Horizontal drilling

A method and apparatus for recovering viscous hydrocarbons from a subsurface reservoir holding the same using an essentially horizontal well bore having a production inlet and containing steam injection tubing that carries a plurality of jet nozzles oriented to emit steam along said injection tubing towards said production inlet.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates to the drilling, completion, and production of an essentially horizontal (hereafter “horizontal”) well section into and along a subsurface, geological formation that contains heavy, viscous hydrocarbons, as disclosed in U.S. Pat. Nos. 5,289,881 and 5,607,018, both issued to Frank J. Schuh.

2. Description of the Prior Art

U.S. Pat. No. 5,289,881 discloses in its FIG. 1 a horizontally extending well bore and casing section which contains steam injection tubing (injection tubing) 32. This injection tubing is terminated at its far down stream end by a choke 22 through which all vaporous steam (steam) injected from the surface of the earth leaves the tubing and enters the well bore casing annulus 42 for injection, through casing perforations 18, into producing zone 14. Zone 14 contains the viscous hydrocarbons that are desired to be produced to and recovered at the earth's surface. U.S. Pat. No. 5,289,881 is hereby incorporated in its entirety by reference.

U.S. Pat. No. 5,607,018 discloses a related production scheme in its FIG. 9 except that steam leaves the interior of steam injection tubing 132 by way of a series of holes 133 in that tubing. Holes 133 allow steam to exit the tubing in a direction that is directly toward casing 116, i.e., a direction that is essentially perpendicular to the long axes of both the injection tubing and the casing (liner) 116. Put another way, the exiting steam from the injection tubing is pointed directly at the inner surface of the casing, and its perforations 118, for injection of that steam into the hydrocarbon bearing formation 114 to liquefy such hydrocarbons for ultimate production to and recovery at the earth's surface. It is also disclosed in this patent, column 12, that the horizontal portion of the well bore can deviate less than 90° or more than 90° from the essentially horizontal portion of the well bore. U.S. Pat. No. 5,607,018 is hereby incorporated in its entirety by reference.

For sake of clarity, the horizontal sections of the well bore, casing and injection tubing are all shown in both of the aforesaid patents to be essentially straight along their longitudinal axes. In reality, this is not always the case. In drilling the horizontal portion of a well bore, the driller uses a commercially available instrument known as a three axis accelerometer to direct the drilling of that horizontal section. The typical accuracy for this instrument ranges from ¼ to ½ degree and can cause the driller to unknowingly deviate from the desired path. If the drilling path for any of a number of well known reasons, e.g., subsurface heterogeneities, tends too far upward or downward while drilling in the formation, the driller makes adjustments either up or down to the drilling apparatus to get the drill bit back on the desired drilling path. As explained hereinafter in greater detail, these adjustments, which are made while drilling proceeds unchecked, can result in the horizontal section of the well bore having, at least in parts thereof, a sinusoidal shape along the longitudinal axis of the well bore. Any sinusoidal configuration of the well bore is, upon completion of the well, transferred to the casing and injection tubing contained in the horizontal section of that well bore.

Thus, in reality, there can be one or more low spots in the horizontal sections of the well bore, casing, and injection tubing which can be substantial. For example, it is not uncommon for a low spot to deviate from about one to about five feet lower in elevation than the adjacent high spot.

Produced fluids, as used herein, are primarily a combination of liquid water (largely condensed steam) and liquid hydrocarbons that have been mobilized by contact with the steam injected into the formation from the injection tubing by way of the casing perforations. Produced fluids can collect in the aforementioned low spots. Undesired pools of produced fluids in such low spots not only mean lost production of desired hydrocarbons to the earth's surface, but can adversely affect the hydrocarbon production operation, e.g., by impeding or otherwise altering in a deleterious way the flow of steam in the casing annulus that surrounds the injection tubing.

Accordingly, it is highly desirable to have a horizontal well bore production scheme that overcomes the ill effects of hydrocarbons collecting in casing low spots, and this invention does just that.

SUMMARY OF THE INVENTION

In accordance with this invention, there is provided a method and apparatus for rendering mobile a viscous hydrocarbon held in a subsurface geologic formation by employing a horizontal well bore completion scheme that includes a steam injection tubing string that contains a plurality of jet nozzles that inject vaporous steam along the injection tubing, and toward a production tubing inlet.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 1shows earth's surface110into which has been drilled in a conventional manner an essentially vertical well bore111which has been turned essentially 90° from the vertical to form an essentially horizontal well bore section (interval)112in hydrocarbon containing formation (reservoir)114. At the upstream end of horizontal section112of the well bore, a pack off126has been installed through which passes 1) steam injection tubing120whose horizontal section132contains a plurality of apertures (holes)133along its longitudinal axis (seeFIG. 2), and 2) production tubing124with its associated production inlet127. Production string inlet127receives produced fluids from horizontal section112, and transmits them by way of production tubing124to earth's surface110for recovery and other processing as desired.

Steam injected from earth's surface110through injection tubing120leaves the interior of that tubing by way of both holes133, as shown by arrows130, and choke122; and enters the annulus135inside casing116, which annulus surrounds horizontal section132of injection tubing120. Annulus135has a substantially larger internal volume than the internal volume of injection tubing120, e.g., a volumetric ratio of annular volume to injection tubing volume of from about 3/1 to about 5/1. This steam then leaves the interior of casing116by way of certain of the apertures118that extend around the circumference of section112of casing116, and enters the interior of formation114, as shown by arrows136. This forms a steam cavity in formation114from which some hydrocarbon has been recovered and in which fresh steam is motivating (liquefying) additional viscous hydrocarbon present in the walls of such steam cavity. Produced fluids enter annulus135by way of certain other apertures118as shown by arrows138.

Line140inFIG. 1denotes the interface between vaporous steam from holes133and liquid, produced fluids from certain apertures118as afore said, and further shows that a certain volume of produced fluids will be trapped in low spot141of thisFIG. 1. Low spot141can contain a substantial volume of trapped produced fluids because it can extend for tens of feet in length and be from one to five feet lower in elevation150than its associated high spot151. Holes133inject steam directly toward the interior surface152and holes118of casing116, i.e., essentially perpendicular to the longitudinal axis of injection tubing120, and are not effective in cleaning out produced fluids trapped in low area141of annulus135for recovery of same at the earth's surface. In a given well, horizontal section112can contain a plurality of such low spots, just one such spot141being shown inFIG. 1for sake of brevity and clarity.

FIG. 2shows a section of injection tubing120that employs a jet nozzle pursuant to this invention. Tubing120has an outer surface201and an inner surface202. The longitudinal axis of tubing120is shown at200. Steam from the earth's surface passes through interior203of tubing120in the direction shown by arrow204. Steam204can be at a pressure of from about 250 to about 680 psia, and a temperature of from about 400 to about 500° F. Jet nozzle205is in fluid communication between injection tubing interior203and casing annulus135. Outer surface201carries a jet nozzle205which contains a constriction206which accelerates the velocity of steam204, and a narrower passage (choke)207which further accelerates the compressed, pressurized steam208into lower pressure, larger volume annulus135, thus injecting steam208with substantial force into annulus135. Such compressed steam208is also deliberately injected along the long axis200, i.e., outer surface201, of injection tubing120in a direction towards production inlet127(FIG. 1) to move both the produced fluids and steam toward the inlet for production to the earth's surface. This injection of compressed steam208into annulus135not only forcibly moves produced fluids towards production inlet127, but at the same time removes essentially all trapped production fluids held in one or more low spots, e.g., area141ofFIG. 1, that can occur from location to location along the length of injection tubing120. Choke207can be, but is not necessarily, essentially round, and has a diameter of from about 7/32 to about 14/32 of an inch, or the equivalent if not round.

FIG. 3shows a longer section of injection tubing120containing a plurality of jet nozzles205. Note that downstream end300is closed and does not contain a choke122. Thus, choke122has been eliminated with out eliminating the function thereof. The injection of compressed steam208into annulus135is so robust that nozzles205can be spaced about the outer surface (periphery)201of tubing120in a random or patterned fashion and the results of this invention still realized. Thus, as shown in this Figure, nozzles205can be distributed on the top, bottom, and/or sides of tubing120as desired, or any individual choice or combination thereof.

By using a plurality of nozzles205that discharge steam essentially parallel to the long axis200of injection tubing120, and toward the production inlet127, sufficient flow-energy is generated to transport essentially all produced fluids, including any and all produced fluids trapped in low spots, to production inlet127.

The amount of flow-energy generated, and the lift capacity of the nozzle array employed will vary considerably depending on the details of the particular well completion, and can be controlled by the steam injection rate at the earth's surface, the production rate of produced fluids at the earth's surface, and nozzle sizing, spacing, and positioning along the injection tubing, all of which can readily be determined by one skilled in the art once apprised of this invention. With close spaced nozzles, the available energy is greater than required to transport produced fluids, and the uniformity of steam distribution maximized. With widely spaced nozzles, the available energy exceeds the transport requirement. Although nozzle spacing can vary widely, from a practical point of view a maximum spacing could be about 400 feet, and a minimum spacing about 35 feet. The spacing is from about 100 to about 150 feet under most conditions. Injection tubing120can, if desired, be essentially centralized inside annulus135to provide a clearer path for steam flow around the entire circumference of the injection tubing. Desirably, nozzles205will be located near the center of annulus135between the outer surface201of the injection tubing and the inner surface400(seeFIG. 4) of casing116. Also desirably, the operation is carried out at an essentially constant temperature and pressure within the steam cavity formed by mobilizing hydrocarbons in formation114. Minimizing any excess of flow-energy can be obtained by maintaining an essentially constant pressure, which also favors close spaced nozzles.

The maximum lift capacity can occur at the bottom of the horizontal portion of the well bore adjacent the closed end300(FIG. 3) of injection tubing120. At that location, a280foot spacing of nozzles can provide an average of about 3 feet of lift per hundred foot of horizontal bore hole. This lift rate can vary from about 1.2 to about 4.8 per hundred feet over the life of the well. In the middle of the horizontal interval the lift capacity is less than half of the maximum, while the lift rate for the first nozzle below packer126is about 30% of the maximum. Selecting a spacing that provides the required lift for the upward undulations in the horizontal interval of the well bore can lessen the variation of pressure along the horizontal borehole.

The produced fluids rate at the earth's surface increases rapidly as the steam cavity expands upward to the top of formation114. From that point it declines until the economic production rate limit is reached. The rate of liquid steam condensate production at the earth's surface is essentially the same as the steam injection rate at the earth's surface. Thus, for a typical design the steam injection rate at the earth's surface can start at about 12,000 pounds per hour, reach a peak of about 21,000 pounds per hour, and drop to about 11,000 pounds per hour as the economic production limit is reached.

FIG. 4shows a cross-section of how produced fluids flow in the operation of this invention between adjacent jet nozzles205and405, with nozzle405being located on the side of injection tubing120, rotated about 90° from nozzle205. Nozzle205is designed to introduce the steam vapor at the rate that will enter the steam cavity between nozzles205and405. Line406shows the interface between essentially only vaporous steam, and essentially liquid produced fluids. Thus, immediately adjacent the outlet of nozzle205is primarily steam with a minor amount of liquid at the bottom of annulus135. Intermediate nozzles205and405, as steam escapes into formation114by way of holes118(arrows136), the share (fraction) of liquid in annulus135increases. Just up stream of nozzle405the last of the steam vapor exits the annulus at that location. Thus it can be seen that steam208is a substantial propellant of liquid (produced fluids) that enters the annulus by way of holes118at the bottom of casing116as shown by arrow138. Note that the produced fluids are also forcibly propelled in the direction of arrows208which is essentially parallel to long axis200(FIG. 3) and toward production inlet127(FIG. 1).

FIG. 5shows a cross section5-5ofFIG. 4, and further shows that annulus135is essentially 90% full of produced fluids at this location.

FIG. 6shows a cross section6-6ofFIG. 4, and further shows that annulus135is about 40% full of produced fluids at this location.

FIG. 7shows a cross section7-7ofFIG. 4, and further shows that annulus135is about 80% full of produced fluids at this location.

Thus, it can be seen that produced fluids are driven by steam208toward inlet127, and, because of the flow-energy imparted by a plurality of spaced apart jet nozzles along the length of injection tubing120, not only moves newly entering produced fluid, but, at the same time, moves trapped produced fluids from low spots such as area141(FIG. 1).

EXAMPLE

Formation114is at a depth of about 100 feet, and a thickness of about 36 feet. A well bore is drilled down to the formation and then horizontally in that formation for about 1,300 feet about 1 foot above the bottom of the formation. The well is cased with 9⅝ inch casing from the earth's surface to the beginning of the horizontal interval. The horizontal interval is cased with pre-perforated 7 inch outer diameter liner116(6.366 inch inner diameter). The 3½ inch outer diameter (2.992 inch inner diameter) production tubing string124extends from the earth's surface to and just through the dual packer126, terminating at production inlet127. Four inch outer diameter (3.548 inch inner diameter) steam injection tubing120extends essentially to the bottom of the well bore, i.e., far end of the horizontal section of the well bore and its casing (FIG. 1). Thirteen horizontally oriented (with respect to the long axes of both the casing and injection tubing) steam injection nozzles205,405, etc. are placed at about 100 foot intervals along and around (FIG. 3) the length of the injection tubing with their outlets facing toward inlet127.

The horizontal section of the well bore and the steam cavity in formation114are kept at an essentially constant temperature and pressure of about 350° F. and about 135 psia.

The 13 nozzles use an initial steam injection rate of about 945 pounds per hour per nozzle, using nozzle chokes from about 0.302 to about 0.308 inches. Individual nozzle steam emission velocities are about 1,339 feet per second. The horizontal interval varies in a sinusoidal manner up and down from the intended well bore path about 1 foot.

After 3.5 years of production, the maximum steam injection rate is about 20.6 million BTU's per hour, thereby producing about 200 barrels of hydrocarbon per day and about 1,520 barrels of water per day. At this time each nozzle is emitting about 1,620 pounds of steam per hour at an exit velocity of about 1,384 feet per second.

At the multi-year producing life of the well, the injection rate is 11.1 million BTU's per hour of steam. The final producing rate is about 71 barrels of hydrocarbon per day and about 820 barrels of water per day. The final individual nozzle flow rate is about 865 pounds per hour with a steam emission velocity of about 1,334 feet per second.