OPEN HOLE GAS WELL CLOSED CYCLE DRILLING AND PRODUCTION SYSTEM WITHOUT GAS VENTING AND FLARING OR RESERVOIR DAMAGES

Abstract

An open-hole drilling method and process is embodied in creation of a closed cycle and system for extracting gas from shale and other impermeable and natural vertical fracture dominated reservoirs. The closed cycle system enables gas from reservoir to be used as a drilling fluid, with any excess gas produced as the wellbore is extended, to be sold in real time through a gas pipeline. Since only natural gas exists throughout the closed system, no risk exists for downhole explosions, and no wellbore damages occur from foreign fluids, such as mud, cement, and water. Limits of wellbore length due to gas produced while drilling, and risks during gas flaring are eliminated. All products produced from wellbore are captured so no venting of any liquids, gases, or solids. All hydraulic fracturing issues are avoided. Gas flow rate measurements while drilling enables technical, financial, reserve estimate models development in real time.

Claims

1. A closed loop system for natural gas extraction, the system comprising: an external gas pipeline; a master meter valve, wherein the master meter valve supplies natural gas to the system, the supplied natural gas is obtained from the external gas pipeline; one or more of a first compressor, wherein the natural gas supplied from the master meter valve flows to the first compressor so to increase gas pressure; a surge and storage tank reservoir, wherein once a desired pressure is reached, the pressurized natural gas flows from the first compressor and system to the surge and storage tank reservoir; one or more of a second natural gas compressor which receive natural gas when needed from the surge and storage reservoir so to deliver gas at rates and pressures required for drilling processes; a well site, including a vertical well and a drill rig; the drill rig further comprising a drill bit which is actuated by the pressurized natural gas fluid received from within the system or by a rotating drill pipe; a particle separator for separating large particle cuttings from gas circulating fluid received from the well site; a filter subsystem for removing smaller particles the gas circulating fluid received after being processed by the particle separator; a natural gas stream conditioner for preparing the natural gas suitable to enter the external gas pipeline; wherein once the natural gas is processed by the filter subsystem, the processed natural gas is dispersed between the natural gas stream conditioner and reentry into the system at the storage and surge tank reservoir as needed.

2. The system as claimed in claim 1, the system further comprising: wherein the system is closed and sealed so that no substances other than natural gas are entered, exited or circulated within.

3. The system as claimed in claim 1, the system further comprising: wherein the system is closed and sealed so that no substances are vented into the atmosphere.

4. The system as claimed in claim 1, the system further comprising: wherein a primer quantity of natural gas is obtained from the external gas pipeline.

5. The system as claimed in claim 4, the system further comprising: wherein after being primed, the pressurized natural gas fluid is obtained from the same gas reservoir borehole as the one being drilled.

6. The system as claimed in claim 1, the system further comprising: wherein the system does not use any of drilling mud, cementing pipe through the pay zone, perforating pipe and hydraulic fracturing.

7. A method using a closed loop system for natural gas extraction, the method comprising: obtaining natural gas from an external gas pipeline; supplying natural gas to the system from a master meter valve; receive the flow of natural gas from the master meter valve at one or more of a first compressors; increase gas pressure using the one or more of a first compressors to a desired pressure within the system; wherein the pressurized natural gas flows from the first compressor and system to a surge and storage tank reservoir; when needed, receive natural gas at one or more of a second natural gas compressors from the surge and storage reservoir so to deliver gas at rates and pressures required for drilling processes; actuating a drill bit of a drill rig using a vertical well at a well site using the pressurized natural gas fluid received from within the system or actuating a drill bit by a rotating string of drill pipe; separating large particle cuttings from gas circulating fluid received from the well site at a particle separator; removing smaller particles from the gas circulating fluid received after being processed by the particle separator at a filter subsystem; preparing the natural gas to enter the external gas pipeline at a natural gas stream conditioner; wherein once the natural gas is processed by the filter subsystem, the processed natural gas is dispersed between the natural gas stream conditioner and reentry into the system at the storage and surge tank reservoir as needed.

8. The method as claimed in claim 7, the method further comprising; a process of completion that does not involve the injection of any substance into the reservoir rock.

9. The method as claimed in claim 7, the method further comprising: wherein the natural gas produced and processed from the well site being drilled is recycled back into the system as drilling fluid through the system.

10. The method as claimed in claim 9, the method further comprising: the obtained natural gas from the external pipeline is used to prime the system, once the system is primed, the system then switches to used recycled natural gas.

11. The method as claimed in claim 7, the method further comprising: a drilling process; wherein the drilling process comprises: reaming a borehole while drilling a directionally controlled pilot hole by forward and reverse cycles, wherein the cycles are determined manually, periodically, or based upon measured variables values to achieve at least one of a plurality of objectives, the objectives comprising: a) cleaning the borehole of larger particles and crushing larger chunks suitable for gas stream entrainment and circulation to above ground facilities, b) enlarging the diameter of a borehole, and c) removing the damaged surface due to the front end drill bit.

12. The system as claimed in claim 1, the system further comprising: wherein the excess natural gas produced beyond that required for drilling is cycled back through the system and out to the master meter valve, wherein the master meter valve supplies natural gas back to a master sales meter and the external gas sales pipeline.

13. The method as claimed in claim 7, the method further comprising: wherein the excess natural gas produced beyond that required for drilling is cycled back through the system and out to the master meter valve, wherein the master meter valve supplies natural gas back to a master sales meter and the external gas sales pipeline.

14. The system as claimed in claim 1, the system further comprising: wherein the system is hypoxia or anaerobic oxygen-free such that no internal system explosions can occur.

15. The system as claimed In claim 1, the system further comprising: wherein after the conventionally drilled vertical well is drilled and completed, the system does not use any water on the drill pad, so to eliminate the risks of spills, prevent environmental violations, and prevent environmental damage to any adjacent water, ponds, creeks, streams, or rivers.

16. The method as claimed in claim 7, the method further comprising: wherein after the conventionally drilled vertical well is drilled and completed, water is not used on the drill pad, so as to eliminate the risks of spills, prevent environmental violations, and prevent environmental damage to any adjacent water, ponds, creeks, streams, or rivers.

17. The method as claimed in claim 7, the method further comprising: wherein a closed cycle extraction process is independent of mechanical properties of reservoir rock or its states of in situ stress field.

18. The system as claimed in claim 1, the system further comprising: real time gas flow rate data from a master flow meter, which are used in real time to create computer models including reserve estimates.

19. The method as claimed in claim 7, the method further comprising: calculating reserve estimates, by using real time gas flow rate data in conjunction with the real time created computer models.

20. The system as claimed in claim 1, the system further comprising: wherein a length of drilled borehole that can be drilled is not limited as a result of an amount of gas liberated into a wellbore while drilling, when using the pressurized natural gas fluid as a drilling fluid, because quantities of the amount of gas liberated into a wellbore while drilling is unsafe and too great of a quantity to be flared.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0010] The aforementioned and other aspects, features and advantages can be more readily understood from the following detailed description with reference to the accompanying drawings wherein:

[0011] FIG. 1 shows the major components and functionality of this closed cycle system are illustrated.

DETAILED DESCRIPTION OF THE INVENTION

[0012] Basic Closed Cycle System Functionality

[0013] The closed cycle system illustrated in FIG. 1 functions in the following simplified manner. Natural gas is purchased by opening master valve A1 which is connected to a gas sales and purchasing master meter A2, which is then connected to a gas purchasing and sales pipeline A3, whereupon gas, flows through pipeline (A1 to C1) and compressed by C1 to scavenge, purge, pressurize and pressure test the entire system piping network, starting with B and cycling through C2, E, F, G, H and pipelines (H to A), and (G to B). Following startup safety and operational protocols, gas circulation begins, the drill bit encounters the pay zone with prescribed bit pressure, and drilling begins and continues to final length. All pipes and connections in this closed cycle are conventional high pressure pipes rated above 10,000 psi and typically connected and sealed with conventional hammer unions and not disconnected during entire process. During the lateral drilling process additional pipe joints are added using a hydraulic type fitting with O-ring type seals that prevent pressure loss during added joints makeup and drilling. When gas produced by the well while drilling exceeds that required for drilling, the excess gas, instead of being flared conventionally, is cycled back through the F, G and H system shown in FIG. 1, and then passes back through a master valve A1 and gas master flow meter A2 into a gas sales pipeline A3.

[0014] This basic closed cycle system, one-phase process, and simultaneous combined drilling and well-completion methodology incorporate subsystems that create versatility, features, and results also unique to the industry. The methodology is described first.

[0015] Methodology

[0016] For many reasons described above under Background that are distinctly different from this herein methodology, it is hereby made a part of this Specification. It is of paramount importance to use in the drilling process through a friable and sensitive rock formation, such as the Marcellus and other Shales, a drilling fluid that does not damage in any way the ability for gas to flow from the rock, it's matrix or natural fracture network system, into a penetrating wellbore. Thus, the minimum restriction of an uncased borehole without steel pipe cemented in, or any sleeves is a fundamental condition and objective of this methodology. This is known as an open-hole well completion method. The various unique embodiments of this methodology include:

[0017] 1. The natural gas drilling fluid used is in a gaseous thermodynamic state, without presence of any oxygen or water molecules. Since no air, drilling mud, cement, or any other oxygen containing compound is introduced into the wellbore during or after drilling, this method uniquely constitutes both an oxygen-free drilling, and well-completion method and process. The hypoxia or anaerobic down-hole environment thusly created entirely eliminates the risk and preventative measures normally taken for downhole explosions.

[0018] 2. The drilling fluid is a hydrocarbon of the same general chemical composition as the native fluid stored in the rock formation, known as natural gas, which may have innumerable hydrocarbons, all combustible or explosive when combined with oxygen under various conditions. However, this fluid being reintroduced to the rock faces does not in any manner damage the ability of the rock to allow gas to flow into the wellbore.

[0019] This is in stark contrast to use of water with viscosity and surface tension plugging small fractures and prohibiting gas tlow.

[0020] 3. This unique method utilizes the native fluid of natural gas from the gas reservoir as the drilling fluid, starting from the beginning of the drilling process and rapidly increasing to 100% after the priming natural gas of essentially the same composition obtained from the gas sales pipeline is displaced and returned to the gas sales pipeline from which it was obtained. In essence, the startup priming natural gas from the sales pipeline is just borrowed for a very short period and quickly returned to the sales pipeline from which it was obtained. This method has never been used, and is a dramatic and unprecedented achievement.

[0021] 4. The rapidity with which the borrowed priming natural gas is displaced and replaced as the drilling fluid occurs in dramatic steps, typically every 3 to 10 of borehole drilled, as each natural vertical fracture is intersected. This is a result of the Marcellus and other Shales having nano order of matrix permeability, while the vertical fractures, the main conduits to the wellbore, have permeabilities of 3 to 6 or higher orders of ten magnitude of permeability. This rapid entry of gas from the fractured reservoir into the wellbore largely constitutes excess gas that would normally be vented to the atmosphere or flared in exiting the above ground piping annulus. In this unique, unprecedented method, this gas is returned to the sales pipeline on a continuous, steady basis.

[0022] 5. Ordinarily, gas sales pipelines laid to the pad and connected in any way to any pipe connected to the drilled well are the last step in the drilling and completioiu process for a wide variety of reasons. However, in this method, laying a gas sales pipeline up to the pad, and connecting it to a drill pipe is one of the initial steps in this method and process.

[0023] 6. This selling-gas-while-drilling method also enables other processes to be introduced, including:

[0024] a) The economic success of the well is measured continuously, every foot of wellbore drilled and every natural fracture intersected by the wellbore, because the gas is going through a sales gas meter, which can be remotely monitored either in an onsite van monitoring and control station, or over the internet. This means that economic algorithms can be used in real time every step of the way to calculate the value of reserves being recovered using existing reservoir models, which may also provide bases of when to stop drilling based upon any economic or risk models.

[0025] 7. In fact, this methodology enables and allows for the first time, the real-time research task of creating new reservoir models for naturally fissured and fractured reservoirs and calibrating them based not only upon real gas flow quantities recovered, but all of the precise geological, natural gas and petroleum engineering conditions and data existing at the specific site to be input to the onsite computer system apriori to drilling, such that immediately after the well is drilled, RESERVES ESTIMATES for the ultimate production for the life of the well can be made available to investors and the users of technical data and models. This is again a monumental capability and achievement for the industry. Even just the basic calculations of reserves estimates are currently conventionally made days and months after the well is drilled. The real-time creation and calibration of such a model for fractured reservoirs over an extended period of time and by large funded research programs is a major objective of the industry today.

[0026] 8. The fact that gas flow rates into the open wellbore are measured while drilling is a valuable research tool. This allows gas entry to be correlated with major natural fracture systems, and map them, their frequency, and major role assessment in reserves recovery models, all useful in creating engineering design plans for drilling and advancing technology in sensitive reservoirs. This enables creation of all types of models in real time ranging from process design to financial analysis to futuristic reserve recovery efficiency and total reserves to be recovered.

[0027] 9. This selling-gas-while-drilling method also reduces the current methodology urgency and main objective to get the lateral borehole drilled ASAP, because the Rig cost of nominally $15,000/day is largely offset, since the excess gas being recovered while drilling is being sold. That is, drilling penetration rate can be as slow as needed without major financial penalty.

[0028] 10. This selling-gas-while-drilling method also is in stark contrast to the current methodology limitation of having to stop drilling and remove the drilling tools from the wellbore under risky conditions, when drilling on air or other gases or liquids, and the volumes of natural gas being produced greatly increase risk of down-hole explosions, or can no longer be safely flared or handled by the equipment and well-control risks are too high. In this method, many such issues are averted, and the length of borehole that can be drilled is greatly increased.

[0029] 11. This selling-gas-while-drilling methodology enables the currently feasible length of drilled laterals to be extended by 1,000's of feet, and only limited when a variety of other parameters or variables become the limiting factors. That is the extra gas entering following each natural vertical fracture intersected does not become an untenable or unmanageable problem. On the contrary it is immediately an asset.

[0030] 12. This methodology also embodies a start-stop-forward-and reverse-drill cycle (FRDC). The friable, fissured shales are highly likely to shear or drop slivers or blocks of shale into the drilled wellbore. These droppings are usually referred to as wellbore stability issues, which can cause high torque on the drill collars or drill bit assembly and the entire drill pipe to get stuck and potential loss of the well. Thus, this FRDC can be enabled and utilized at any point or time deemed desirable in the entire wellbore drilling process. A conventional reaming type tool is assembled behind the main drill bit in such manner that when forward drilling or reverse retrieving the drill pipe while still rotating, the reaming tool will crush the droppings into fine particles that can be circulated to above ground facilities along with all other cuttings. Several variables, such as drill pipe torque, reduction in steady flow of cuttings, downhole pressures, volumes of gas being produced, etc. can be used for decision making to determine two characteristics of the FRDC process, namely a) the stroke amplitude of the FRDC, and the frequency of utilization of the FRDC. Once again, while rig cost is a decision making parameter, these other downhole parameters also become strong variables in the decision making of the drilling engineer. This FRDC can also be considered a safety factor to be used frequently to avert risk of getting tools stuck in the wellbore.

[0031] 13. This FRDC also is a process that functions without needing to know the unknown shale mechanical properties of moduli, such as the classical Young's Modulus, shear and bulk moduli, defined and used for conventional elastic, isotropic, and homogeneous material properties. When the in situ stress field of 1,000's psi is removed in creating the open borehole, the shale expands in all three dimensions in response to the three different magnitudes of in situ stresses along the borehole. This expansion in 3-D has various implications, one of them being the radial expansion toward the centerline of the borehole axis. This radial expansion will result in a reduction of wellbore diameter in real time while drilling, which will likely also contribute in various ways to the resulting named wellbore instability issue. This FRDC process allows this to happen in a less catastrophic and controlled or managed manner. That is, in contrast just to taking the bit to the reservoir rock and drilling the borehole forcibly and aggressively at maximum speed, this FRDC allows the reservoir rock to come to the bit in a controlled-managed manner. This method and process does not require any advance knowledge of the relative magnitudes of the horizontal-bedding plane in situ stresses or their differences, or the material mechanical properties. The FRDC method and process deals with these many possible mechanisms and above mentioned unknown material properties and behaviors of this fissured material in such a manner they are to a significant degree ameliorated by the FRDC.

[0032] 14. This FRDC is the sub-process that is enabled by the closed cycle system, process and methodology, which constitutes both a combined drilling and well-completion process, which is always a separate and distinctly different process in all oil and gas well drilling operations today. This FRDC is in stark contrast to the hydraulic fracturing completion method and process used almost exclusively today, which creates traumatic borehole damages, and actually entombs and honeycombs with cement a high percent of the resources in place, perhaps greater than 60 or 70% that can never be recovered by any economic or technically feasible process.

[0033] 15. Although one of the principal applications of this extraction process is solving problems for low permeability shales, it is actually independent of, and not a function of many of the mechanical properties of the reservoir rocks, and likewise independent of the state of in situ stresses of the reservoir. Therefore, it is applicable to any type of reservoir rock or it's in situ conditions. Current methodology today requires calculations that involve such mechanical properties as Young's modulus, compressive and shear ultimate strengths and elastic ranges, bulk modulus, fracture network characterization, in situ stresses, etc. These properties are incapable of being determined or even estimated in some cases. Since this method and-process do not utilize the properties in engineering design calculations, it is an extremely important feature of this method, system, and process. There are no completion steps, like hydraulic fracturing, staging, or fracture propping wherein such properties are used.

[0034] The Closed Cycle System

[0035] In this unprecedented single step or phase gas well drilling and production strategy and process, specially designed components allow the creation of a closed system, and closed cycle in which the same gas or gas just previously allowed to flow into the borehole is cycled back down the drill pipe after extracting all significant particles to continue drilling in a continuous, cyclic manner. Since this is a continuous process until the planned end of the horizontal lateral borehole is reached, it is truly a one-step or one-phase process. This achievement is believed to be truly transformational with huge potential for the oil and gas extraction industry around the world. This closed cycle system, comprised of the illustrated components, functions as a single entity in unison, such as a device or machine with single global purpose accomplishing a plethora of functions, and whcrein the two basic remaining conventional phases of drilling and well-completion are achieved simultaneously in one phase. This closed cycle system, wherein excess liberated gas beyond that required for drilling is disposed of by sending it back to a gas purchasing pipeline, enables the wellbore to be drilled to lengths dependent upon such variables as, strength of steel pipe, not quantities of gas produced from fractures that has to be flared in a wasteful and dangerous manner.

[0036] Larger Particles Separator

[0037] As the particle laden gas stream exits the tee connected to the annulus between the production string of pipe and drill pipe, it all passes through a large, high pressure vessel selected to separate the larger particles using centrifugal and gravitational forces, shapes, and geometrical configurations to separate the bulk of the particles from the turbulent gas stream. Vibrators may be strategically placed on the exterior walls of the separator to expedite particle collection at bottom of separator and mitigate side-wall sticking. The particles settle in a collector pipe at the bottom of the pressure vessel and entrance to a large ball-type valve with full throat opening and closing at 90 degree rotational intervals. This valve opens to a depressurization chamber of such size and volume to contain the particles during a pressure release period, which is cycled to dump the particles into an atmospheric pressure chamber collector for disposal. This is accomplished by a second ball valve on the bottom of the depressurization temporary storage-depressurization chamber. This emptying cycle period is computer controlled based upon transducers located on the separator.

[0038] Smallcr Particles Separator-Filter Sub-System

[0039] The characteristics of the particles suspended in the particle-gas stream at this point will vary with several variables associated with the drilling process and the fabric of the shale being drilled. A variety of commercially available separators and filters are used in a cascade manner in this system component. The fine particles are removed to whatever specifications

[0040] as may be required by various types of compressors, and as may be required by different pipeline companies to assure the excess gas stream meets gas sales pipeline quality standards. Appropriate modifications to these subsystems include the same provisions of vibration, collection, depressurization chamber with two isolation ball valves and atmospheric pressure collection vessel for particle disposal as in the larger particle separator.

[0041] Compressors

[0042] Two compressors illustrated in FIG. 1 as C1 and C2 meet the principal gas compression requirements for the closed cycle system. Since the process begins with thoroughly scavenging and purging the entire system of all existing gases, and then pressurization of the entire system for leak detection, followed by drilling initiation, the two distinct compressors are prescribed to serve these specific needs. The C1 compressor is a high-pressure low-volume-rate compressor, since time or rate are not of the same order as for C2.

[0043] That is, C1 can accept gas at whatever rate the gas sales pipeline can deliver at whatever pressure, and compress it to the desired pressure established for the surge-storage tank reservoir during whatever time is reasonably required. The requirements of C2 are similar in size and volume rate capacity to commercial compressors conventionally used for air drilling of wellbores. These rates for compressing the natural gas drilling stream are not of significant difference. There is one more compressor C3 not illustrated in FIG. 1, because it may or may not be needed as a required component to the basic closed cycle system. C3 will be designed and installed in the system on an as needed basis, which is contingent upon different drill site conditions, including the sales pipeline operating pressure. The sales pipeline rate capacity for accepting gas would obviously be capable of handling any excess volume produced during drilling or routine well production, or it would not have been laid to the drill pad in the first place. Thus, C3 specifications are, in general, lower pressure and lower flow-rate than C2, and lower pressure, but higher rate than C1.