U.S. patent application number 13/732994 was filed with the patent office on 2014-07-03 for system for developing high pressure shale or tight rock formations using a profusion of open hole sinusoidal laterals.
This patent application is currently assigned to Era Exploration LLC. The applicant listed for this patent is Tim Maloney. Invention is credited to Tim Maloney.
Application Number | 20140182834 13/732994 |
Document ID | / |
Family ID | 51015824 |
Filed Date | 2014-07-03 |
United States Patent
Application |
20140182834 |
Kind Code |
A1 |
Maloney; Tim |
July 3, 2014 |
System for developing high pressure shale or tight rock formations
using a profusion of open hole sinusoidal laterals
Abstract
A wellbore system to produce natural gas and/or oil from high
pressure shale or tight rock formations using a profusion of open
hole sinusoidal laterals to achieve comparable contact surface
areas with multi-stage hydraulically fractured wellbores. The
laterals are drilled in an orientation designed to intersect the
dominant natural fracture system and are also drilled in a
sinusoidal pattern to interconnect the individual rock facies
within the targeted subterranean zone. The sequence of lateral
drilling is toe to heel, with the open hole kickoff in the downward
direction to facilitate easy re-entry upon drill string tripping.
By drilling enough laterals to achieve comparable contact surface
area with hydraulically fractured wells, the subject invention
allows for comparable quantities of natural gas and/or oil to be
produced from high pressure shale or tight rock formations at
significantly lower capital cost.
Inventors: |
Maloney; Tim; (Houston,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Maloney; Tim |
Houston |
TX |
US |
|
|
Assignee: |
Era Exploration LLC
Houston
TX
|
Family ID: |
51015824 |
Appl. No.: |
13/732994 |
Filed: |
January 2, 2013 |
Current U.S.
Class: |
166/50 |
Current CPC
Class: |
E21B 43/305
20130101 |
Class at
Publication: |
166/50 |
International
Class: |
E21B 43/00 20060101
E21B043/00 |
Claims
1. A wellbore system for surface production of natural gas and/or
oil from a subterranean zone, comprising: a) a cased wellbore that
begins on the surface and lands in the subterranean zone, and then
continues to transverse the zone with a main wellbore; b) a
profusion of sinusoidal laterals drilled off the main wellbore that
provide a total contact surface area, between rock and wellbore,
comparable to multi-stage hydraulically fractured well systems; c)
production of commercial quantities of natural gas and/or oil
comparable to hydraulically fractured well systems; d) cost of
construction lower than comparable hydraulically fractured well
systems; and e) wherein the subterranean zone comprises shale
and/or tight rock beds with natural gas and/or oil present.
2. The wellbore system of claim 1, wherein the main wellbore is an
open hole wellbore, with no casing or liner, through the
subterranean zone.
3. The wellbore system of claim 1, wherein the laterals are open
hole wellbores drilled off the main wellbore, each in the direction
of a targeted volume of rock within the overall subterranean
zone.
4. The wellbore system of claim 3, wherein the laterals are spaced
from 50' to 500' apart, with the potential of 200 laterals drilled
along a 9000' main wellbore.
5. The wellbore system of claim 3, wherein each lateral is of 500'
to 2000' in length.
6. The wellbore system of claim 3, wherein the laterals are drilled
in succession from toe to heel along the main wellbore.
7. The wellbore system of claim 3, wherein each lateral is kicked
off in a downward direction to enable easy access to the lateral in
subsequent trips and re-entries.
8. The wellbore system of claim 3, wherein the laterals are drilled
with a non-damaging mud system to minimize the reduced permeability
observed with water based drilling and fracturing systems.
9. The wellbore system of claim 3, wherein once each lateral is
drilled to total depth, then the drilling mud is circulated out
with weighted completion fluid before proceeding to next lateral
drilling operation.
10. The wellbore system of claim 1, wherein each lateral is drilled
in a sinusoidal path to optimize its contact surface area in the
vertical dimension within the overall subterranean zone.
11. The wellbore system of claim 10, wherein the degree of
sinusoidal drilling is dictated by the level of vertical interlayer
communication as determined by whole core analysis and other
methods.
12. A wellbore system of claim 1, wherein the laterals are drilled
in an orientation to intersect the dominant nature fractures in the
targeted subterranean zone.
13. A wellbore system of claim 12, wherein the direction of the
dominant fracture system is determined by wellbore petrophysical
techniques and other methods.
14. A wellbore system of claim 1, wherein the original reservoir
pressure is high (at or above hydrostatic pressure).
Description
TECHNICAL FIELD OF THE INVENTION
[0001] The present invention relates generally to the recovery of
subterranean resources, and more particularly to a method and
system for enabling commercial production of high pressure natural
gas, condensate or oil from tight subterranean zones without the
use of hydraulic fracturing.
BACKGROUND OF THE INVENTION
[0002] Subterranean deposits of shale or tight rock that contain
high pressure natural gas or oil usually require hydraulic
fracturing to create sufficient `contact surface area` and flow
paths to enable production of commercial quantities of
hydrocarbons. While the hydraulic fracturing method of completing
wells in high pressure shale or tight rock formations is
commonplace in many subterranean deposits, it is very capital
intensive and requires copious amounts of water and proppant.
[0003] The `contact surface area` of hydraulically fractured wells
is calculated by multiplying the `frac height` by `frac length` by
`number of frac stages` completed along the main wellbore. The frac
height is limited to the subterranean zone height, even if the
fracture extends into adjacent layers above or below the
hydrocarbon bearing zone. Frac length can be measured by
microseismic monitoring of fracture treatments. Whereas, the
`contact surface area` of multilateral wells is similarly
calculated by multiplying `effective wellbore height` by `lateral
length` by `number of laterals`. The effective wellbore height is
somewhat difficult to measure precisely because it needs to account
for near wellbore effects, including drilling stress fractures. So,
while the actual hole size is usually 0.5 feet, the effective
height of the wellbore can be 1-2 feet. Hence, a low cost solution
to yield comparable contact surface areas as with hydraulic
fracturing would be advantageous in the development of high
pressure shale or tight rock formations.
[0004] The main problem in producing natural gas and/or oil from
shale and tight rock is the extremely low permeability of the rock,
which, until now, required hydraulic fracturing to create
sufficient contact surface area for the hydrocarbons to flow from
the surrounding rock into the wellbore where it flows, or is
pumped, up to the surface facilities. Often the wells, either
vertical or horizontal, are hydraulically fractured in multiple
stages, with each stage creating separate fractures along the
wellbore through the use of downhole pressure isolation equipment.
Without hydraulic fracturing the contact surface area between the
rock and the wellbore is insufficient to flow commercial quantities
of hydrocarbons. Even very long horizontal wells, drilled within
the shale or rock beds themselves, have insufficient contact
surface area without the additional step of hydraulic fracturing.
For example, a well in the Bakken oil shale play in North Dakota
has a main horizontal wellbore within the target zone of
approximately 9000' in length. Without hydraulic fracturing this
unstimulated well will only produce about 50 barrels of oil per day
over the first year. However, after stimulating the well with 30
separate hydraulic fracture stages along this 9000' long wellbore
the well will produce approximately 500 barrels of oil per day over
the first year. The hydraulic fracturing cost is about half the
well cost, or about $5 million of the total $10 million well cost.
So, while the incremental $5 million is worthwhile given the
increase in production from 50 to 500 barrels of oil per day, a
lower cost solution that achieves comparable contact surface area
(and flow rates) to the hydraulic fracturing method would be
advantageous.
[0005] Another problem in hydraulically fracturing shale or tight
rock is that the water needed to fracture the rock causes a
`reduced relative permeability` effect in the rock matrix, and thus
inhibits the flow rate of natural gas and oil. While the benefits
of increased contact surface area from the induced fracture network
outweigh this reduced permeability effect, methods of increasing
the contact surface area without exposing the rock to water would
improve the flow rates, both initially and over time. Some
operators have conducted hydraulic fracturing with non-water based
systems, though these are even more expensive than the water based
fracs. Hence, a low cost solution that achieves the required
contact surface area without exposing the sediment to water would
be advantageous.
[0006] Another problem with hydraulically fractured wells in shale
or tight rock is the `reduced conduit flow capacity` effect
resulting from fracture closure and proppant embedment after the
well has produced for a while and the overburden pressure causes
proppant crushing and/or sediment deformation around the proppant.
Typical hydraulically fractured wells experience a steep decline in
gas or oil flow rates, upwards of 80% loss in productivity, in just
the first year. The decline continues into the second year and
begins to level out in subsequent years.
[0007] This decline in production flow is the result of depletion
of pore pressure in the rock surrounding the main wellbore and
fracture conduits. Fracture closure accelerates this decline due to
the reduction of flow capacity in these conduits and thus reduces
the effective contact surface area available to flow into the main
wellbore and up to the surface. Operators counteract this fracture
closure problem with high strength proppant materials and high
concentrations of proppant in the frac fluid. Both these solutions
drive up the cost of hydraulic fracturing. Hence, a low cost
solution that maintains high flow capacity conduits from the rock
to the main wellbore throughout the entire well life would be
advantageous.
[0008] Another challenge with wells in shale or tight rock is to
drill the main wellbore in the precise sediment bed (within the
larger shale or tight rock zone) that is best suited for the
subsequent hydraulic fracturing step. This target sediment bed may
only be a 5' thick, whereas the entire shale or tight rock zone may
be 50' thick or more. The target sediment bed will often have
properties such as: slightly better permeability, natural fractures
and/or proper brittlement (to assist fracture initiation). In
addition, wells that will be hydraulically fractured need to stay
well clear of the top and bottom layers of the shale or tight rock
zone in order to avoid fracturing out of zone. Thus, these wells
must be drilled within a narrow directional window, which further
drives up the cost of the well. Each and every shale or tight rock
subterranean deposit has its own unique rock facies, and therefore,
the placement of the main wellbore is optimized within this rock
package to facilitate the subsequent hydraulic fracturing step.
Similarly, any alternative method must also determine and target
the optimum wellbore trajectories to maximize the contact surface
area within the entire shale or tight rock zone. Hence, a solution
that can achieve the contact surface area without requiring the
very narrow directional drilling window would be advantageous.
SUMMARY OF THE INVENTION
[0009] The present invention provides a method and system for
surface production of natural gas, condensate and/or oil from
subterranean resources that reduces the disadvantages and problems
associated with previous systems, especially hydraulic fracturing.
In a particular embodiment, natural gas and/or oil are produced
from a shale or tight rock formation through a profusion of medium
length lateral well bores, all drilled laterally from the main
wellbore, in order to increase the total contact surface area
between the rock and wellbores to enable commercial quantities of
hydrocarbons to be produced.
[0010] Technical advantages of the present invention include
providing comparable contact surface area to hydraulically
fractured wells. In accordance with one embodiment of the present
invention, a method and system for surface production of gas and/or
oil from a subterranean zone includes drilling 100 medium length
laterals (1200' each) from one main wellbore (9000' long). This
well has a total contact surface area between rock and wellbore of
approximately 240,000 square feet. By comparison, a comparable
multistage frac well with 30 stages along a 9000' long horizontal
well, with a zone height of 50' and frac lengths of 150' each,
would have a total contact surface area between rock and wellbore
of 225,000 square feet. Hence, the 100 medium laterals achieve
comparable contact surface area to the 30 hydraulic fracture
stages, and, therefore, produce comparable quantities of natural
gas and oil.
[0011] In addition, the cost to drill 100 short laterals would be
approximately $2 million, assuming one rig-day per lateral, whereas
the 30 stage hydraulic fracturing would cost approximately $5
million. Thus, the present invention provides a method and system
to produce comparable quantities of natural gas and oil to the
hydraulically fractured well, but at a significantly lower capital
cost.
[0012] Another technical advantage of the present invention
includes the option to drill and complete the well with non-water
based drilling and completions fluids. This eliminates the `reduced
relative permeability` effect water has on the rock matrix, thus
maximizing the rock's capacity to flow gas and/or oil. Two examples
of non-water based drilling fluids include oil-based drilling mud
and foam drilling systems. The secondary technical advantage of not
using water in the drilling and/or completion of the well is that
the well will not produce as much water over the life of the well,
which reduces the size and complexity of the surface
facilities.
[0013] Another technical advantage of the present invention is to
eliminate the `reduced conduit flow capacity` effect of fracture
closure or proppant embedment. Because the invention achieves the
contact surface area from a profusion of laterals, not
hydraulically fractured conduits, the flow capacity remains
unaffected by production or pressure depletion over time. The
individual lateral wellbores are structurally stable and remain
open throughout the life of the well, thus, no restriction to flow
occurs as it does in hydraulically fractured conduits that
experience fracture closure and/or proppant embedment.
[0014] As with hydraulically fractured wells, the present invention
also requires drilling the well bores in a targeted manner in order
to maximize the contact surface area within the entire shale or
tight rock zone. In accordance with one embodiment of the present
invention, a method to achieve this optimum contact area includes
drilling each lateral in a sinusoidal trajectory to intersect each
of the individual rock facies several times during the course of
the lateral length. This method of drilling sinusoidal horizontal
laterals is easier to execute than adhering to a very narrow
directional drilling window required by targeting a specific
sediment bed within the larger shale or tight rock zone.
BRIEF DESCRIPTION OF THE FIGURES
[0015] For a more complete understanding of the present invention
and its advantages, reference is now made to the following
description taken in conjunction with the accompanying drawings,
wherein like numerals represent like parts, in which:
[0016] FIG. 1 is a perspective view illustrating the overall
surface and subterranean positioning of one embodiment of the
present invention showing one well with 40 medium length laterals,
placed within a single shale or tight rock zone.
[0017] FIG. 2 has a top and side view of the shale or tight rock
zone with diagrammatic representations of the targeted rock volume
of each lateral show in shaded areas.
[0018] FIG. 3 is a cross sectional view of just the lower
subterranean section of one well with a single lateral exiting from
the bottom of the main wellbore and then following its own path
within the zone.
[0019] FIG. 4 is stereographic view of a typical borehole `poles of
natural fracture planes` showing the areal orientation of primary
natural fractures and the ideal placement of laterals to intersect
them.
[0020] FIG. 5 is a sectional view of a typical shale or tight rock
subterranean zone with the complex sub-facies and natural
fracturing within and across these small bed members.
[0021] FIGS. 6, 7, 8 and 9 are top views of alternative
diagrammatic representations of the development pattern for
different overall unit sizes and main wellbore orientations.
DESCRIPTION OF A PREFERRED EMBODIMENT
[0022] Referring to FIGS. 1, 2 and 3, there is shown a development
system comprising a cased wellbore 1 connecting the surface
facilities 8 to the lowest casing shoe 2. After the casing shoe the
well continues on a path within the shale or tight rock zone 3 as
an open hole wellbore 4. This main wellbore 4 usually extends the
full length of the targeted shale or tight rock zone. The laterals
6 exit the main wellbore at an open hole kickoff point 5 where the
path moves away from the main wellbore. This lateral is drilled in
a direction to establish an effective contact surface area in a
targeted volume within the shale or tight rock zone.
[0023] As shown in FIG. 2, each lateral targets a volume 7 that
will be penetrated in such a direction, both areal and vertical, to
optimize the contact surface area within that volume. In essence,
the laterals are acting like the individual stages of a multi stage
hydraulically fractured well, but instead of creating the contact
surface area by many propped fractures extending away from the main
bore, it is created by many laterals extending away from the main
wellbore. The degree of sinusoidal drilling in each lateral will
vary by shale or tight rock type, depending on the overall
thickness of the zone, the heterogeneity of the rock facies and the
concentration of naturally occurring fractures. In one embodiment,
as shown in FIG. 3, the lateral 6 is highly sinusoidal to ensure
contact with all sub-facies within the overall shale or tight rock
zone.
[0024] As shown in FIG. 3, the kickoff point 5 is drilled downward
from the main bore before beginning to follow the path needed to
develop the targeted volume. This downward kickoff direction is
important in the overall drilling of the well. The sequence will
begin with drilling the main wellbore the full length of shale or
tight rock zone. Then a lateral will be drilled at the most distant
position near the toe of the wellbore. By dropping downward
initially, this lateral can then be easily re-entered during any
drill string tripping operations. That is, when the drill string is
pulled from the well to repair any downhole equipment, and then
rerun to continue in the first lateral, the downward angle will
make it easy to re-entry the correct lateral. Therefore, the
laterals are drilled in sequence from toe to heel.
[0025] As each lateral is drilled to its target final depth, before
the drill string is removed to commence the next lateral operation,
the drilling mud in the lateral is replaced with a weighted
completion fluid by circulating this from the surface drilling rig
down the drill string and around the drill bit into the annular
space. The drill string is pulled from this lateral, leaving it
full of the weighted completion fluid, which will hold back the
natural gas and/oil from flowing into the lateral during the
continued drilling operation.
[0026] Once all the laterals are drilled, each full of weighted
completion fluid, the well is ready for putting on production. No
additional casing or liners need to be installed in the well. The
main wellbore and laterals remain as open hole bores. No hydraulic
fracturing is performed. The drilling mud in the vertical wellbore
is circulated out of the well with a light weight completion fluid
so that the well can then begin to flow. Once most of the weighted
completion fluid has flowed or been circulated out of the well it
will begin to produce natural gas and/or oil to the surface
facilities 8.
[0027] Referring to FIGS. 4-9, there are several factors that go
into the specifics of this wellbore system, in terms of wellbore
geometry and development patterns. With regard to the cardinal
direction of the laterals, as shown in FIG. 4, once the dominant
direction of natural fractures 10 are determined by borehole
fracture measurements 9, then the ideal orientation of the laterals
can be planned to maximize the frequency of intersection with these
natural vertical fractures. The wellbore plan view 11 (from FIG. 2)
is overlain on the stereographic plot to show the ideal orientation
of the main wellbore and laterals to cut across the dominant
natural fractures.
[0028] As shown in FIG. 5, the target subterranean zones are
actually composed of finely laminated and complex rock facies, as
depicted by this typical shale or tight rock sectional view. The
laterals 6 will be drilled in a sinusoidal path to create contact
surface area through a majority of the individual rock facies
within the subterranean zone. The degree of vertical communication
between the individual layers due to natural fractures and rock
porosity will determine the extent of sinusoidal drilling required.
That is, in rock facies with high levels of interlayer
communication the sinusoidal pattern will be subtle. On the other
hand, where there is poor vertical communication, the sinusoidal
pattern will be intense. There are three levels of natural
fractures: bed contained fractures 12, cross-bed fractures 13, and
fracture corridors 14. The level of interlayer communication is
determined by whole core analysis and other methods. Each
subterranean zone will be different, but the general pattern will
be to use the sinusoidal drilling technique to optimize the
vertical contact surface area within the target zone.
[0029] As shown in FIGS. 6-9, the development pattern can be
adjusted to meet alternate development areas and main wellbore
orientations. FIG. 6 shows a development pattern with three
separate wellbores adjacent to each other. This pattern would be
suited to developing spacing units of 1 mile by 2 miles in
dimension. Alternatively, the same sized spacing unit could be
developed with long laterals from one main wellbore as depicted in
FIG. 7. FIGS. 8 and 9 show patterns for developing 1 mile by 1 mile
sections, either in the east-west main wellbore orientation, FIG.
8, or a NW-SE main wellbore orientation, FIG. 9.
* * * * *