en) * | 2013-05-21 | 2014-11-27 | Total E&P Canada, Ltd. | Radial fishbone sagd |
WO2018081511A1 (en) * | 2016-10-28 | 2018-05-03 | Saudi Arabian Oil Company | Wellbore system with lateral wells |
US11193332B2 (en) | 2018-09-13 | 2021-12-07 | Schlumberger Technology Corporation | Slider compensated flexible shaft drilling system |
US11203901B2 (en) | 2017-07-10 | 2021-12-21 | Schlumberger Technology Corporation | Radial drilling link transmission and flex shaft protective cover |
US11466549B2 (en) | 2017-01-04 | 2022-10-11 | Schlumberger Technology Corporation | Reservoir stimulation comprising hydraulic fracturing through extended tunnels |
US11486214B2 (en) | 2017-07-10 | 2022-11-01 | Schlumberger Technology Corporation | Controlled release of hose |
US11840909B2 (en) | 2016-09-12 | 2023-12-12 | Schlumberger Technology Corporation | Attaining access to compromised fractured production regions at an oilfield |
Families Citing this family (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
CN110821462B (en) * | 2019-10-16 | 2022-03-25 | 新疆中凌工程技术有限公司 | Method for drawing tail end of horizontal well group with interlayer in SAGD control well reservoir |
Citations (3)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20050072567A1 (en) * | 2003-10-06 | 2005-04-07 | Steele David Joe | Loop systems and methods of using the same for conveying and distributing thermal energy into a wellbore |
US20070039729A1 (en) * | 2005-07-18 | 2007-02-22 | Oil Sands Underground Mining Corporation | Method of increasing reservoir permeability |
US8240381B2 (en) * | 2009-02-19 | 2012-08-14 | Conocophillips Company | Draining a reservoir with an interbedded layer |
Family Cites Families (3)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
CA2780335A1 (en) * | 2008-11-03 | 2010-05-03 | Laricina Energy Ltd. | Passive heating assisted recovery methods |
CA2651527C (en) * | 2009-01-29 | 2012-12-04 | Imperial Oil Resources Limited | Method and system for enhancing a recovery process employing one or more horizontal wellbores |
CA2684049C (en) * | 2009-10-27 | 2014-07-29 | Suncor Energy Inc. | Infill well methods for sagd well heavy hydrocarbon recovery operations |
-
2014
- 2014-10-07 WO PCT/US2014/059515 patent/WO2015054267A2/en active Application Filing
- 2014-10-07 US US14/508,789 patent/US20150096748A1/en not_active Abandoned
Patent Citations (3)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20050072567A1 (en) * | 2003-10-06 | 2005-04-07 | Steele David Joe | Loop systems and methods of using the same for conveying and distributing thermal energy into a wellbore |
US20070039729A1 (en) * | 2005-07-18 | 2007-02-22 | Oil Sands Underground Mining Corporation | Method of increasing reservoir permeability |
US8240381B2 (en) * | 2009-02-19 | 2012-08-14 | Conocophillips Company | Draining a reservoir with an interbedded layer |
Cited By (8)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20140345855A1 (en) * | 2013-05-21 | 2014-11-27 | Total E&P Canada, Ltd. | Radial fishbone sagd |
US9567842B2 (en) * | 2013-05-21 | 2017-02-14 | Total E&P Canada Ltd | Radial fishbone SAGD |
US11840909B2 (en) | 2016-09-12 | 2023-12-12 | Schlumberger Technology Corporation | Attaining access to compromised fractured production regions at an oilfield |
WO2018081511A1 (en) * | 2016-10-28 | 2018-05-03 | Saudi Arabian Oil Company | Wellbore system with lateral wells |
US11466549B2 (en) | 2017-01-04 | 2022-10-11 | Schlumberger Technology Corporation | Reservoir stimulation comprising hydraulic fracturing through extended tunnels |
US11203901B2 (en) | 2017-07-10 | 2021-12-21 | Schlumberger Technology Corporation | Radial drilling link transmission and flex shaft protective cover |
US11486214B2 (en) | 2017-07-10 | 2022-11-01 | Schlumberger Technology Corporation | Controlled release of hose |
US11193332B2 (en) | 2018-09-13 | 2021-12-07 | Schlumberger Technology Corporation | Slider compensated flexible shaft drilling system |
Also Published As
Publication number | Publication date |
---|---|
WO2015054267A3 (en) | 2015-06-25 |
WO2015054267A2 (en) | 2015-04-16 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
US20150096748A1 (en) | Systems and methods for enhancing steam distribution and production in sagd operations | |
US7451814B2 (en) | System and method for producing fluids from a subterranean formation | |
US8240381B2 (en) | Draining a reservoir with an interbedded layer | |
US7422063B2 (en) | Hydrocarbon recovery from subterranean formations | |
CN106948795A (en) | A kind of method that multi-branched horizontal well closed cycle develops hot water type underground heat | |
US20070175638A1 (en) | Petroleum Extraction from Hydrocarbon Formations | |
CN112392472B (en) | Method and device for determining integrated development mode of shale and adjacent oil layer | |
CN104265242B (en) | The ground thermal extraction method of geothermal well | |
CN104633996B (en) | Water source heat pump recharging technical method | |
Shen | SAGD for heavy oil recovery | |
CN109356560B (en) | In-situ mining method and in-situ mining well pattern | |
US9784082B2 (en) | Lateral wellbore configurations with interbedded layer | |
US10400561B2 (en) | Method for accelerating heavy oil production | |
RU2386804C1 (en) | Method of oil pool development with gas cap and bottom water | |
CA2893170A1 (en) | Thermally induced expansion drive in heavy oil reservoirs | |
US20140076566A1 (en) | Use of Underground Access to Improve Steam Distribution in SAGD Operations | |
US20150345270A1 (en) | Thermally induced expansion drive in heavy oil reservoirs | |
Malik et al. | Steamflood with vertical injectors and horizontal producers in multiple zones | |
Hocking et al. | Single-well SAGD: overcoming permeable lean zones and barriers | |
RU2467161C1 (en) | Thermal well method of developing fractured deposit of extra-heavy oil | |
Guinand et al. | Drilling the first SAGD wells in the Orinoco oil-belt bare field: a case history | |
MX2013001364A (en) | Systems and methods for the improved recovery, applied to reservoirs which crudes have conditions of movement at the bottom. | |
RU2652245C1 (en) | Method for developing the bituminous oil deposit | |
Price et al. | Acordionero Oil Field: From Discovery to Development, Middle Magdalena Basin, Colombia. | |
RU2681758C1 (en) | Method of developing super-viscous oil field |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
AS | Assignment |
Owner name: BP AMERICA INC., TEXAS Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:WEST, CHRISTOPHER C;REEL/FRAME:034171/0469 Effective date: 20141007 |
|
STCB | Information on status: application discontinuation |
Free format text: ABANDONED -- FAILURE TO RESPOND TO AN OFFICE ACTION |