US20090301704A1

US20090301704A1 - Recovery of Hydrocarbons Using Horizontal Wells

Info

Publication number: US20090301704A1
Application number: US12/300,981
Authority: US
Inventors: Peter M. Dillett; Pat R. Perri
Original assignee: Chevron USA Inc
Current assignee: Chevron USA Inc
Priority date: 2006-05-16
Filing date: 2007-05-16
Publication date: 2009-12-10
Also published as: WO2007137061A2; EA200870537A1; CN101484662A; EA018256B1; CA2652159A1; WO2007137061A3; CN101484662B; BRPI0711475A2

Abstract

A method of drilling a wellbore useful for the recovery of hydrocarbons from a subsurface reservoir, penetrated by one or more wellbores previously injected with steam, comprises drilling a wellbore having a substantially horizontal productive portion lying within the subsurface reservoir.

Description

GROSS REFERENCE TO RELATED APPLICATIONS

The present application claims priority under 35 U.S.C. 119 to U.S. Provisional Patent Application No. 60/801,016 filed on May 16, 2006, the entire content of which is hereby incorporated by reference.

BACKGROUND

1. Field of Art
Provided is a method that relates to the recovery of hydrocarbons in subsurface formations, particularly the recovery of heavy oil from reservoirs in which steam fracturing operations have been conducted.
2. Background of the Related Art
Unconventional, heavy oil reserves, such as, for example, Miocene diatomite (Opal A), can be recovered through “steam fracturing”. Steam fracturing takes place through a cyclic process with characteristics that include injection pressures of approximately 1000 psi and temperatures of +/−500-550° F. Commonly assigned U.S. Pat. Nos. 5,085,276 and 5,305,829 disclose process(es) for cyclic steaming that are applicable to diatomite formations. Such processing generally includes:

- Steaming. Injection takes place for 2-3 days (approximately 1000-1500 Barrels of Steam Per Day or BSPD) until a target volume of steam (e.g., 3000-5000 barrels of steam) is achieved. The steam is injected at approximately 1000 psi, which typically serves to exceed the fracture gradient of the subsurface rock, fracture the low-permeability reservoir (5 millidarcy or mD), and create secondary fracture permeability.
- Soak Period. After steaming the well, the well is shut in and “soaked” for approximately 2 days. The high temperature provides necessary viscosity reduction for the 13° API oil and allows the oil to flow more easily. In addition, a process known as imbibition takes place, in which condensed steam vapor is preferentially imbibed by the (hydrophilic) diatomite rock and oil is displaced into fractures and the well bore.
- Production. After “soaking” the well, the well is produced for approximately 20 or more days. The production causes a pressure drop, which induces “flashing” of hot water to steam, which provides lift energy for the fluid column. As a result, the wells flow and do not have to be artificially lifted, as long as the wells are subsequently steamed. Typically, a flowing wellhead configuration is used for cyclic steaming at a heavy oil field. After a well dies, the well is prepared for the next steam job.

SUMMARY

In an embodiment, provided is a method of drilling a wellbore useful for the recovery of hydrocarbons from a subsurface reservoir, the method comprising drilling a wellbore having a substantially horizontal productive portion lying within the subsurface reservoir. The subsurface reservoir is penetrated by one or more wellbores previously injected with steam.
In an embodiment, provided is a method of drilling a wellbore useful for the recovery of hydrocarbons from a subsurface reservoir, the method comprising drilling a wellbore having a substantially horizontal productive portion lying within the subsurface reservoir, drilling one or more substantially vertical wellbores; and perforating the one or more substantially vertical wellbores according to a depth of the substantially horizontal productive portion of the wellbore.

BRIEF DESCRIPTION OF THE FIGURES OF THE DRAWINGS

The appended drawings illustrate typical embodiments and are not to be considered limiting in scope.

FIG. 1 shows a cross-section of the first horizontal well of the Example. The productive interval (slotted liner) for the first horizontal well of the Example intersects intervals above top perforations of vertical wells. The intervals above the top perforations of the vertical wells are interpreted to be heated and highly fractured, due to steaming of the vertical wells: (prior to abandonment).

FIG. 2 shows a cross-section through an oil saturation model depicting the lateral section of the first horizontal well of the Example. The view is looking to the north-northwest direction at the steep dips of the formation, and the schematic indicates that gravity drainage could be a significant component of the producing mechanism for the first horizontal well of the Example.

DETAILED DESCRIPTION

While heavy oil reserves can be recovered through known “steam fracturing” processes, it has been discovered, as indicated by data acquired through the use of surface tiltmeters, that, during some steam cycles, fugitive steam migration can occur in the overburden (i.e., above the reservoir). The fugitive steam migration is believed to be caused by shallow casing damage or out-of-zone fracturing and result in higher than normal pressures in the overburden. The higher than normal pressures are believed to cause surface expressions, drilling issues, workover difficulties and surface uplift. As used herein, “surface expressions” refer to high-pressure volumes of steam and oil that breach the surface and result in recordable spills. Recordable spills are not only costly from an HES (health-environmental-safety) standpoint, but can also lead to significant lost production/revenue if steaming is curtailed as a result. In particular, surface expressions can lead to the abandonment of damaged (or assumed damaged) wellbores.
A surface expression can lead to a moratorium on drilling/steaming new replacement or infill wells in the area of the surface expression, as well as a moratorium on operating remaining wells around the surface expression by conventional cyclic steaming means, for fear of agitating the surface expression. It was surprisingly discovered that such remaining wells, when converted to artificial lift (rod-pump) without active steam injection, in order to help reduce surface dilation and continue to recover reserves in close proximity to the surface expression, produced at rates exceeding expectations.
Thus, high oil production from the post-steam, artificial lift (rod-pump) wells, without direct cyclic steam injection, led to the exploration of whether the performance of rod-pump wells could be duplicated with a horizontal well. It was discovered that a horizontal well could intersect the cyclic-steam induced fractures of abandoned vertical wells and still be productive without steam injection. Without wishing to be bound by any theory, it is believed that the production mechanisms for artificial lift wells in the reservoir are three-fold. First, gravity drainage likely assists in areas of steeply-dipping beds and thus oil can migrate within a single pattern. Second, established, open-fractures (both steam-induced and natural) play a major role in providing migration pathways for the oil in the low-permeability matrix rock. Third, the remaining heat from prior cyclic steaming, along with steaming on the periphery of the area, both play an important role in the heating and viscosity reduction of the oil.
The area near a surface expression can be characterized as one that has both steam-induced fractures as well as existing natural fractures. The high frequency of natural fractures can be documented near surface expressions through a detailed FMI/EMI (electromagnetic interference) study. Without wishing to be bound by any theory, it is believed that the natural fractures, along with steam-induced fractures, likely create a network that can be supplied with steam and can become “pressured”, as well as further heated, which allows for the production of oil through an artificial lift mechanism and does not necessarily require active injection in the producing wellbore. While not clear how far steam and pressure can propagate through existing fractures in the area of a field near a surface expression, rod-pump response to aggressive steaming suggests that the methods disclosed herein are a viable mechanism for continual resurgence in production.
As used herein, the phrase “substantially vertical” refers to an orientation of approximately 30° or less from vertical, while the phrase “substantially horizontal” refers to an orientation of approximately 30° or less from the horizontal.
From a strictly subsurface standpoint, there are a few basic criteria to be followed when planning a wellpath of a horizontal well. The criteria are used to create a “best-fit” line for a lateral section of the well. Exemplary criteria include:
1) The path should be within approximately 50 feet of targeted abandoned wells.
2) The path should pass by the abandoned wells at an elevation no greater than approximately 160 feet above (in TVDSS) top perforations of the abandoned wells.
3) The path should pass by the abandoned wells at a TVDSS elevation that would be no lower than bottom perforations for the abandoned wells.
4) The interpreted fracture networks from abandoned wells was targeted with greater than 150,000 barrels (CWE) of cumulative steam injection.
As disclosed herein, horizontal rod-pump wells are viable options to cyclic steaming in thermally mature areas, by taking advantage of a combination of steam-induced and natural fractures and gravity drainage of hot, mobile oil. Exemplary uses include:
1) Drilling horizontal Wells to supplement existing vertical wells or replace vertical abandoned wells, when the vertical wells have previously been injected with greater than 50,000 cumulative barrels of steam (Cold Water Equivalent or CWE) and the lateral (production) section of the horizontal well is generally between the depths (total vertical depth subsea or TVDSS) of top and bottom perforations of offset vertical wells (when passing by the vertical wells). In one embodiment, the depth range is within approximately 200 feet TVDSS (height) from the top perforation of the vertical wells or approximately 50 feet TVDSS (depth) below bottom perforation of the vertical wells.
2) Drilling horizontal wells in a thermal diatomite field such that a productive portion of the horizontal well lies within approximately 100 feet from all existing or abandoned wells that have previously been injected with greater than 50,000 barrels of steam (OWE), in accordance with the aforementioned parameters for depth relative to perforations of offset vertical wells. In an embodiment, the productive portion of the horizontal well can be defined as any well completion (perforated or slotted liner) that is at an angle of 90°, or higher, and is used for inflow of oil and water.
3) Drilling horizontal wells in thermal diatomite, followed by drilling and completing vertical wells according to the aforementioned parameters for depths of perforations, relative to the productive portion of the horizontal well.
Essentially, the horizontal well disclosed herein employs a “fracture/heat salvage” approach for production in heavy oil fields such as, for example, thermal diatomite settings.

EXAMPLE

The following illustrative example is intended to be non-limiting.
A surface expression led to a moratorium on drilling/steaming new replacement or infill wells, within a 500 feet radius of the surface expression. The great number (i.e., twenty two) of abandoned wells and the restricted steaming policy led to significant loss of production (on the order of approximately 1000 Barrels Per Day or BPD) in the area of the surface expression.
Despite the abandonment of several active wells around the surface expression, there were several wells that remained. The several remaining wells were not operated by conventional cyclic steaming means, for fear of agitating the surface expression. Thus, one well was converted to artificial lift (rod-pump) in order to increase Antelope withdrawal, help reduce surface dilation, and continue to recover reserves in close proximity to the surface expression. Surprisingly, without active steam injection, the well produced at rates exceeding expectations (on the order of hundreds of BPD), until casing damage necessitated the abandonment of the converted well. Shortly after the conversion to rod-pump, four other producing wells were also equipped with rod-pumps. The four additional converted wells also responded positively.
When planning the first horizontal well, the exemplary well planning criteria as disclosed herein were focused on to ensure that the wellpath would be close enough to the abandoned wells, so as to capitalize on steam-induced fracturing and heating (see FIG. 1). Specifically, the productive portion, or productive interval (slotted liner), for the first horizontal well intersected intervals above the top perforations of the vertical wells. The intersected intervals above the top perforations were interpreted to be heated and highly fractured, due to steaming of the vertical wells (prior to abandonment).
The path of the first horizontal well targeted four previously abandoned wells in the area of the surface expression. The first horizontal well took a little over a week to drill and complete. The well was put on production with an initial production (IP) exceeding 1000 Barrels of Oil Per Day (BOPD). The first horizontal well had sustained production exceeding the average well production in the field by a factor of ten.
Prior to drilling the first horizontal well, the hypothesized mechanism for production was that the horizontal well would take advantage of the years of historic steam injection in the area by intersecting both steam-induced and natural fractures and also benefit from gravity drainage in the reservoir and wellbore (heel-to-toe elevation change rises 12°). The performance of the first horizontal well substantiates the hypotheses and suggests contribution from the majority of lateral section.
In addition to the first horizontal well, two additional horizontal well opportunities in the field were identified and capitalized on. The two additional horizontal wells were planned and drilled parallel to the first horizontal well, with the path of the second and third additional horizontal wells targeting six and five previously abandoned wells in the area of the surface expression, respectively.
FIG. 2 is a cross section through an oil saturation model for the oil field in which the surface expression occurred, showing the steep dips of the formation. Without wishing to be bound by any theory, it is believed that steep dips of the formation of the oil field in which the surface expression occurred, along with natural and steam-induced fractures, allow for the likelihood that gravity drainage could have been a significant component of the production mechanism for some horizontal wells at the oil field. Bedding dips can exceed 45° in the part of the field where the three horizontal wells were drilled and hot, mobile oil can drain down the steep beds. If a gravity drainage mechanism was taking place, then lateral portions of the three horizontal wells were in favorable position to capture the hot, mobile oil.
Previous near-wellbore volumetric calculations indicated that a considerable portion of the oil in the first horizontal well path was drained within 25 feet of the abandoned wellbores. However, the same study also concluded similar results for the aforementioned vertical rod-pump producers. The actual performance of the first horizontal well (discussed below), along with the rod-pump production response to offset steaming, suggests that oil production can be contributed from further than 25 feet away (from bottomhole location), which suggests that a fracture network exists in the mature area of the surface expression and the fracture network likely allows for the migration of steam and oil.
Many modifications of the exemplary embodiments disclosed herein will readily occur to those of skill in the art. The present disclosure is intended for purposes of illustration only and should not be construed in a limiting sense. Accordingly, the present disclosure is to be construed as including all structure and methods that fall within the scope of the appended claims. The term “comprising” within the claims is intended to mean “including at least” such that the recited listing of elements in a claim are an open set or group. Similarly, the terms “containing,” having,” and “including” are all intended to mean an open set or group of elements. “A,” “an” and other singular terms are intended to include the plural forms thereof unless specifically excluded.

Claims

1. A method of drilling a wellbore useful for the recovery of hydrocarbons from a subsurface reservoir the method comprising:

drilling a wellbore comprising a substantially horizontal productive portion lying within the subsurface reservoir;

wherein the subsurface reservoir is penetrated by one or more wellbores previously injected with steam.

2. The method of claim 1, further comprising producing hydrocarbons from the wellbore.

3. The method of claim 1, wherein the subsurface reservoir has achieved a threshold thermal maturity from the steam previously injected therein.

4. The method of claim 1, wherein the subsurface reservoir is penetrated by one or more wellbores previously injected with at least 50,000 cumulative barrels of steam.

5. The method of claim 1, wherein the subsurface reservoir is penetrated by one or more wellbores previously injected with at least 150,000 cumulative barrels of steam.

6. The method of claim 1, wherein the subsurface reservoir is penetrated by one or more substantially vertical wellbores previously injected with steam.

7. The method of claim 6, further comprising positioning the substantially horizontal productive portion of the wellbore within a lateral range of approximately 100 feet of one or more of the substantially vertical wellbores.

8. The method of claim 6, further comprising positioning the substantially horizontal productive portion of the wellbore at a depth defined by top-most and bottom-most perforations of one or more of the substantially vertical wellbores.

9. The method of claim 6, further comprising positioning the substantially horizontal productive portion of the wellbore within a depth range defined by an upper depth limit of approximately 200 feet TVDSS above a top-most perforation of one or more of the substantially vertical wellbores and a lower depth limit of approximately 50 feet TVDSS beneath a bottom-most perforation of one or more of the substantially vertical wellbores.

10. The method of claim 6, further comprising positioning the substantially horizontal productive portion of the wellbore a depth range defined by an upper depth limit of approximately 160 feet TVDSS above a top-most perforation of one or more of the substantially vertical wellbores and a lower depth limit no lower than a bottom-most perforation of one or more of the substantially vertical wellbores.

11. The method of claim 1, wherein the subsurface reservoir is a heavy oil reservoir.

12. The method of claim 11, wherein the subsurface reservoir is a diatomite reservoir.

13. The method of claim 1, further comprising planning a path of the substantially horizontal productive portion of the wellbore to be within a lateral range of approximately 100 feet of one or more of the wellbores previously injected with steam.

14. The method of claim 1, further comprising planning a path of the substantially horizontal productive portion of the wellbore to be within a lateral range of approximately 50 feet of one or more of the wellbores previously injected with steam.

15. A drilled wellbore comprising:

a substantially horizontal productive portion lying within a subsurface reservoir, wherein the subsurface reservoir is penetrated by one or more substantially vertical wellbores, the substantially horizontal productive portion located;

within a depth range defined by an upper depth limit of approximately 200 feet TVDSS above a top-most perforation of one or more of the substantially vertical wellbores and a lower depth limit of approximately 50 feet TVDSS beneath a bottom-most perforation of one or more of the substantially vertical wellbores; and

within a lateral range of approximately 100 feet of one or more of the wellbores previously injected with steam.

16. A method of drilling a wellbore useful for the recovery of hydrocarbons from a subsurface reservoir, the method comprising:

drilling one or more substantially vertical wellbores; and

perforating the one or more substantially vertical wellbores according to a depth of the substantially horizontal productive portion of the wellbore.

17. The method of claim 16, further comprising producing hydrocarbons from the wellbore.

18. The method of claim 16, wherein a top-most perforation of the one or more substantially vertical wellbores occurs not lower than approximately 200 feet TVDSS beneath the substantially horizontal productive portion of the wellbore and a bottom-most perforation of the one or more substantially vertical wellbores occurs not more than approximately 50 feet TVDSS above the substantially horizontal productive portion of the wellbore.

19. The method of claim 16, wherein the subsurface reservoir is penetrated by one or more wellbores previously injected with at least 50,000 cumulative barrels of steam.

20. The method of claim 16, further comprising planning a path of the substantially horizontal productive portion of the wellbore to be within a lateral range of approximately 100 feet of one or more of the wellbores previously injected with steam.