US20160053542A1

US20160053542A1 - Apparatus and Method for Underbalanced Drilling and Completion of a Hydrocarbon Reservoir

Info

Publication number: US20160053542A1
Application number: US14/831,639
Authority: US
Inventors: John M. Stafford
Original assignee: Laris Oil & Gas LLC
Current assignee: Laris Oil & Gas LLC
Priority date: 2014-08-21
Filing date: 2015-08-20
Publication date: 2016-02-25

Abstract

A system and method for underbalanced drilling and completion of a hydrocarbon reservoir is disclosed. The system prevents formation damage by using a solids-free, non-wetting phase drilling fluid while maintaining underbalanced conditions throughout the entire drilling and completion phase of the operation. By preventing formation damage, this system provides an alternative or supplement to hydraulic fracking.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority to and the benefit of U.S. Provisional Patent Application No. 62/040,285 entitled “Apparatus and Method for Underbalanced Drilling and Completion of a Hydrocarbon Reservoir” filed on Aug. 21, 2014, the entire disclosure of which is incorporated by reference herein.

FIELD

Embodiments of the present invention are generally related to a system and method for underbalanced drilling and completion of a hydrocarbon reservoir and in particular, to a system and method for underbalanced drilling and completion of a hydrocarbon reservoir while maintaining underbalanced conditions throughout the entire drilling and completion phase of the operations.

BACKGROUND

Conventional hydrocarbon reservoir drilling employs overbalanced drilling, cementing of the steel casing of the wellbore, and a kill mud approach for well completion. In overbalanced drilling, the wellbore is kept at a pressure higher than the pressure of the hydrocarbon formation to prevent formation fluid from entering the well. These conventional techniques cause formation damage to the hydrocarbon reservoir. Formation damage results in reduced reservoir permeability which limits well productivity. Furthermore, formation damage caused by overbalanced drilling can so reduce reservoir permeability that hydraulic fracturing is required to yield an economically viable well.
Formation damage is caused by foreign fluids and/or solids entering a hydrocarbon bearing reservoir during the drilling and/or completion phase of the operation. Such foreign fluids can cause: (1) capillary pressure water blocks to form within the pores, pore throats and/or fracture apertures within the reservoir; (2) expandable clays such as Smectite or mixed-layer clays (such as Chlorite-Smectite) to expand within the pores, pore throats and/or fracture apertures within the reservoir; or (3) solids contained within the drilling mud (such as mud additives or rock cuttings) to be injected into the pores, pore throats and/or fracture apertures within the reservoir. All such types of formation damage reduce the permeability of the reservoir which in turn reduces the ability of hydrocarbons to flow through the reservoir and into the wellbore, thereby reducing the productivity of a well. When the amount of formation damage is significant, the reservoir must be hydraulically fractured in order to mitigate the formation damage and obtain economic rates of production.
A system and method for underbalanced drilling (“UBD”) and completion of a hydrocarbon reservoir is disclosed. In underbalanced drilling, the pressure in the wellbore is kept lower than the fluid pressure in the formation being drilled. The system and method for underbalanced drilling and completion of a hydrocarbon reservoir maintains underbalanced conditions throughout the entire drilling and completion phase of the operation, thereby not causing formation damage to the hydrocarbon reservoir which would reduce reservoir permeability and thus limit well productivity. By preventing formation damage, the need to hydraulically fracture stimulate the hydrocarbon bearing reservoir may be eliminated in many cases. As such, the system and method provides an alternative or supplement to hydraulic fracture stimulations. In one embodiment, the system and method uses a solids free, non-wetting phase drilling fluid and does not cement a casing string across the producing formation in the wellbore. Maintaining underbalanced conditions throughout the drilling and completion phase of the operation, together with not cementing a string of casing in the producing formation and using only non-wetting phase drilling and completion fluids while in the target zone, prevents formation damage from occurring.

SUMMARY

A “Cradle-to-Grave” system and method to prevent formation damage in oil and/or gas reservoirs by drilling with a solids-free, non-wetting phase drilling fluid, while maintaining underbalanced conditions throughout the entire drilling and completion phase of the operation, is disclosed.
In one embodiment, an advanced method of drilling a hydrocarbon wellbore is disclosed, the method comprising: using at least one of an overbalanced and an underbalanced fluid column to drill a wellbore to an upper portion of a hydrocarbon reservoir; installing and cementing a casing string inside the wellbore to the upper portion of the hydrocarbon reservoir; providing a mechanical fluid control valve in the casing string segment above a predetermined target producing zone; using an underbalanced fluid column, drilling and completing the targeted producing zone using a solids-free and non-wetting phase drilling fluid maintained below the pressure of the hydrocarbon reservoir; injecting nitrogen into the drilling fluid as needed to reduce the hydrostatic head of the drilling fluid and enable the underbalanced drilling to be maintained; and circulating the drilling fluid and nitrogen, and any produced fluids and rock cuttings, through a series of surface process equipment designed to separate oil, gas, water and rock cuttings under pressure.
In another embodiment, a method of drilling for recovery of hydrocarbons comprising oil and natural gas from a hydrocarbon reservoir is disclosed, the method comprising: using an overbalanced or underbalanced fluid column to drill a hydrocarbon wellbore to an upper portion of a hydrocarbon reservoir; installing and cementing a casing string inside the wellbore; providing a downhole deployment valve in a lowermost casing string segment and above a projected hydrocarbon producing zone; using an underbalanced fluid column, drilling and completing the targeted producing zone using a solids-free and non-wetting phase drilling fluid maintained below the pressure of the hydrocarbon reservoir; providing nitrogen as needed in the drilling fluid to reduce the hydrostatic head of the drilling fluid; circulating the nitrogen through an annulus formed by a second casing; circulating the drilling fluid and nitrogen, and any produced fluids and rock cuttings, through surface process equipment designed to separate oil, gas, water and rock cuttings under pressure.
In yet another embodiment, a system for drilling for recovery of hydrocarbons comprising oil and natural gas from a hydrocarbon reservoir is disclosed, the system comprising: a wellbore extending at least to an upper portion of a hydrocarbon reservoir; a casing string disposed inside the wellbore; a mechanical fluid control valve disposed in the casing string segment and above a target producing zone; utilizing a solids-free and non-wetting phase drilling fluid maintained below the pressure of the hydrocarbon reservoir; and wherein the drilling fluid is maintained below the pressure of the hydrocarbon reservoir to enable underbalanced drilling; wherein nitrogen is injected into the drilling fluid as needed to reduce the hydrostatic head of the drilling fluid and enable the underbalanced drilling to be maintained; and wherein nitrogen, hydrocarbons, and drilling fluid are produced and treated under pressure with surface process equipment.
This Summary is neither intended nor should it be construed as being representative of the full extent and scope of the present disclosure. The present disclosure is set forth in various levels of detail in the Summary as well as in the attached drawings and the Detailed Description of the Invention, and no limitation as to the scope of the present disclosure is intended by either the inclusion or non-inclusion of elements, components, etc. in this Summary of the Invention. Additional aspects of the present disclosure will become more readily apparent from the Detailed Description, particularly when taken together with the drawings.
The above-described benefits, embodiments, and/or characterizations are not necessarily complete or exhaustive, and in particular, as to the patentable subject matter disclosed herein. Other benefits, embodiments, and/or characterizations of the present disclosure are possible utilizing, alone or in combination, as set forth above and/or described in the accompanying figures and/or in the description herein below. However, the Detailed Description of the Invention, the drawing figures, and the exemplary claim set forth herein, taken in conjunction with this Summary of the Invention, define the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are incorporated in and constitute a part of the specification, illustrate embodiments of the invention and together with the general description of the invention given above, and the detailed description of the drawings given below, serve to explain the principals of this invention.

FIG. 1 depicts a circulation schematic of one embodiment of the underbalanced drilling method and system;

FIG. 2A depicts a one embodiment of the underbalanced drilling method and system using a wellbore single casing arrangement; and

FIG. 2B depicts another embodiment of the underbalanced drilling method and system using a wellbore dual casing arrangement;

It should be understood that the drawings are not necessarily to scale. In certain instances, details that are not necessary for an understanding of the invention or that render other details difficult to perceive may have been omitted. It should be understood, of course, that the invention is not necessarily limited to the particular embodiments illustrated herein.
To assist in the understanding of one embodiment of the present invention the following list of components and associated numbering found in the drawings is provided.


#	Component

10	System
12	Drilling Rig
14	Rotating Control Device (RCD)
16	Blow Out Preventer
18	Downhole Deployment Valve (DDV)
20	Manifold
22	4-Phase Separator
24	Flare Line
26	Flare Stack
28	Oil Line
29	Water Line
30	Solids Dump Line
32	N₂Source
34	Command Trailer
36	Frac Tanks Cascaded together to contain produced oil
37	Frac Tanks Cascaded together to contain produced water
38	Tanks Containing Solids-Free, Non-Wetting Phase Drilling Fluid
40	Rig Tanks
42	Rig Pumps
44	Drilling Fluid
46	Reserve Pit
48	Oil and/or Gas Bearing Reservoir
50	Mudlogger's Trailer
60	Single Casing Wellbore
62	Surface Casing
64	Last Casing Run above Target Formation
66	Annulus (single)
68	Drill Bit
70	Drill Pipe
72	N₂injected with Drilling fluid
74	N₂Return Flow up the Annulus
80	Concentric Casing Wellbore
82	Tie-Back Liner
84	Outer Annulus
86	Inner Annulus
88	Ports in Tie-Back Liner
90	N₂Injected into Outer Annulus
92	N₂Return Flow Up Inner Annulus

DETAILED DESCRIPTION

FIG. 1 depicts a circulation schematic of one embodiment of the drilling system 10. A drilling rig 12 sits atop the oil and/or gas bearing reservoir 48. The drilling rig 12 is connected by piping to the rotating control device (RCD) 14. A rotating head is required at the surface to provide a seal that diverts produced fluids to the 4-phase separator 22, via a manifold 20, to allow the drill string to continue drilling (i.e. rotating) during underbalanced conditions. The RCD also connects downstream from the blow out preventer 16 which connects downstream to the downhole deployment valve 18 before reaching into the oil and/or gas bearing reservoir 48.
The 4-phase separator 22 separates the oil, water, solids, and gas. The gas feeds into the flare line 24 before being burned off in the flare stack 26. The solids feed into the solids dump line 30 which feeds into the mudlogger's trailer 50. The water feeds into the water line 29 which deposits into the hydraulic fracturing (aka “frac”) tanks cascaded together to contain produced water 37. The oil feeds into the oil line 28 which is deposited into the frac tanks cascaded together to contain produced oil 36.
Tanks containing solids-free, non-wetting phase drilling fluid 38 feed into the rig tanks 40. The rig tanks keep a positive suction head on the rig pumps 42 which pump a combination of the non-wetting phase drilling fluid and nitrogen gas (“N₂”) from the N₂source 32 which combine in drilling fluid 44 line. The destination of the produced oil, water, solids, and/or produced gas may be controlled at the command trailer 34.
The reserve pit 46 is used to store any spare waste mud, base oil, or brine.
Conventional overbalanced drilling techniques rely on the hydrostatic head created by a heavy column of drilling mud to exert a pressure at depth that is equal to or greater than the formation pressure of the reservoir, thereby preventing formation fluids (oil, gas and/or water) from entering the wellbore while drilling. The pressure at depth that results from the hydrostatic head of the heavy column of mud commonly exceeds the formation pressure, resulting in the introduction of foreign fluids and/or solids into the hydrocarbon bearing reservoir 48. It is this entry of foreign fluids and/or solids into the reservoir that causes the formation damage.
Even if a well is drilled underbalanced, heavy kill mud is commonly pumped into the wellbore prior to completing the well. The heavy kill mud prevents the well from flowing when the drill pipe is removed from the wellbore. The kill mud has the same damaging effects as drilling the well overbalanced. As an alternative to using heavy kill mud, the use of a mechanical fluid control valve, such as a DDV 18, allows a well to be shut-in mechanically at depth by closing a hydraulically operated flapper valve via the use of controls at the surface. The use of the DDV 18 allows the operator to prevent the well from flowing mechanically (as opposed to hydraulically) and thereby eliminates the need to pump the kill mud. The DDV 18 allows for the prevention of the formation damage that would otherwise be caused by the kill mud. It is the use of the DDV 18 that allows underbalanced conditions to be maintained during trips for bit replacement and/or maintenance and when the drilling rig 12 is moved off the well in order to move in the completion rig.
Completing a well commonly involves running steel casing into the wellbore and cementing it in place prior to perforating the casing to establish production through the perforations or through which to fracture stimulate the formation in one or more stages. The process of cementing the casing into the wellbore involves pumping wet cement into the well so that it is forced up the annulus 66 (space between the outside of the casing and open hole) until cement reaches the desired height. The particulate matter making up the cement and the liquid cement filtrate are forced into the formation and cause formation damage in the same manner as the drilling mud described above.
Hydrocarbon reservoirs 48 are either “water-wet” or “oil-wet”. Those terms refer to the type of fluid that adheres to the surface of rock, not the type of fluid that the reservoir is capable of producing. If the reservoir 48 is water-wet, the wetting phase is water and similarly if the reservoir rock is oil-wet, the wetting phase is oil. Most hydrocarbon bearing reservoirs 48 are water wet, although some are oil wet and some have a mixed wettability (i.e. partially oil wet and partially water wet). Natural gas is never the wetting phase. During the drilling and completion process, the reservoir will imbibe the wetting phase fluid if that phase fluid is present in the drilling or completion fluids. For example, if a water-wet, oil bearing reservoir is drilled with a water based drilling mud, then the reservoir will imbibe the water contained within the drilling mud. This imbibition process drives the oil within the reservoir away from the wellbore. This process is analogous to the process used to water flood reservoirs whereby water is injected into an injection well so that the water will drive the oil within the reservoir toward other nearby producing wells. In a damage prone reservoir (that is not intended to be a water flood operation), once the hydrocarbons are pushed out away from the wellbore during drilling and completion, any formation damage caused by that imbibed fluid or the solids contained therein, will impede the return flow of those hydrocarbons back toward the producing wellbore. This impedance of the return flow is typically not a complete barrier to return flow toward the producing wellbore, but rather a relative decrease in flow compared to an otherwise non-damaged reservoir. In water wet or partially water wet reservoirs, however, imbibed water can create significant formation damage in the form of a capillary pressure water block. Accordingly, in order to maximize the production rate from a well, it is imperative to drill and complete the well using only a solids free, non-wetting phase fluid.
Generally, a “Cradle-to-Grave” process to prevent formation damage in oil and/or gas reservoirs by drilling and completing the well with a solids-free, non-wetting phase fluid, while maintaining underbalanced conditions throughout the entire drilling and completion phase of the operation, is disclosed. The application of this Cradle-to-Grave process prevents formation damage from occurring, therefore, it is not necessary to mitigate any formation damage and economic rates of production may be achieved without the need to hydraulically fracture the reservoir.
FIG. 2A depicts a cross sectional view of a single casing wellbore 60 which uses nitrogen to maintain balancing conditions. The underbalanced drilling method and system, in one embodiment, may use such a casing arrangement. The drill bit 68 is contained within the surface casing 62, which runs from the earth's surface, and the last or most distal casing run 64. The drill bit 68 drives interior or within the casing run 64 to reach the hydrocarbon reservoir 48. Nitrogen is injected under pressure downhole with the drilling fluid 72, exiting the drill bit 68 and returning up the annulus 74 formed between the casing and the drill pipe. The N₂returns 74 to the surface via the single annulus 66 outside the drill pipe 70 and inside the last casing run 64.
FIG. 2B depicts a cross sectional view of another embodiment of a wellbore casing arrangement of the underbalanced drilling method and system, comprising a concentric casing (aka dual casing) wellbore 80. The underbalanced drilling method and system may alternatively use such a casing arrangement. The surface casing 62 runs from the earth's surface and comprises the last casing run 64. Interior to the last casing run 64 is, concentrically, outer annulus 84, the tie-back liner 82, and the inner annulus 86. N₂is injected 90 down the outer annulus 84, where it flows through the ports in the tie-back liner 88, and is urged upwards through inner annulus 86 by pressure of the hydrocarbon reservoir 48 and the buoyancy of the nitrogen gas. The buoyancy of the nitrogen gas, among other things, reduces the hydrostatic head of the fluid column. The drill pipe 70 is positioned within the inner annulus 92 and attaches to the drill bit 68, which drives further into the earth than the annuli 84, 86.
In yet another embodiment, nitrogen may be injected down the inner annulus 86 where it flows through the ports in the tie-back liner 88, and is urged upwards through the outer annulus 84 by pressure of the hydrocarbon reservoir 48 and the buoyancy of the nitrogen gas. In one embodiment, no drilling or completion fluid which is overbalanced with respect to the hydrocarbon formation pressure comes in contact with the hydrocarbon formation.
With respect to FIGS. 1 and 2, the elements of the system and method are discussed below.

Pre-Drill Modeling for UBD Conditions

Pre-drill modeling is conducted to determine and assess drilling conditions as suitable for underbalanced drilling.

Training Rig and 3^rdParty Contractors in UBD

Because UBD is an atypical drilling method, rig and third-party contractors are provided special training in UBD.

Drill to the Top of the Targeted Pay Zone Using Conventional Overbalanced Drilling Techniques

Conventional overbalanced techniques are used until the targeted zone is reached, to include conventional cementing of the casing string within the wellbore, at least within the upper portion of the wellbore. One embodiment of a wellbore includes an upper (vertical well) portion drilled using conventional overbalanced techniques and lower portion (horizontal portion), in targeted zone, drilled using underbalanced drilling. Other embodiments include using conventional overbalanced techniques until the targeted zone is reached as discussed above, with the lower portion using underbalanced techniques but also in a vertical wellbore. An alternate embodiment of the method to drill the underbalanced portion of the well comprises the use of coiled tubing, as known to those skilled in the art. In an alternate embodiment, the DDV 18 is located at or near the surface, or in any location wherein the well may be shut without having to kill the well or snub out of the well.
An alternate embodiment comprises any mechanical fluid control valve that serves the same function as the DDV 18, that is, any device that allows the well to be shut-in mechanically from within the wellbore, as opposed to using heavy kill mud to kill the well.
Set Casing Immediately Above or Just into the Targeted Pay Zone
The last casing run includes a DDV 18, discussed in more detail below. In certain circumstances, including but not limited to areas in which significant water production is anticipated, it may be preferable to use a concentric casing design created by a tie back liner 82 to the surface to create a dual annulus 90, 92. The drill pipe is then run inside the tie back liner 82. The underbalanced portion of the well is drilled with a drill string that runs inside the liner. The two annuluses are: (1) between the drill pipe and the liner 86, and (2) between the liner and the casing 84.
The liner includes ports or check valves 88 at depth that allow nitrogen to be circulated through the dual annulus system rather than through the drill pipe. This reduces corrosion to the bottom hole assembly as any oxygen contained in the injected nitrogen does not materially contact the bottom hole assembly. In a horizontal wellbore targeting a naturally fractured reservoir, circulating nitrogen through the concentric casing (as opposed to through the drill pipe) reduces the vertical loss of nitrogen to the formation via the fracture system. The switch to underbalanced drilling occurs prior to the drilling out of cement in the last casing run above the targeted horizon.
Drill and Complete with Solids-Free, Non-Wetting Phase Fluid
In one embodiment, the solids-free, non-wetting phase fluid comprises crude oil (preferably lease crude oil), pure mineral oil or low volatility and toxicity (LVT) drilling fluid. LVT is a mineral oil based drilling fluid, and is not pure mineral oil. Water is not used unless the wetting phase of the reservoir is oil, i.e. an oil wet reservoir. No cement is used in the productive zone.

Continuous Pressure Monitoring During Drilling

Nitrogen is injected into the drilling fluid 72 as it is pumped downhole to reduce the density of the drilling fluid. See FIG. 2A. The amount of nitrogen required (if any) depends upon the reservoir conditions and wellbore 60 configuration. Nitrogen lowers the hydrostatic head of the drilling fluid, thereby enabling underbalanced drilling. The nitrogen is available at all times to maintain underbalanced conditions. If the reservoir pressure at all times exceeds the pressure exerted by the column of solids-free, non-wetting phase drilling fluid, the injection of nitrogen may not be required. In other embodiments, other methods of injection are used, such as using a parasite tube run on the outside of the casing.

Downhole Deployment Valve

18

The DDV 18 (or any other form a mechanical fluid control or shut-in valve) is cemented in the last casing run above the target zone (in the vertical section if the well is a horizontal well). If using the concentric casing well design 80, the DDV 18 is put into the inner liner that is tied back to the surface, which is not cemented into place. The DDV 18 eliminates the need to “kill” the well.
A DDV 18 generally allows an upper section of a wellbore to be isolated from a tower section. DDV 18 technologies and operations are described in the following documents, each of which are incorporated by reference in their entirety: U.S. Pat. No. 7,690,432 to Noske et al. issued Apr. 6, 2010; U.S. Pat. No. 7,475,732 to Hosie et al.; U.S. Pat. No. 7,451,809 to Noske et al., issued Nov. 18, 2008; U.S. Pat. No. 7,350,590 to Hosie et al., issued Apr. 1, 2008; and U.S. Pat. No. 7,178,600 to Luke et al. issued Feb. 20, 2007.

Rotating Head Blowout Preventer (BOP), Rotating Control Head or Device (RCH or RCD) 14

Rotating Head Blowout Preventer 16 (BOP) technologies and operations are described in the following documents, each of which are incorporated by reference in their entirety: U.S. Pat. No. 8,353,337 to Bailey et al. issued Jan. 15, 2013; U.S. Pat. No. 8,113,291 to Bailey et al. issued Jan. 13, 2009; U.S. Pat. No. 7,934,545 to Bailey et al., issued May 3, 2011; U.S. Pat. No. 7,836,946 to Bailey et al.; U.S. Pat. No. 7,380,590 to Hughes et al. issued Jun. 3, 2008; U.S. Pat. No. 7,258,171 to Bourgoyne et al. issued Aug. 21, 2007; U.S. Pat. No. 7,159,669 to Bourgoyne et al. issued Jan. 9, 2007; U.S. Pat. No. 7,040,394 to Bailey et al. issued May 9, 2006; and U.S. Pat. No. 6,470,975 to Bourgoyne et al. issued Oct. 29, 2002.

4-Phase Separator 22, Real Time Data Acquisition and Flare System

A 4-Phase Separator 22 (water, oil, gas, solids i.e. drill cuttings), Real Time Data Acquisition and Flare System enable drilling ahead safely while producing. In one embodiment, these components enable a production of up to 100 MMCFPD+40,000 bbls fluid per day. A 4-phase separator 22 is described in U.S. Pat. No. 7,654,319 to Chitty et al. issued Feb. 2, 2010, which is incorporated by reference in its entirety. As appreciated by one skilled in the art, any capacity of 4-phase separation could be used based on the wellbore flow characteristics.
The 4-phase separator 22 in one example comprises at least a pressure tank, a flow line, a check valve, a flare stack 26, an electrical generator, a glycol heater, an injection pump and a rotating blowout preventer 16, as well as other safety devices such as level and pressure controls.

Tankage Available at the Surface to Handle High Rates of Fluid Production During Drilling

Frac tanks are cascaded together to contain produced fluid 36.

Well Completion

In one embodiment, the well is a barefoot completion, i.e. no casing or liner is set across the reservoir formation, thereby allowing produced hydrocarbon fluids to flow directly into the wellbore. In another embodiment, the well is completed using any technique known to those skilled in the art, to include a slotted liner, a pre-holed liner, a pre-cut liner and a pre-drilled liner.
Although the disclosed invention has been discussed as part of an effort to extract oil and/or gas, it could be used to mine any kind of hydrocarbon. Although the disclosed invention discussed using N₂gas, any gas known to a person skilled in the art could be used. As will be appreciated, it would be possible to provide for some features of the inventions without providing others.

Underbalanced Drilling Operations

Several aspects of underbalanced drilling operations as used in the method and system of the disclosure differ from conventional (i.e. overbalanced) drilling. The following specific UBD operations are described in detail: a) well control; b) making a connection; c) tripping in and out of the hole using a DDV; d) rate of penetration; e) stuck pipe and loss of circulation; and f) mud logging and open hole well logging.

a) Well Control (Kick and Blowouts)

Operations regarding well control comprise: allowing the well to flow (“influx”) into wellbore and to surface; safely controlling the pressure and flow using special UBD equipment (RCD, UBD choke and 4-phase separator; and modeling and monitoring circulating ECD downhole and keeping pressures below reservoir pressure at all times. Furthermore, operations involving well control should not comprise: closing pipe rams or annular preventer; evacuating personnel from location when gas is flaring (normal operation); “killing” the well using higher mud weight drill fluid; and reverting to well control by circulating through rig choke manifold until flow stops and well is “dead.”

b) Making a Connection

Operations involving making a connection comprise: bypassing nitrogen injection into well through standpipe & divert gas to reserve pit; continue pumping drilling fluid to displace nitrogen below top drill float (“check valve”) in drill pipe; stop rig pumps and make connection as usual; resume rig pumps and turn nitrogen back to standpipe.
What not to do: Do not “slug” drill pipe with a heavy barite pill to prevent wet connections (no solids in system); never break pipe for a connection until nitrogen pressure has been displaced below top float.

c) Tripping in and Out of the Hole Using a DDV

What to do: After trip, start stripping back into the well conventionally without pressure (live well is shut-in beneath DDV flapper); when lower marker sub is noted, bit is just above DDV; equalize pressure across the DDV; open the DDV; slowly strip BHA through DDV until upper marker sub is noted (well “live”); circulate out potential gas bubble trapped under DDV; finish stripping to TD under pressure (“live” well) using RCD; start stripping out of well under pressure using RCD to seal against drill pipe; look for upper marker sub to indicate position of BHA just below DDV depth; slowly strip BHA through DDV until lower marker sub is pulled, showing bit is above DDV; close DDV and bleed off pressure on annulus, then trip out of hole conventionally.
What not to do: Do not forget that DDV flapper is blocking casing ID; do not trip too fast because surge pressure can open DDV prematurely & allow leakage; do not run bit into flapper before opening DDV (will damage tool); do not forget to equalize pressures across DDV before trying to open DDV (will damage tool); do not trip BHA too fast through DDV (can damage tool); do not forget to circulate out gas bubble that was trapped beneath DDV while flapper was closed; do not forget that well is “live” with pressure at surface; do not trip BHA through DDV without slowing tripping speed (can damage DDV); do not keep pulling pipe without closing DDV after bit is above DDV (avoid “pipe light” condition).

d) Rate of Penetration (ROP)

What to do: UBD causes ROP to double or triple vs. overbalanced drilling therefore control drill (hold back) penetration rate to avoid excessive ROP; look for unusual increases in ROP which is a positive indication of increased fractures.
What not to do: Do not drill as fast as bit will drill as it will result in excessive quantity of cuttings returning to surface and higher than desired effective fluid weight that can cause overbalanced pressures.

e) Stuck Pipe and Loss of Circulation

What to do: Stuck pipe and/or losses of circulation mean the pressures being exerted on the reservoir are too high (i.e., the well is no longer underbalanced), stop drilling until normal conditions return; minimize surface back-pressure at choke or separator; adjust drilling fluid and/or nitrogen pumping rates to re-establish UBD conditions at lower ECD pressures; pipe will free itself when differential pressure is removed, then resume drilling.
What not to do: Do not revert to conventional free point and back-off measures to free drill pipe; do not spot pipe ease pill to loosen stuck pipe or pump LCM pill to stop losses (will cause solids plugging); do not need costly fishing jobs; do not keep pumping away drilling fluid if losses are noted . . . will only result in costly drilling fluid losses and possible damage to reservoir.

f) Mud Logging and Open Hole Well Logging

What to do: Mud logging requires different techniques: Cuttings cannot be collected coming off shale shakers; must be collected at UBD 4-phase separator under pressure (usually very fine samples); gas monitoring at separator or off gas flare line, not at possum belly (gas will contain nitrogen). Usually do not open hole log UBD wells, but can if necessary under pressure.
What not to do: Do not allow mud loggers to operate sample catchers at 4-phase separator; let service company technicians gather samples due to pressure on vessel; do not forget that some formations may contain poisonous hydrogen sulfide gas; take adequate safety precautions.

Example Drilling Program

An example of a drilling program using the disclosed method and system is as follows:

- 1. Stake location.
- 2. Obtain necessary regulatory permits.
- 3. Build all weather road and location for drilling rig.
- 4. Drill water well for rig use or provide alternate water source.
- 5. Set 16″ conductor at ±40′. Install 8′ OD×5′ deep cellar (corrugated metal), Drill mousehole and rathole.
- 6. Move in and rig up drilling rig.
- 7. Notify appropriate regulatory entity (e.g. in Texas, the RRC division) of intent to spud 24 hrs prior to spudding in.
- 8. Build spud mud in working tanks.
- 9. Drill 12¼″ surface hole to 1000′ or depth required by appropriate regulatory entity. Circulate hole clean and make clean-up trip to the surface. Measure out of hole. Drill to 1000′. Run one pump until the bottom hole assembly is below the conductor. Take wireline surveys every 500′.
- 10. Circulate and condition mud.
- 11. Pull out of the hole to run 9⅝″ casing.
- 12. Run float shoe (down jet), 1 joint of 9⅝″ casing, float collar and 9⅝″ casing as follows:


Interval	Length	Wt.	Grade	Coupling

0′-1000′	1000′	36#/ft.	J-55	STC

- - Clean and drift casing prior to running. Thread lock from top of float shoe to top of float collar. Install centralizer 5′ above shoe, 5′ below the float collar, on collar of 2nd, 3rd, 4th and 5th joints and then every fourth collar to the surface (17 centralizers). Have standby tongs on location.
- 13. Circulate well clean with a least 1 casing volume or bottoms up, whichever is greater.
- 14. Rig up Cementers. Pump 50 barrels of fresh water followed by cement as per cement proposal.
  - Note:
  - a. Notify the appropriate regulatory entity, as required, prior to spud and 24 hours prior to setting all casing strings.
  - b. If cement s not circulated to surface, obtain approval from the appropriate regulatory entity, prior to topping out.
- 15. Wait on cement for 6 hours. Cut off conductor and 9⅝″ casing. Weld on 9⅝″ SOW×11″ 5000 psi bradenhead. Allow weld to cool and test weld to 1000 psi (collapse rating on 9⅝″ casing is 2020 psi).
- 16. Nipple up 11″ 5000 psi (double rani) blowout preventers, 11″ 5000 psi annular preventer and 5000 psi choke manifold.

It is noted that: Blowout preventers to have 5″ pipe rams on bottom and blind rams on top; Kelly to have an upper and lower Kelly cock valve (with handle available); have on the floor at all times, safety valves and inside blowout preventers (with subs) to fit all drill string connections in use; the blowout preventers will be retested: (1) whenever any seal subject to test pressure is broken (2) at 14-day intervals; the annular preventer will be functionally operated at least weekly; pipe and blind rams will be activated during each trip; a blowout preventer pit level drill shall be conducted weekly for each drilling crew; all of the blowout preventer test and drills shall be recorded in the daily drilling report.

- 17. Test all blowout related equipment with test plug to 5000 psi and 250 psi except the annular preventer, which should be tested to 2500 psi and 250 psi. All tests are to be recorded on a pressure-recording chart and emailed to the office immediately after successful completion of the tests. Install wear ring (drain BOP stack, prior to installing wear ring).
- 18. Run 8¾″ PDC bit and drill string.
- 19. Tag cement and test casing to 1500 psi (rated at 3520 psi). Drill 10′ of new formation and test casing seat to 11 ppg EMW. Report the results to the office immediately after completion of the test.
- 20. Drill ahead. Run mud as per mud program.
- 21. Drill an 8¾″ hole to 150′ above KOP.
- 22. Trip out to pick up directional tools and RIH. Take surveys every 250′ while running into the hole.
- 23. Drill curve at 10-12°/100′ BUR. Drill to +/−70°, or until returns show 100% of targeted formation.
- 24. The following equipment should be operational below surface casing: power choke, PVT, flow sensor and drilling monitor. Mud logger should be rigged up and logging at 3000′.
- 25. Make short trips as hole conditions dictate.
- 26. Short trip at intermediate total depth. Circulate and condition mud. Measure out of the hole.
- 27. Run logs per the logging program: for example: GR/High Resolution Induction/Spectral Density/Dual Spaced Neutron (Triple Combo).
- 28. Prior to running the 7″ casing, clean threads and drift.
- 29. After logging, go in the hole and condition mud. POOH LD 5″ drill pipe.
- 30. Run 7″, 23#, L-80, LTC casing. Run casing slowly to reduce the risk of lost returns. Have standby tongs on location.
- 31. Run float shoe (down jet), 1 joint of 7 casing, float collar and 7″, 23#, L-80, LTC casing to surface. Thread lock all connections from top of float shoe to top of float collar. Run Solid. Body centralizer 5′ above float shoe, 5′ below float collar, below the collar of each joint to 5700′ and then bowsprings every other joint to 4600′. Run DDV @6,500′ from surface. Detailed DDV running procedure may be provided by the DDV manufacture, i.e. Weatherford.
- 32. Run Cement DV Tool @3,000′ or as required by appropriate regulatory entity.
- 33. Circulate well clean with at least 1 casing volume.
- 34. Rig up Cementers. Pump Cement as per cementing proposal.
- 35. Displace cement and bump plug with 500 psi above final pump pressure. Bleed pressure to zero to insure the floats are holding. The casing should be reciprocated 20′ as long as possible during circulation and cementing operations. Cement volume to be calculated from caliper log, using 10% excess.
- 36. Cycle the DDV several times as per Weatherford procedures to ensure there is no residual cement in the valve or sliding sleeve.
- 37. Nipple down blowout preventers. Set slips with casing in full tension.
- 38. Cut off 7″ casing and nipple up 11″ 5000 psi×11″ 5000 psi casing hanger. Test pack off to 2500 psi (collapse rating of 7″ casing is 3830 psi).
- 39. Nipple up 11″, 5000 psi (double) blowout preventers, 11″ 5000 psi annular preventer and 5000 psi choke manifold.
- 40. Rig up UBD 4 phase separator, N2 package, and rotating head preventer (e.g. Series 7100)
- 41. Test all blowout preventer related equipment to 5000 psi and 250 psi with the exception of the annular preventer, which should be tested to 2500 psi and 250 psi. All tests are to be recorded on a circular chart and emailed to the office immediately after successful completion of the test. Install wear ring (drain BOP stack).

It is noted that: Blowout preventers to have 3⅕″ pipe rams on bottom and blind rams on top; Kelly to have an upper and lower Kelly cock valve (with handle available); have on the floor at all times, safety valves and inside blowout preventers (with subs) to fit all drill string connections in use; the blowout preventers will be retested: (1) whenever any seal subject to test pressure is broken (2) at 14 day intervals; the annular preventer will be functionally operated at least weekly; pipe and blind rams will be activated during each trip; a blowout preventer pit level drill shall be conducted weekly for each drilling crew; all of the blowout preventer test and drills shall be recorded in the daily drilling report.

- 42. Pick up 3½″ DP. Run 6⅛″ PDC bit and BHA.
- 43. RIH with drill string to 9 joints above DDV. Install Marker Sub. Continue into the hole until the BRA is 9 joints below the DDV and install another marker sub. This provides a reference for the positioning of the DDV during trips.
- 44. Tag cement and test casing to 2500 psi (burst rating at 6340 psi).
- 45. Clean mud tanks Fill with 500 BBLS lease crude. Displace water base mud with 60 barrels of water followed by lease crude. Displace at high pump rate and rotate the drill string during the displacement.

Note: To minimize oil losses during trip and on connections, use a Kelly check valve, pipe rack drain pans and pipe wiper.

- 46. Drill the float collar, cement float shoe and 10′ of new formation. Circulate bottoms up and condition mud.
- 47. An Underbalanced bottom hole condition will be maintained at all times during the drilling of the lateral. This will be monitored using a Pressure While Drilling (PWD) sub in the MWD. If the drilling fluid column is too heavy, the N2 will be used to aerate the fluid.
- 48. Drill a 6⅛″ hole to planned TD of 11,000′.
- 49. Monitor and report flow rates in and out, and pressure on the 4 phase separator.
- 50. If a trip is needed, circulate 2× bottoms up prior to preparing to trip out. Strip out of the hole using the rotating head to the 1st marker sub. Pull the BHA to 1 joint above the DDV. Shut in the well at surface. Close the DDV and pump 10 bbls of clean fluid across the closed flapper. This will help to clear any debris from the flapper that would hinder the metal-to-metal seal. Bleed pressure off at surface and monitor flow. If hole is static, continue out of the hole and change the necessary components of the BHA. Trip back in the hole using the same marker sub method used on the first trip in.
- 51. Trip back in the hole using the same marker sub method used on the first trip in. When the BHA is above the DDV, close in the well and cycle the DDV open. If there is pressure below the valve, it will need to be equalized before the valve will completely open. Continue stripping into the hole to continue drilling.
- 52. After reaching total depth, Circulate a minimum of 2× bottoms up. Shut pumps down and measure natural flow rate from well. Measure out of the hole.
- 53. Close DDV in same method as stated in #48. Continue out of the hole.
- 54. TIH and set storm packer@50′.
- 55. Nipple down blowout preventers. Nipple up capping flange.
- 56. Clean mud tanks and release rig. Report volume of produced oil returned to Purchaser

Claims

What is claimed is:

1. An advanced method of drilling a hydrocarbon wellbore, comprising:

using at least one of an overbalanced and an underbalanced fluid column to drill a wellbore to an upper portion of a hydrocarbon reservoir;

installing and cementing a casing string inside the wellbore to the upper portion of the hydrocarbon reservoir;

providing a mechanical fluid control valve in the casing string segment above a predetermined target producing zone;

using an underbalanced fluid column, drilling and completing the targeted producing zone using a solids-free and non-wetting phase drilling fluid maintained below the pressure of the hydrocarbon reservoir;

injecting nitrogen into the drilling fluid as needed to reduce the hydrostatic head of the drilling fluid and enable the underbalanced drilling to be maintained; and

circulating the drilling fluid and nitrogen, and any produced fluids and rock cuttings, through a series of surface process equipment designed to separate oil, gas, water and rock cuttings under pressure.

2. The method of claim 1, wherein the solids-free and non-wetting phase fluid comprises a crude oil, a pure mineral oil and an LVT drilling fluid for a water wet reservoir.

3. The method of claim 1, wherein the nitrogen is injected into the hydrocarbon wellbore by at least one of the drill string and through an annulus formed with a casing string.

4. The method of claim 3, wherein the solids-free and non-wetting phase fluid comprises water for an oil wet reservoir.

5. The method of claim 1, wherein a rotating pressure control device is positioned at a surface location in communication with the drill string, and the mechanical fluid control valve is positioned at a subsurface location above the producing formation.

6. The method of claim 1, wherein nitrogen is circulated downhole between two strings of casing.

7. The method of claim 1, wherein no drilling or completion fluid which is overbalanced with respect to the hydrocarbon formation pressure comes in contact with the hydrocarbon formation.

8. The method of claim 1, wherein the underbalanced fluid column is maintained throughout the entire drilling and completion operations.

9. The method of claim 5, wherein the downhole deployment valve is interconnected to the lowermost portion of casing string.

10. The method of claim 9, wherein formation cuttings, nitrogen and any wellbore fluid is produced under pressure in the annulus between the drill string and production casing.

11. A method of drilling for recovery of hydrocarbons comprising oil and natural gas from a hydrocarbon reservoir, comprising:

using an overbalanced or underbalanced fluid column to drill a hydrocarbon wellbore to an upper portion of a hydrocarbon reservoir;

installing and cementing a casing string inside the wellbore;

providing a downhole deployment valve in a lowermost casing string segment and above a projected hydrocarbon producing zone;

providing nitrogen as needed in the drilling fluid to reduce the hydrostatic head of the drilling fluid;

circulating the nitrogen through an annulus formed by a second casing;

circulating the drilling fluid and nitrogen, and any produced fluids and rock cuttings, through surface process equipment designed to separate oil, gas, water and rock cuttings under pressure.

12. The method of claim 11, wherein the wellbore is configured such that underbalanced conditions are maintained throughout the entire drilling and completion operations.

13. A system for drilling for recovery of hydrocarbons comprising oil and natural gas from a hydrocarbon reservoir, comprising:

a wellbore extending at least to an upper portion of a hydrocarbon reservoir;

a casing string disposed inside the wellbore;

a mechanical fluid control valve disposed in the casing string segment and above a target producing zone;

utilizing a solids-free and non-wetting phase drilling fluid maintained below the pressure of the hydrocarbon reservoir; and

wherein the drilling fluid is maintained below the pressure of the hydrocarbon reservoir to enable underbalanced drilling;

wherein nitrogen is injected into the drilling fluid as needed to reduce the hydrostatic head of the drilling fluid and enable the underbalanced drilling to be maintained; and

wherein nitrogen, hydrocarbons, and drilling fluid are produced and treated under pressure with surface process equipment.

14. The system of claim 13, wherein the solids-free and non-wetting phase fluid comprises: (a) crude oil, pure mineral oil and LVT drilling fluid for water wet and partially water wet reservoirs, and (b) water for oil wet reservoirs.

15. The system of claim 14, wherein the nitrogen is injected into the wellbore through at least one of a drill string and an annulus in the casing.

16. The system of claim 15, wherein the rotating pressure control device is positioned at a surface location, and the mechanical fluid control valve is deployed subsurface above the hydrocarbon formation.

17. The system of claim 16, wherein the downhole deployment valve is interconnected to the lowermost joint of casing.

18. The system of claim 13, wherein the solids-free and non-wetting phase fluid comprises a crude oil, a pure mineral oil and an LVT drilling fluid for a water wet or partially water wet reservoir.

19. The system of claim 13, wherein no drilling or completion fluid which is overbalanced with respect to the hydrocarbon formation pressure comes in contact with the hydrocarbon formation.

20. The system of claim 13, wherein produced hydrocarbons, drilling fluid, water, nitrogen, wellbore cuttings and gas are treated in a pressurized four phase separator at a surface location.