US20140182834A1

US20140182834A1 - System for developing high pressure shale or tight rock formations using a profusion of open hole sinusoidal laterals

Info

Publication number: US20140182834A1
Application number: US13/732,994
Authority: US
Inventors: Tim Maloney
Original assignee: Era Exploration LLC
Current assignee: Era Exploration LLC
Priority date: 2013-01-02
Filing date: 2013-01-02
Publication date: 2014-07-03
Also published as: WO2014107475A1

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.

Description

TECHNICAL FIELD OF THE INVENTION

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

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.
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.
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.
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.
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.
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.
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

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.
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.
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.
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.
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.
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

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:

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.

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.

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.

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.

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.

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

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.
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.
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.
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.
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.
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.
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.
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.

Claims

What is claimed is:

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).